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 ~~June~~September 30, 2011
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 ý 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.

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Table of Contents

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED ~~JUNE~~SEPTEMBER 30, 2011

				Page No.

PART I—FINANCIAL INFORMATION
	Item 1.	Financial Statements		2
		Unaudited Condensed Balance Sheets as of ~~June~~September 30, 2011 and December 31, 2010		2
		Unaudited Condensed Statements of Revenues and Expenses For the Three and ~~Six~~Nine Months ended ~~June~~September 30, 2011 and 2010		4
		Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the ~~Three and Six~~Nine Months ended ~~June~~September 30, 2011 and 2010		5
		Unaudited Condensed Statements of Cash Flows For the ~~Six~~Nine Months ended ~~June~~September 30, 2011 and 2010		6
		Notes to Unaudited Condensed Financial Statements For the Three and ~~Six~~Nine Months ended ~~June~~September 30, 2011 and 2010		7
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		2021
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		32
	Item 4.	Controls and Procedures		3233
PART II—OTHER INFORMATION			��
	Item 1.	Legal Proceedings		3334
	Item 1A.	Risk Factors		3334
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		3334
	Item 3.	Defaults Upon Senior Securities		3334
	Item 4.	Reserved		3334
	Item 5.	Other Information		3334
	Item 6.	Exhibits		3435
SIGNATURES				3536

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Condensed Balance Sheets
~~June~~September 30, 2011 and December 31, 2010


			(dollars in thousands)							(dollars in thousands)
		2011			2010				2011			2010
			(Unaudited)							(Unaudited)
Assets	Assets							Assets
Electric plant:	Electric plant:							Electric plant:
	In service	$	7,294,325		$	6,672,253		In service	$	7,319,697		$	6,672,253
	Less: Accumulated provision for depreciation		(3,265,632	)		(3,101,731	)	Less: Accumulated provision for depreciation		(3,299,200	)		(3,101,731	)

			4,028,693			3,570,522				4,020,497			3,570,522
	Nuclear fuel, at amortized cost		273,254			249,563		Nuclear fuel, at amortized cost		275,626			249,563
	Construction work in progress		1,497,072			1,195,475		Construction work in progress		1,614,300			1,195,475

			5,799,019			5,015,560				5,910,423			5,015,560

Investments and funds:	Investments and funds:							Investments and funds:
	Decommissioning fund		278,235			265,483		Decommissioning fund		252,393			265,483
	Deposit on Rocky Mountain transactions		127,740			123,573		Deposit on Rocky Mountain transactions		129,894			123,573
	Investment in associated companies		57,019			56,125		Investment in associated companies		56,488			56,125
	Long-term investments		81,342			79,212		Long-term investments		77,221			79,212
	Other, at cost		3,508			3,570		Other, at cost		3,475			3,570

			547,844			527,963				519,471			527,963

Current assets:	Current assets:							Current assets:
	Cash and cash equivalents, at cost		417,946			672,212		Cash and cash equivalents, at cost		410,461			672,212
	Restricted cash, at cost		3,770			6,300