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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2010
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                    to

Commission File No. 000-53908

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

Georgia (State or other jurisdiction of incorporation or organization)	58-1211925 (I.R.S. employer identification no.)
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices)	30084-5336 (Zip Code)
Registrant's telephone number, including area code	(770) 270-7600

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

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

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

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

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

(This page has been left blank intentionally.)

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2010

			Page No.
PART I—FINANCIAL INFORMATION
	Item 1.	Financial Statements	2
		Unaudited Condensed Balance Sheets as of September 30, 2010 and December 31, 2009	2
		Unaudited Condensed Statements of Revenues and Expenses For the Three and Nine Months ended September 30, 2010 and 2009	4
		Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit For the Nine Months ended September 30, 2010 and 2009	5
		Unaudited Condensed Statements of Cash Flows For the Nine Months ended September 30, 2010 and 2009	6
		Notes to Unaudited Condensed Financial Statements For the Three and Nine Months ended September 30, 2010 and 2009	7
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	18
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
	Item 4.	Controls and Procedures	28
PART II—OTHER INFORMATION
	Item 1.	Legal Proceedings	29
	Item 1A.	Risk Factors	29
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
	Item 3.	Defaults Upon Senior Securities	29
	Item 4.	Reserved	29
	Item 5.	Other Information	29
	Item 6.	Exhibits	30
SIGNATURES			31

1

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
September 30, 2010 and December 31, 2009

			(dollars in thousands)
		2010			2009
Assets
Electric plant:
	In service	$	6,662,637		$	6,550,938
	Less: Accumulated provision for depreciation		(3,074,288	)		(2,993,215	)
			3,588,349			3,557,723
	Nuclear fuel, at amortized cost		236,276			215,949
	Construction work in progress		1,049,600			626,824
			4,874,225			4,400,496
Investments and funds:
	Decommissioning fund		251,939			239,746
	Deposit on Rocky Mountain transactions		121,556			115,641
	Investment in associated companies		54,794			53,199
	Long-term investments		91,031			87,129
	Other, at cost		3,493			4,597
			522,813			500,312
Current assets:
	Cash and cash equivalents, at cost		432,796			579,069
	Restricted cash, at cost		6,299			22,405
	Restricted short-term investments		80,771			80,590
	Receivables		127,703			110,258
	Inventories, at average cost		185,701			209,837
	Prepayments and other current assets		13,778			9,393
			847,048			1,011,552
Deferred charges:
	Premium and loss on reacquired debt, being amortized		114,832			122,847
	Deferred amortization of capital leases		68,293			77,755
	Deferred debt expense, being amortized		53,865			57,262
	Deferred outage costs, being amortized		31,644			31,319
	Deferred tax assets		—			24,000
	Deferred asset associated with retirement obligations		27,952			31,413
	Deferred interest rate swap termination fees, being amortized		26,303			29,296
	Deferred depreciation expense, being amortized		52,988			54,056
	Other		29,421			29,926
			405,298			457,874
		$	6,649,384		$	6,370,234

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

2

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
September 30, 2010 and December 31, 2009

			(dollars in thousands)
		2010			2009
Equity and Liabilities
Capitalization:
	Patronage capital and membership fees	$	598,071		$	562,219
	Accumulated other comprehensive deficit		(168	)		(1,253	)
			597,903			560,966
	Long-term debt		4,170,484			4,178,981
	Obligation under capital leases		189,127			208,945
	Obligation under Rocky Mountain transactions		121,556			115,641
			5,079,070			5,064,533
Current liabilities:
	Long-term debt and capital leases due within one year		147,942			119,241
	Short-term borrowings		581,046			283,634
	Accounts payable		97,093			24,184
	Accrued interest		37,449			50,947
	Accrued and withheld taxes		22,085			24,864
	Member power bill prepayments, current		64,963			182,514
	Other current liabilities		17,276			28,000
			967,854			713,384
Deferred credits and other liabilities:
	Gain on sale of plant, being amortized		29,206			31,062
	Net benefit of Rocky Mountain transactions, being amortized		51,762			54,151
	Asset retirement obligations		276,769			264,635
	Accumulated retirement costs for other obligations		38,737			43,955
	Long-term contingent liability		—			24,000
	Member power bill prepayments, non-current		19,720			18,000
	Power sale agreement, being amortized		73,663			86,211
	Other		112,603			70,303
			602,460			592,317
		$	6,649,384		$	6,370,234

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

3

Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three and Nine Months Ended September 30, 2010 and 2009

				(dollars in thousands)
			Three Months						Nine Months
			2010			2009			2010			2009
Operating revenues:
	Sales to Members		$	370,453		$	308,414		$	1,000,244		$	890,646
	Sales to non-Members			796			334			1,188			974
		Total operating revenues		371,249			308,748			1,001,432			891,620
Operating expenses:
	Fuel			160,174			94,508			383,725			281,627
	Production			82,717			69,144			245,978			209,177
	Purchased power			24,721			44,349			60,346			103,545
	Depreciation and amortization			35,441			34,301			108,956			98,012
	Accretion			4,282			4,565			12,848			13,696
		Total operating expenses		307,335			246,867			811,853			706,057
Operating margin				63,914			61,881			189,579			185,563
Other income:
	Investment income			7,950			8,147			23,103			24,210
	Other			3,231			2,152			9,413			7,418
		Total other income		11,181			10,299			32,516			31,628
Interest charges:
	Interest expense			65,946			59,419			197,089			176,198
	Allowance for debt funds used during construction			(10,474	)		(3,979	)		(28,611	)		(12,523	)
	Amortization of debt discount and expense			5,775			5,378			17,765			13,698
		Net interest charges		61,247			60,818			186,243			177,373
Net margin			$	13,848		$	11,362		$	35,852		$	39,818

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

4

Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Deficit (Unaudited)
For the Nine Months Ended September 30, 2010 and 2009

			(dollars in thousands)
		Patronage Capital and Membership Fees		Accumulated Other Comprehensive (Deficit)			Total
Balance at December 31, 2008		$	535,829	$	(1,348	)	$	534,481
Components of comprehensive margin:
	Net margin		39,818		—			39,818
	Unrealized gain on available-for-sale securities		—		263			263
Total comprehensive margin								40,081
Balance at September 30, 2009		$	575,647	$	(1,085	)	$	574,562
Balance at December 31, 2009		$	562,219	$	(1,253	)	$	560,966
Components of comprehensive margin:
	Net margin		35,852		—			35,852
	Unrealized gain on available-for-sale securities		—		1,085			1,085
Total comprehensive margin								36,937
Balance at September 30, 2010		$	598,071	$	(168	)	$	597,903

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

5

Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30, 2010 and 2009

					(dollars in thousands)
				2010			2009
Cash flows from operating activities:
	Net margin			$	35,852		$	39,818
	Adjustments to reconcile net margin to net cash provided (used) by operating activities:
		Depreciation and amortization, including nuclear fuel			196,509			171,124
		Accretion cost			12,848			13,696
		Amortization of deferred gains			(4,245	)		(4,245	)
		Allowance for equity funds used during construction			(1,707	)		(1,904	)
		Deferred outage costs			(25,229	)		(25,362	)
		(Gain) loss on sale of investments			(12,013	)		12,018
		Regulatory deferral of costs associated with nuclear decommissioning			4,987			(20,810	)
		Other			(4,216	)		(483	)
	Change in operating assets and liabilities:
		Receivables			(25,622	)		(5,501	)
		Inventories			24,137			(24,056	)
		Prepayments and other current assets			(4,384	)		131
		Accounts payable			(2,487	)		(12,512	)
		Accrued interest			(13,498	)		(3,319	)
		Accrued and withheld taxes			(2,779	)		2,072
		Other current liabilities			(2,782	)		(92	)
		(Decrease) increase in Member power bill prepayments			(115,831	)		189,047
			Total adjustments		23,688			289,804
Net cash provided by operating activities					59,540			329,622
Cash flows from investing activities:
		Property additions			(524,334	)		(454,313	)
		Plant acquisition			—			(105,008	)
		Activity in decommissioning fund—Purchases			(480,447	)		(495,689	)
		—Proceeds			476,630			491,715
		Decrease in restricted cash and cash equivalents			16,106			10,255
		Increase in restricted short-term investments			(181	)		(39,738	)
		Activity in investment in associated organizations—Purchases			(4,142	)		(11,395	)
		—Proceeds			3,196			1,666
		Activity in other long-term investments—Purchases			(4,313	)		(1,037	)
		—Proceeds			3,100			900
		Other			5,420			(2,158	)
Net cash used in investing activities					(508,965	)		(604,802	)
Cash flows from financing activities:
		Long-term debt proceeds			222,631			464,026
		Long-term debt payments			(222,265	)		(86,419	)
		Increase in short-term borrowings, net			297,413			206,672
		Other			5,373			(6,147	)
Net cash provided by financing activities					303,152			578,132
Net (decrease) increase in cash and cash equivalents					(146,273	)		302,952
Cash and cash equivalents at beginning of period					579,069			167,659
Cash and cash equivalents at end of period				$	432,796		$	470,611
Supplemental cash flow information:
Cash paid for—
		Interest (net of amounts capitalized)		$	173,307		$	161,457
Supplemental disclosure of non-cash investing and financing activities:
		Plant expenditures included in ending accounts payable and other long-term liabilities		$	95,797		$	(977	)
		Acquired power purchase and sale liability		$	—		$	98,100

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

6

Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
September 30, 2010 and 2009

(A)

General.    The condensed financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. 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 three- and nine-month periods ended September 30, 2010 and 2009. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe 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 our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, as filed with the SEC. The results of operations for the three- and nine-month periods ended September 30, 2010 are not necessarily indicative of results to be expected for the full year. As noted in our 2009 Form 10-K, substantially all of our sales are to our 39 electric distribution cooperative members and, thus, the receivables on the accompanying balance sheets are principally from our members. (See "Notes to Financial Statements" in our 2009 Form 10-K.)

(B)

Fair Value Measurements.    Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

•

Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.

•

Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.

•

Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

7

As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

1.    Market approach.    The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.

2.    Income approach.    The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

3.    Cost approach.    The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence.

The tables below detail assets and liabilities measured at fair value on a recurring basis for the periods ended September 30, 2010 and December 31, 2009.

						Fair Value Measurements at Reporting Date Using
				September 30, 2010			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
				(dollars in thousands)
Decommissioning funds
	Domestic equity		$	84,984		$	84,984	$	—		$	—
	Corporate bonds			50,894			50,894		—			—
	International equity			40,308			40,308		—			—
	U.S. Treasury and government agency securities			43,896			43,896		—			—
	Agency mortgage and asset backed securities			29,220			29,220		—			—
	Municipal bonds			1,525			1,525		—			—
	Derivative instruments			(523	)		—		—			(523	)
	Other			1,635			1,635		—			—
Bond, reserve and construction funds				2,877			2,877		—			—
Long-term investments				91,031			66,937		—			24,094	(1)
Natural gas swaps				(4,724	)		—		(4,724	)		—
Deposit on Rocky Mountain transactions				121,556			—		—			121,556
Investments in associated companies				54,794			—		—			54,794
		Total	$	517,473		$	322,276	$	(4,724	)	$	199,921

8

						Fair Value Measurements at Reporting Date Using
				December 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
				(dollars in thousands)
Decommissioning funds:
	Domestic equity		$	89,723		$	89,723	$	—		$	—
	Corporate bonds			48,317			48,317		—			—
	International equity			40,951			40,951		—			—
	U.S. Treasury and government agency securities			35,137			35,137		—			—
	Agency mortgage and asset backed securities			21,383			21,383		—			—
	Preferred stock			1,463			—		1,463			—
	Municipal bonds			1,267			1,267		—			—
	Derivative instruments			(260	)		—		—			(260	)
	Other			1,765			1,765		—			—
Bond, reserve and construction funds				3,982			3,982		—			—
Long-term investments				87,129			60,119		—			27,010	(1)
Natural gas swaps				(12,516	)		—		(12,516	)		—
Deposit on Rocky Mountain transactions				115,641			—		—			115,641
Investments in associated companies				53,199			—		—			53,199
		Total	$	487,181		$	302,644	$	(11,053	)	$	195,590

⁽¹⁾

Represents auction rate securities investments we hold.

The following tables present the changes in our Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2010 and 2009, respectively.

		Three Months Ended September 30, 2010
			Decommissioning funds			Long-term investments			Deposit on Rocky Mountain transactions		Investments in associated companies
			(dollars in thousands)
Assets:
Balance at June 30, 2010		$	(311	)	$	24,485		$	119,542	$	55,329
Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(212	)		—			2,014		(535	)
	Impairment included in other comprehensive deficit		—			9			—		—
Purchases, issuances, liquidations			—			(400	)		—		—
Balance at September 30, 2010		$	(523	)	$	24,094		$	121,556	$	54,794

9

		Nine Months Ended September 30, 2010
			Decommissioning funds			Long-term investments			Deposit on Rocky Mountain transactions		Investments in associated companies
			(dollars in thousands)
Assets:
Balance at January 1, 2010		$	(260	)	$	27,010		$	115,641	$	53,199
Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(263	)		—			5,915		1,595
	Impairment included in other comprehensive deficit		—			184			—		—
Purchases, issuances, liquidations			—			(3,100	)		—		—
Balance at September 30, 2010		$	(523	)	$	24,094		$	121,556	$	54,794

		Three Months Ended September 30, 2009
			Decommissioning funds			Long-term investments			Deposit on Rocky Mountain transactions		Investments in associated companies
			(dollars in thousands)
Assets:
Balance at June 30, 2009		$	8,661		$	29,299		$	111,868	$	53,491
Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		31			—			1,886		(1,140	)
	Impairment included in other comprehensive deficit		—			27			—		—
Purchases, issuances, liquidations			(3,153	)		(700	)		—		—
Balance at September 30, 2009		$	5,539		$	28,626		$	113,754	$	52,351

		Nine Months Ended September 30, 2009
			Decommissioning funds			Long-term investments			Deposit on Rocky Mountain transactions		Investments in associated companies
			(dollars in thousands)
Assets:
Balance at January 1, 2009		$	6,085		$	29,643		$	108,219	$	43,441
Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		31			—			5,535		8,910
	Impairment included in other comprehensive deficit		—			(117	)		—		—
Purchases, issuances, liquidations			(577	)		(900	)		—		—
Balance at September 30, 2009		$	5,539		$	28,626		$	113,754	$	52,351

Realized gains and losses included in earnings for the period are reported in investment income.

10

The assets included in the "Long-term investments" column in each of the Level 3 tables above are auction rate securities. As a result of market conditions, including the failure of auctions for the auction rate securities in which we invested, the fair value of these auction rate securities was determined using an income approach based on a discounted cash flow model. The discounted cash flow model utilized projected cash flows at current rates, which was adjusted for illiquidity premiums based on discussions with market participants. At September 30, 2010, we held auction rate securities with maturity dates ranging from March 15, 2028 to December 1, 2045.

At December 31, 2009, we had a total temporary impairment of $1,690,000 on our investments in auction rate securities. Based on the fair value of these auction rate securities as of September 30, 2010, we recorded a reduction to the temporary impairment of approximately $184,000. The temporary impairment is reflected in "Accumulated other comprehensive deficit" on the condensed unaudited balance sheets. The various assumptions we utilize to determine the fair value of our auction rate securities investments will vary from period to period based on the prevailing economic conditions. If the market for our auction rate securities investments should deteriorate, we 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 September 30, 2010, would have resulted in a decrease in the fair value of our auction rate securities investments by approximately $1,310,000. These investments were rated either A3 or Aaa by Moody's Investors Service and AAA by Standard and Poor's as of September 30, 2010. Because we have the ability and intent to hold these investments until we recover our original investment value, we considered the investments to be only temporarily impaired at September 30, 2010.

(C)

Disclosures about Derivative Instruments and Hedging Activities.    Our executive risk management committee provides general oversight over all risk management activities, including but not limited to, commodity trading and investment portfolio management. We use commodity trading derivatives, which are designated as hedging instruments under authoritative guidance for Accounting for Derivatives and Hedging Activities, to manage our exposure to fluctuations in the market price of natural gas. Consistent with our rate-making treatment for energy costs which are flowed-through to our members, unrealized gains or losses on the natural gas swaps are reflected as an unbilled receivable. Within our nuclear decommissioning trust fund, derivatives including options, swaps and credit default swaps which are non-speculative, are utilized to mitigate volatility associated with duration, default, yield curve and the interest rate risks of the portfolio. We do not hold or enter into derivative transactions for trading or speculative purposes. Consistent with our rate-making treatment, unrealized gains or losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset or liability.

Under the natural gas swap arrangements, 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.

At September 30, 2010, the estimated fair value of our natural gas contracts was an unrealized loss of approximately $4,724,000. See Note B for further discussion on fair value measurements of financial instruments.

We are 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. We manage 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 us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer

11

a financial loss. However, as of September 30, 2010, all of the counterparties with transaction amounts outstanding in our hedging portfolio are rated above investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated above investment grade.

We have entered into International Swaps and Derivatives Association Agreements with our natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring counterparties' credit standing, including those experiencing financial problems, significant swings in credit default swap rates, credit rating changes by external rating agencies, or changes in ownership. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider 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 us 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. The collateral and credit support requirements vary by contract and by counterparty. We may only post credit support in the form of a letter of credit due to provisions within our Rural Utilities Service Loan Contract; however, we may receive collateral in the form of cash or credit support. As of September 30, 2010, neither we 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 September 30, 2010 due to our credit rating being downgraded below investment grade, we could have been required to post letters of credit totaling up to $4,724,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives and derivatives within our nuclear decommissioning trust fund as of September 30, 2010 that are expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)		Decommissioning Fund Derivative Instruments (in millions)
2010	0.64	$	(1.40	)
2011	2.55		(0.60	)
2012	0.38		0.20
2013	—		(3.80	)
2014	—		(1.92	)
2015	—		(0.20	)
2016	—		(0.08	)
Total	3.57	$	(7.80	)

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The table below reflects the fair value of derivative instruments and their effect on our condensed unaudited balance sheet for the period ended September 30, 2010.

		Balance Sheet Location	Fair Value
				(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities:
Assets
	Natural Gas Swaps	Receivables	$	4,750
	Natural Gas Swaps	Receivables		(26	)
Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities			$	4,724
Liabilities
	Natural Gas Swaps	Other current liabilities	$	4,750
	Natural Gas Swaps	Other current liabilities		(26	)
Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities			$	4,724
Not designated as hedges under authoritative guidance related to derivatives and hedging activities:
Assets
	Nuclear decommissioning trust	Decommissioning fund	$	20,995
	Nuclear decommissioning trust	Decommissioning fund		(21,518	)
	Nuclear decommissioning trust	Deferred asset associated with retirement obligations		21,003
	Nuclear decommissioning trust	Deferred asset associated with retirement obligations		(21,071	)
Total not designated as hedges under authoritative guidance related to derivatives and hedging activities			$	(591	)

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The following table presents the gains and (losses) on derivative instruments recognized in income for the three and nine months ended September 30, 2010.

Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses
		Income Statement Location	Three months ended			Nine months ended
				(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities
	Natural Gas Swaps	Purchase power	$	(12,383	)	$	(17,824	)
Not designated as hedges under authoritative guidance related to derivatives and hedging activities
	Nuclear decommissioning trust	Investment income		1,042			2,107
	Nuclear decommissioning trust	Investment income		(999	)		(2,048	)
Total losses on derivatives			$	(12,340	)	$	(17,765	)

(D)

Investments in Debt and Equity Securities:    Under Accounting for Certain Investments in Debt and Equity Securities, investment securities we hold 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 September 30, 2010 and December 31, 2009. All realized and unrealized gains and losses were determined using the specific identification method. Approximately 25% of these gross unrealized losses were in effect for less than one year. The total gross unrealized losses were primarily due to investments in fixed income securities held in the nuclear decommissioning trust fund. Consistent with our ratemaking, unrealized gains and losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset.

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For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of September 30, 2010 and December 31, 2009:

		(dollars in thousands)
			Gross Unrealized
September 30, 2010	Cost		Gains		Losses			Fair Value
Equity	$	136,650	$	31,305	$	(6,197	)	$	161,758
Debt		174,709		32,557		(24,683	)		182,583
Other		1,502		4		—			1,506
Total	$	312,861	$	63,866	$	(30,880	)	$	345,847

				Gross Unrealized
December 31, 2009	Cost			Gains		Losses			Fair Value
Equity	$	127,704		$	35,003	$	(3,671	)	$	159,036
Debt		170,033			15,685		(13,089	)		172,629
Other		(815	)		7		—			(808	)
Total	$	296,922		$	50,695	$	(16,760	)	$	330,857

(E)

Recently Issued or Adopted Accounting Pronouncements.    In January 2010, the Financial Accounting Standards Board (FASB) issued Fair Value Measurements and Disclosures—Improving Disclosures about Fair Value Measurements. The new guidance provides for improved disclosure requirements about fair value measurements and requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The guidance also clarifies that fair value measurement disclosures are required for each asset class. In the reconciliation for fair value measurements using significant unobservable inputs (Level 3), the standard also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one number). We adopted this new guidance beginning with the quarter ended March 31, 2010 except that the requirement to present Level 3 activity separately is not effective for us until the quarter ending March 31, 2011. The adoption of the standard did not have a material effect on our disclosures.

(F)

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 our 2009 Form 10-K.

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

	Accumulated Other Comprehensive Deficit Three Months Ended
		Available-for-sale Securities			Total
Balance at June 30, 2009	$	(1,427	)	$	(1,427	)
Unrealized gain		342			342
Balance at September 30, 2009	$	(1,085	)	$	(1,085	)
Balance at June 30, 2010	$	(220	)	$	(220	)
Unrealized gain		52			52
Balance at September 30, 2010	$	(168	)	$	(168	)

	Accumulated Other Comprehensive Deficit Nine Months Ended
		Available-for-sale Securities			Total
Balance at December 31, 2008	$	(1,348	)	$	(1,348	)
Unrealized gain		263			263
Balance at September 30, 2009	$	(1,085	)	$	(1,085	)
Balance at December 31, 2009	$	(1,253	)	$	(1,253	)
Unrealized gain		1,085			1,085
Balance at September 30, 2010	$	(168	)	$	(168	)

(G)

Environmental Matters.    There are a number of environmental matters that could have an effect on our financial condition or results of operations. At this time, the resolution of these matters is uncertain, and we have 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, 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 the future, we may become subject to greenhouse gas emission restrictions as a result of regulation aimed at responding to climate change.

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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. See "BUSINESS—ENVIRONMENTAL AND OTHER REGULATION" in our 2009 Form 10-K for a more detailed discussion of current and potential future regulations. 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. Although it is our intent to comply with applicable current and future regulations, we cannot provide assurance that we will always be in compliance with such requirements.

(H)

Restricted cash.    The restricted cash balance at September 30, 2010 consisted of $6,299,000 of clean renewable energy bond proceeds on deposit with CoBank to fund a clean renewable energy project at the Rocky Mountain Pumped Storage Hydroelectric facility.

(I)

Restricted short-term investments.    At September 30, 2010, we had $80,771,000 on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service/Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.

(J)

Member Power Bill Prepayments.    In December 2008, we instituted a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited each and every month against the power bills and are recorded on our books as a reduction to member revenues. At September 30, 2010, member power bill prepayments as reflected on the condensed balance sheets, including unpaid discounts, were $84,683,000, of which, $64,963,000 is classified as current liabilities and $19,720,000 as deferred credits and other liabilities. The prepayments are being applied against members' power bills through May 2015, with the majority of the remaining balance scheduled to be applied in 2011.

(K)

Bond Issuance.    In March 2010, the Development Authority of Burke County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $133,550,000 in aggregate principal amount of tax-exempt pollution control revenue bonds for the purpose of refunding certain pollution control revenue bonds previously issued by the development authorities on our behalf. We redeemed the prior bonds on April 1, 2010.

(L)

Subsequent Events.    We have evaluated subsequent events up until the time that our financial statements were issued.

On November 9, 2010, we issued $450,000,000 of taxable first mortgage bonds primarily for the purpose of funding a portion of the cost of constructing Plant Vogtle Units No. 3 and No. 4. A substantial portion of the proceeds were used to repay outstanding short-term borrowings in connection with payments previously made for construction of this facility. The first mortgage bonds are secured under our first mortgage indenture.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 39 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members through a combination of our generation assets, and to a lesser extent, power purchased from power marketers and other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Forward-Looking Statements and Associated Risks

This Quarterly Report on Form 10-Q contains forward-looking statements, including statements regarding, among other items, (i) anticipated financing transactions by us, (ii) our future capital expenditure requirements and funding sources and (iii) achievement of a margins for interest ratio at the minimum requirement contained in our first mortgage indenture and, in the case that our board of directors approves a budget for a particular fiscal year that seeks to achieve a higher margins for interest ratio, such higher board-approved margins for interest ratio. These forward-looking statements are based largely on our current expectations and are subject to a number of risks and uncertainties, some of which are beyond our control. For a discussion of some factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "Item 1A—RISK FACTORS" contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. In light of these risks and uncertainties, there can be no assurance that events anticipated by the forward-looking statements contained in this Quarterly Report on Form 10-Q will in fact transpire.

Results of Operations

For the Three and Nine Months Ended September 30, 2010 and 2009

Net Margin

Throughout the year, we monitor our operating results and, with board approval, make budget adjustments when and as necessary to ensure our targeted margins for interest ratio is achieved. Under the first mortgage indenture, we are required to establish and collect rates that are reasonably expected, together with our other revenues, to yield at least a 1.10 margins for interest ratio in each fiscal year. However, to enhance margin coverage during this period of generation facility construction and acquisition, our board of directors approved budgets for 2010 and 2011 to achieve a 1.14 margins for interest ratio. As our construction program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below the 1.10 margins for interest ratio required under our first mortgage indenture.

Our net margin for the three- and nine-month periods ended September 30, 2010 was $13.8 million and $35.9 million compared to $11.4 million and $39.8 million for the same periods of 2009. Through September 30, 2010, we have collected 106% of our targeted net margin of $33.8 million for the year ending December 31, 2010. This is typical as our management generally budgets conservatively and makes adjustments to the budget throughout the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio of 1.14.

Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned or

18

purchased resources or member-owned resources over which we have dispatch rights and 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 20.1% and 12.3% higher in the three- and nine-month periods ended September 30, 2010 than for the same periods of 2009. Megawatt-hour sales to members increased 19.2% and 11.9% for the three- and nine-month periods ended September 30, 2010 versus the same periods of 2009. The average total revenue per megawatt-hour from sales to members increased 0.7% and 0.3% for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009.

The components of member revenues for the three- and nine-month periods ended September 30, 2010 and 2009 were as follows (amounts in thousands except for cents per kilowatt-hour):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Capacity revenues	$	172,217	$	166,527	$	514,435	$	495,687
Energy revenues		198,236		141,887		485,809		394,959
Total	$	370,453	$	308,414	$	1,000,244	$	890,646
Kilowatt-hours sold to members		6,649,453		5,576,812		17,451,164		15,590,051
Cents per kilowatt-hour		5.57¢		5.53¢		5.73¢		5.71¢

Capacity revenues for the three- and nine-month periods ended September 30, 2010 increased 3.4% and 3.8% compared to the same periods of 2009. This increase in capacity revenues primarily resulted from higher budgeted fixed operations and maintenance expenses and depreciation expenses. Energy revenues were 39.7% and 23.0% higher for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. Our average energy revenue per megawatt-hour from sales to members was 17.2% and 9.9% higher for the three- and nine-month periods ended September 30, 2010 as compared to the same periods of 2009. The increase in total energy revenues was primarily due to the pass-through to our members of higher fuel costs (primarily due to higher coal-fired generation). For a discussion of fuel costs, see "Operating Expenses" below.

Operating Expenses

Operating expenses for the three- and nine-month periods ended September 30, 2010 increased 24.5% and 15.0% compared to the same periods of 2009. This increase in operating expenses was primarily due to higher fuel costs, higher production expenses and higher depreciation expenses, offset somewhat by a decrease in purchased power costs.

For the three- and nine-month periods ended September 30, 2010, total fuel costs increased 69.5% and 36.2% and total megawatt-hour generation increased 21.7% and 13.8% compared to the same periods of 2009. Average fuel costs per megawatt-hour increased 39.3% and 19.8% in the three- and nine-month periods of 2010 compared to the same periods of 2009. This increase in total fuel costs resulted primarily from higher coal-fired generation at Plant Scherer and Plant Wansley. The increase in average fuel costs during the nine-month period ended September 30, 2010 compared to the same period of 2009 resulted primarily from a 23.8% or 1,559,000 megawatt-hour increase in generation at Plant Scherer and Plant Wansley due to significantly less scheduled outage time in 2010 as compared to 2009. In addition, total natural gas-fired generation increased 18.0% or 333,000 megawatt-hours for the nine-months ended September 30, 2010 as compared to the same period of 2009. The average fuel cost per megawatt-hour of coal- and gas-fired generation is substantially higher than nuclear generation;

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thus, the increase in coal- and gas-fired generation was the primary contributor to the increase in average fuel costs per megawatt-hour of generation.

Production expenses increased 19.6% and 17.6% for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. This increase is partly attributable to increased general operations and maintenance expenses at the jointly owned plants (Plants Hatch, Vogtle, Wansley and Scherer) during the three- and nine-month periods ended September 30, 2010 and partly due to operations and maintenance expenses for the Hawk Road and Hartwell Energy Facilities incurred in 2010. We acquired these facilities in May and October of 2009, respectively.

Total purchased power costs decreased 44.3% and 41.7% for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. Purchased megawatt-hours decreased 70.6% and 54.1% for the three- and nine-month periods of 2010 compared to the same periods of 2009. The average cost per megawatt-hour of total purchased power increased 89.8% and 27.1% for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009.

Purchased power costs were as follows (amounts in thousands except for cents per kilowatt-hour):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Capacity costs	$	3,848	$	11,407	$	11,905	$	33,114
Energy costs		20,873		32,942		48,441		70,431
Total	$	24,721	$	44,349	$	60,346	$	103,545
Kilowatt-hours of purchased power		64,711		220,306		291,339		635,251
Cents per kilowatt-hour		38.20¢		20.13¢		20.71¢		16.30¢

Purchased power capacity costs decreased 66.3% and 64.1% in the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. Purchased power energy costs for the three- and nine-month periods ended September 30, 2010 decreased 36.7% and 31.2% compared to the same periods of 2009. The average cost per kilowatt-hour of purchased power energy increased 115.7% and 50.0% for the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. The decrease in purchased power capacity costs is primarily attributable to the Hartwell acquisition. As part of the acquisition, we acquired an existing power purchase agreement we had in place with the former owners of Hartwell. The decrease in purchased power energy costs resulted from (i) a decrease in megawatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with lower price spot market purchased power energy, (ii) lower realized losses incurred for natural gas financial contracts utilized for managing exposure to fluctuations in the market prices of natural gas and (iii) no power purchases under the Hartwell power purchase agreement in 2010 as a result of our acquisition of Hartwell in October 2009.

Depreciation and amortization expense increased 3.3% and 11.2% in the three- and nine-month periods ended September 30, 2010 as compared to the same periods of 2009. The increase was primarily due to increased depreciation expense for Plants Scherer and Wansley related to capital expenditures for environmental compliance projects, and to a lesser extent, depreciation expense related to Hawk Road and Hartwell, which were acquired in May and October of 2009, respectively.

Interest charges

Interest expense increased by 11.0% and 11.9% in the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009. This increase was primarily due to the issuance in November 2009 of $400 million of taxable fixed rate bonds for the purpose of financing construction of Plant Vogtle Units No. 3 and No. 4.

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Allowance for debt funds used during construction increased by 163.2% and 128.5% in the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009 primarily due to construction expenditures for Plant Vogtle Units No. 3 and No. 4.

Amortization of debt discount and expense increased 7.4% and 29.7% in the three- and nine-month periods ended September 30, 2010 compared to the same periods of 2009 partly due to amortization of issuance costs associated with transactions that closed in May and August 2009 to provide supplemental credit enhancement for the Rocky Mountain lease arrangements and partly due to the amortization of losses on debt refinancing associated with the Hartwell acquisition.

Financial Condition

Balance Sheet Analysis as of September 30, 2010

Assets

Cash used for property additions for the nine-month period ended September 30, 2010 totaled $524.3 million. Of this amount, approximately $308 million was associated with the construction expenditures for Plant Vogtle Units No. 3 and No. 4. The remaining expenditures were primarily for environmental control systems being installed at Plant Scherer, normal additions and replacements to existing generation facilities and purchases of nuclear fuel.

Cash and cash equivalents decreased by $146.3 million in the nine-month period ended September 30, 2010 and can be largely attributed to expenditures of approximately $524.3 million for property additions and a net application of $115.8 million of the members' prepayments of their power bills. Other significant uses of cash include principal and interest payments and payments to Georgia Power Company for operation and maintenance costs at our facilities co-owned with Georgia Power. Short-term borrowings and long-term debt proceeds of $297.4 million and $222.6 million, respectively, were significant sources of cash during the nine-month period ended September 30, 2010.

The $6.3 million restricted cash balance at September 30, 2010 consisted of the remaining proceeds obtained from the issuance of clean renewable energy bonds in December 2009. The proceeds from the clean renewable energy bonds are restricted in use for certain qualifying expenditures. The $16.1 million decrease in restricted cash for the nine-month period ended September 30, 2010 was due in part to the expenditure of $5.2 million for such qualifying costs. In addition, $10.9 million of restricted cash, the proceeds from a December 2009 bond refinancing, was utilized to payoff the principal amount of the refinanced pollution control revenue bonds that matured in January 2010.

Receivables increased by $17.4 million in the nine-month period ended September 30, 2010. The December 31, 2009 receivables balance included approximately $20.7 million of credits available to the members for a board approved reduction to 2009 revenue requirements as a result of margins collected in excess of our 2009 target 1.12 margins for interest ratio. The increase in receivables was largely due to these credits being utilized by the members during 2010. The receivable for amounts billed or billable to the members for their monthly power bills also increased by approximately $1.7 million in September 2010 compared to December 2009. Receivables from Smarr EMC for costs incurred for operation of its facilities also increased by $2.5 million. These increases were partially offset by a $7.8 million decrease in the receivable from the members associated with natural gas derivatives. This decrease was largely due to the settlement of certain natural gas contracts. For information regarding the natural gas contracts, see Note C of Notes to Unaudited Condensed Financial Statements.

Inventories, including fossil fuel and spare parts inventories, decreased by $24.1 million in the nine-month period ended September 30, 2010. The decrease was primarily due to a $27.6 million decrease in coal fuel inventories, largely a result of a planned reduction in coal fuel inventory balances.

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Prepayments and other current assets increased by $4.4 million in the nine-month period ended September 30, 2010 primarily as a result of an increase in prepaid insurance balances.

The $9.5 million decrease in deferred amortization of capital leases for the nine-month period ended September 30, 2010 was primarily due to regular monthly amortization.

The deferred tax asset represents an offset to the liability recorded for unrecognized tax benefits due to an uncertain tax position. We are carrying forward significant regular tax and alternative minimum tax net operating losses. As a result, any regular tax liability in open tax years related to an uncertain tax position would be offset by regular net operating losses. At December 31, 2009, we had recognized a $24.0 million liability for an uncertain tax position and consequently an offsetting $24.0 million deferred asset. The uncertain tax position relates to the 2006 tax year for which the U.S. federal statute of limitations expired during the third quarter of 2010. Accordingly, this liability and the related deferred tax asset were each reduced by $24.0 million during the third quarter of 2010 to zero.

The $3.5 million decrease in the deferred asset associated with retirement obligations in the nine-month period ended September 30, 2010 was primarily due to decommissioning fund earnings. The deferred asset increases or decreases to the extent of timing differences between recognized accretion expense associated with nuclear decommissioning and the amounts recovered through decommissioning fund earnings. Nuclear decommissioning accretion and related expenses of approximately $11.3 million and decommissioning fund net earnings of approximately $16.3 million resulted in the deferred charge decreasing by $5.0 million in the nine-month period ended September 30, 2010. Partially offsetting this decrease was a $2.0 million decrease in the unrealized gains associated with the nuclear decommissioning fund. Consistent with our ratemaking policy, unrealized gains or losses from the nuclear decommissioning fund are deducted from or added to the deferred asset associated with retirement obligations. The decrease in the nuclear decommissioning fund unrealized gains therefore increased the deferred asset by $2.0 million.

Equity and Liabilities

Long-term debt and capital leases due within one year increased $28.7 million as a result of scheduled debt maturities and the consequent reclassification of certain long-term debt.

The $297.4 million increase in short-term borrowings was primarily to fund construction of Plant Vogtle Units No. 3 and No. 4.

Accounts payable increased $72.9 million in the nine-month period ended September 30, 2010 primarily due to a $69.8 million increase in the payable to Georgia Power for operation, maintenance and capital costs, primarily associated with construction costs for Plant Vogtle Units No. 3 and No. 4. In addition, there was a $3.8 million increase in the payable for natural gas, primarily due to increased generation at the natural gas fired plants in September 2010 compared with December 2009.

The $13.5 million decrease in accrued interest during the nine-month period ended September 30, 2010 was due to the normal timing differences between interest payments and interest expense accruals.

Member power bill prepayments represent funds received from the members for prepayment of their monthly power bills. At September 30, 2010, $65.0 million of member power bill prepayments was classified as a current liability and $19.7 million of member power bill prepayments was classified as a long-term deferred liability. During the nine-month period ended September 30, 2010, approximately $66.4 million of prepayments was received from the members and approximately $182.2 million was applied to the members' monthly power bills. The application of member prepayments received in the prior year to the current year's power bills significantly reduced net cash provided by operations. For information regarding the power bill prepayment program, see Note J of Notes to Unaudited Condensed Financial Statements and see "Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Liquidity" herein.

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Other current liabilities decreased by $10.7 million during nine-month period ended September 30, 2010, primarily due to a $6.2 million decrease in accruals for other miscellaneous payables. This decrease was largely due to the payment and true-up of estimated operation and maintenance costs. The liability associated with natural gas derivatives also decreased by $7.8 million primarily due to the settlement of certain natural gas contracts. Partially offsetting these increases was a $3.6 million liability established as a result of the receipt of certain grant monies relating to energy efficiency programs.

Primarily as a result of incurring approximately $6.4 million of removal costs for the retirement of certain assets, accumulated retirement costs for other obligations decreased by $5.2 million during the nine-month period ended September 30, 2010.

The long-term contingent liability represents a liability recorded for unrecognized tax benefits. The $24 million decrease was the result of the expiration of the statute of limitations for the 2006 tax year. See the deferred tax asset discussion above for more information.

The $12.5 million decrease in the power sale agreement, which we assumed as part of the acquisition of Heard County Power L.L.C. in May 2009, in the nine-month period ended September 30, 2010 was due to regular monthly amortization.

Other deferred credits and liabilities increased $42.3 million in the nine-month period ended September 30, 2010 partially due to a $19.7 million liability established in 2010 for long-term contract retention payables associated with the Plant Vogtle Units No. 3 and No. 4 construction. The increase was also partially due to a $10.5 million increase in the regulatory liability established to defer the effects on net margin that result from Hawk Road Energy Facility operations. Also contributing to the increase was a $7.5 million increase in funding received from the members for future debt payments related to the Talbot and Chattahoochee Energy Facilities, as well as a $4.2 million increase in funding for the future overhaul of the combustion turbine plants.

Capital Requirements and Liquidity and Sources of Capital

Future Power Resources

To meet the energy needs of our members, we have embarked on a generation expansion program. On October 26, 2010, we entered into a non-binding term sheet with a third party to acquire natural gas-fired generation facilities. In addition to significantly greater generation capacity, the purchase price for the facilities is expected to be less than the cost projected for us to construct a previously disclosed 605-megawatt combined cycle plant. The proposed acquisition remains subject to the completion of our due diligence and approval process, including subscription by our members and approval by our members and our Board of Directors, as well as negotiation of definitive agreements with the third party and, as a result, may not result in a completed transaction. If we complete this acquisition, we anticipate that it will close in early 2011.

If we acquire these facilities, we would revise our plans to construct future generation resources to reflect this additional generation capacity and our members' projected power supply needs. Completing this acquisition would affect two generation projects currently under development, a 605-megawatt combined cycle plant and the 100-megawatt Warren County biomass plant, which are projected to cost us approximately $750 million and $477 million, including allowance for funds used during construction, respectively. Upon closing, we would cancel the combined cycle plant and indefinitely defer the Warren County biomass plant while we continue to monitor regulatory and legislative uncertainties related to biomass electricity generation. These actions would reduce our previously disclosed projected capital expenditures by approximately $250 million through 2012 and by a total of approximately $1.2 billion through 2015, exclusive of expenditures at closing related to the purchase price of the target facilities. To date, the expenditures on the combined cycle and biomass plant have not been material. This acquisition would have no effect on our participation in the construction of Plant Vogtle Units No. 3

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and No. 4. We will continue to evaluate other generation resource development opportunities to help meet our members' projected power supply needs over the next ten years.

See "Financing Activities" herein for a discussion of how we plan to finance the acquisition of the gas-fired facilities, should the acquisition be completed. For further discussion of our planned future generation resources and projected capital expenditures, see "BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources" in our 2009 Form 10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Future Power Resources" and "—Capital Expenditures" in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010.

Environmental Regulations

Several environmental regulation-related developments have occurred since our Quarterly Report on Form 10-Q was filed for the second quarter of 2010 was filed with the SEC. The final rule issued on June 22, 2010 revising the sulfur dioxide standard has now been challenged. After EPA's proposal of the Transport Rule on August 2, 2010, EPA issued a Notice of Data Availability on September 1, 2010, updating certain analyses used to derive the emissions limitations in the Transport Rule and issued a second Notice of Data Availability on October 27, 2010. Also, EPA received approval from the U.S. Court of Appeals for the D.C. Circuit to delay the finalization of the proposed national emission standards for hazardous air pollutants for industrial boilers proposed on June 4, 2010 for one month until January 16, 2011. This rule and the proposed Transport Rule could undergo substantial revision prior to finalization, at which time they too might be challenged. We cannot predict at this time whether any of these developments will ultimately result in the further regulation of emissions from our existing or future power plants, or the effects of any such regulation, including any resulting capital requirements.

Liquidity

At September 30, 2010, we had $862.8 million of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $432.8 million in cash and cash equivalents and $430 million of unused and available committed short-term credit arrangements. As discussed above, cash and cash equivalents decreased by approximately $146.3 million during the nine-month period ended September 30, 2010 compared to the same period in 2009 mainly due to expenditures for property additions and the application of member power bill prepayments to power bills. Short-term borrowings and long-term debt proceeds of $297.4 million and $222.6 million, respectively, were significant sources of cash during the nine-month period ended September 30, 2010.

Our short-term credit facilities are shown in the table below. We expect to renew these short-term credit facilities, as needed, prior to their respective expiration dates.

		Authorized Amount		Available 9/30/2010			Expiration Date
Unsecured Facilities:
	Commercial Paper Backup Line of Credit	$	475	$	1	(1)	July 2012
	CoBank Line of Credit		50		0		December 2010
	CFC Line of Credit		50		0		October 2011
	JPMorgan Chase Line of Credit		150		29	(2)	December 2012
Secured facilities:
	CoBank Line of Credit		150		150		November 2012
	CFC Line of Credit		250		250		December 2013
Total		$	1,125	$	430

⁽¹⁾

The portion of this facility that is unavailable is supporting commercial paper we have issued.

⁽²⁾

$114 million of this facility is currently utilized as letter of credit support for variable rate pollution control revenue bonds.

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Due to the significant amount of expenditures we are incurring relating to environmental compliance projects and construction or acquisition 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. In particular, we are using commercial paper and short-term credit facilities to provide interim financing for the environmental compliance expenditures, for the acquisition of generation facilities and for new generation construction until permanent financing for these projects is in place. In November 2010 we issued $450 million of long-term first mortgage bonds to fund a portion of the cost of constructing Plant Vogtle Units No. 3 and No. 4 and used a substantial portion of the bond proceeds to repay short-term borrowings that were providing interim funding for this same purpose. A similar repayment of short-term borrowings occurred in connection with the issuance of $400 million of long-term first mortgage bonds issued in November 2009. For a more detailed discussion of our plans regarding financing of these facilities, see "—Financing Activities."

In order to further enhance our liquidity position during the peak years of new generation construction, we currently anticipate a restructuring and related upsizing of certain of our short-term credit facilities, including the commercial paper backup credit facility, sometime in 2011. The exact timing, size and term of the restructured credit facilities will be influenced by many factors, including the ultimate size of our construction program, the timing of permanent financing for new generation facilities and overall market conditions.

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 in place, thereby providing 100% dedicated backup support for any paper outstanding. We periodically assess our needs in order to determine the appropriate amount of commercial paper backup to maintain and currently have in place a $475 million committed backup credit facility provided by eight participant banks, with Bank of America serving as administrative agent for this facility.

Along with the lines of credit from CoBank, the National Rural Utilities Cooperative Finance Corporation (CFC) and JPMorgan Chase Bank, funds may also be advanced under the backup line of credit supporting commercial paper for general working capital purposes. In addition, under certain of our committed credit facilities we have the ability to issue letters of credit totaling $450 million in the aggregate, of which approximately $180 million remained available at September 30, 2010. However, any amounts related to issued letters of credit will reduce the amount available to draw as working capital under those facilities. 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.

Under the $250 million line of credit with CFC, we have the option of converting any amounts outstanding under the line of credit to a term loan with a maturity no later than December 31, 2043. Any amounts drawn under the $250 million CFC line of credit, as well as any amounts converted to a term loan, will be secured under our first mortgage indenture.

Several of our line of credit facilities contain a similar financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2010, the required minimum level was $544.8 million and our actual patronage capital was $598.1 million. An additional covenant contained in several of our credit facilities limits our secured indebtedness and our unsecured indebtedness, both as defined by these credit facilities, to $8.5 billion and $4.0 billion, respectively. At September 30, 2010, we had approximately $4.5 billion of secured indebtedness and $666 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.

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We also have a power bill prepayment program that provides us with an additional source of liquidity. Under the program, members can prepay their power bills from us at a discount for an agreed upon number of months in advance, after which the prepayments are credited against the participating members' monthly power bills. The discount is comparable to our avoided cost of borrowing. As of September 30, 2010, the balance of member prepayments received but not yet credited to their power bills was $84.7 million, which represented prepayments from sixteen members participating in the program. We began applying the prepayments against participating members' power bills in 2009 and will continue doing so through May 2015, with the majority of the remaining balance scheduled to be applied in 2011. For more information regarding the power bill prepayment program, see Note J of Notes to Unaudited Condensed Financial Statements.

At September 30, 2010, current assets included $81 million of restricted short-term investments pursuant to deposits made to a Rural Utilities Service Cushion of Credit Account. The deposits with the U.S. Treasury were made voluntarily and earn interest at a guaranteed rate of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service payments on Rural Utilities Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. The amount on deposit in this account is less than one year's debt service payments owed to the Rural Utilities Service and Federal Financing Bank. Our decisions regarding how to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.

Financing Activities

Our Indenture.    At September 30, 2010 we had $4.3 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our tangible and some of our intangible assets, including those we acquire in the future. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—Our Indenture" in our 2009 Form 10-K for a further discussion of our first mortgage indenture.

We intend to put in place by year-end 2010 an indenture for unsecured debt securities to provide an additional financing alternative, most notably in connection with interim financing related to generation facility acquisitions and new generation construction.

Bond Financings.    In March 2010, the Development Authority of Burke County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $133.6 million in aggregate principal amount of tax-exempt pollution control revenue bonds for the purpose of refunding certain pollution control revenue bonds previously issued by the development authorities on our behalf to finance or refinance the costs of our undivided interests in certain air or water pollution control and sewage or solid waste disposal facilities. The bonds were issued as variable rate demand bonds backed by an irrevocable direct-pay letter of credit for each series of bonds issued by Bank of America. The bonds are secured under our first mortgage indenture.

On November 9, 2010, we issued $450 million of taxable first mortgage bonds primarily for the purpose of funding a portion of the cost of constructing Plant Vogtle Units No. 3 and No. 4. A substantial portion of the proceeds were used to repay outstanding short-term borrowings in connection with payments previously made for construction of this facility. The first mortgage bonds were secured under our first mortgage indenture.

We are evaluating the potential for an issuance of a modest amount of new tax-exempt debt in connection with costs related to pollution control equipment being installed at coal-fired Plant Scherer, but the timing and exact amount of this new debt, if any, is uncertain at this time. If issued, this tax-exempt debt will be secured under our first mortgage indenture.

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Rural Utilities Service-Guaranteed Loans.    We currently have five approved Rural Utilities Service-guaranteed loans, funded through the Federal Financing Bank, totaling $1.2 billion that are in the process of being drawn down, with $940 million remaining to be advanced. Two of these loans were approved in the third quarter of 2010, including a loan relating to the acquisition of the Hawk Road Energy Facility ($203.1 million) and a loan relating to the acquisition of the Hartwell Energy Facility ($170 million).

We also have three Rural Utilities Service-guaranteed loan applications pending, totaling approximately $1.3 billion, including a loan application related to the Warren County biomass plant, a loan application related to the 605 MW gas-fired combined cycle plant and a loan application related to general improvements at existing generation facilities (action on this general improvements loan is anticipated in 2011). The President's budget proposal for fiscal year 2011 (which began on October 1, 2010) has not yet been adopted, but if adopted would prohibit Rural Utilities Service funding for (i) improvements to existing fossil-fueled generation facilities unless the improvements are related to carbon-capture projects and (ii) construction of new fossil-fueled generation facilities. Nonetheless, should members subscribe to any additional fossil-fueled facilities, including the gas-fired facilities that we may acquire, we anticipate filing loan applications for those facilities as well to the extent Rural Utilities Service regulations in place at that time allow us to do so. As such, should we complete the acquisition of the natural gas-fired facilities discussed above under "Future Power Resources," we intend to submit a loan application to the Rural Utilities Service for long-term financing of the acquired facility, and at the same time would withdraw our loan application previously submitted to the Rural Utilities Service for the 605 MW gas-fired combined cycle plant. For any amounts not funded through the Rural Utilities Service, we would issue taxable bonds secured under our first mortgage indenture. We are considering a variety of alternatives available to us for interim financing in connection with the potential acquisition of the gas-fired facilities including, but not limited to, using cash on hand, drawing down on our existing credit facilities or new unsecured credit facilities and issuing unsecured notes in transactions registered or exempt under the Securities Act of 1933, as amended (see "Our Indenture").

For a more detailed discussion regarding the Rural Utilities Service's current position on funding of generation facilities and a general discussion of the federal programs administered by it, see "BUSINESS—OGLETHORPE POWER CORPORATION—Relationship with Rural Utilities Service" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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

Department of Energy-Guaranteed Loans.    We have signed a conditional term sheet with the Department of Energy that sets forth the general terms of a loan and related loan guarantee that would fund approximately 70% of the estimated $4.2 billion cost to construct our 30% undivided share of Plant Vogtle Units No. 3 and No. 4, not to exceed $3.057 billion. The loan structure would entail a loan that is expected to be funded by the Federal Financing Bank carrying a federal loan guarantee provided by the Department of Energy, with the debt secured under our first mortgage indenture.

We are working with the Department of Energy to finalize the loan guarantee. However, final approval and issuance of a loan guarantee by the Department of Energy is subject to receipt of the combined construction permits and operating licenses for Plant Vogtle Units No. 3 and No. 4 from the Nuclear Regulatory Commission, negotiation of definitive agreements, completion of due diligence by the Department of Energy and satisfaction of other conditions. Therefore, there can be no assurance that the Department of Energy will ultimately issue the loan guarantee to us. We anticipate that any Plant Vogtle costs not funded under the Department of Energy loan guarantee program would be financed through the issuance of taxable bonds.

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Of the approximately $1.2 billion of currently estimated project costs not expected to be funded under the Department of Energy loan guarantee program, we have already financed $850 million through the issuance of first mortgage bonds. We expect to issue another approximately $400 million of first mortgage bonds for this purpose sometime in 2011.

For more detailed information regarding our financing plans, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2009 Form 10-K.

Newly Adopted or Issued Accounting Standards

For a discussion of recently issued or adopted accounting prouncements, see Note E of Notes to Unaudited Condensed Financial Statements herein.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

Our market risks have not changed materially from the risks reported in our 2009 Form 10-K.

Item 4.    Controls and Procedures

As of September 30, 2010, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting or other factors that occurred during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A.    Risk Factors

There have not been any material changes in our risk factors from those reported in "Item 1A—RISK FACTORS" of our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Reserved

Item 5.    Other Information

Not Applicable.

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Item 6.    Exhibits

Number	Description
4.1	Sixth Amended and Restated Loan Contract, dated as of August 13, 2010, between Oglethorpe and the United States of America, together with two notes executed and delivered pursuant thereto.
4.2	Fifty-Fifth Supplemental Indenture, dated as of August 1, 2010, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2010 (FFB V-8) Note and Series 2010 (RUS V-8) Reimbursement Note.
31.1	Rule 13a-14(a)/15d-14(a) Certification, by Thomas A. Smith (Principal Executive Officer).
31.2	Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
32.1	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Thomas A. Smith (Principal Executive Officer).
32.2	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: November 12, 2010	By:	/s/ Thomas A. Smith Thomas A. Smith President and Chief Executive Officer
Date: November 12, 2010		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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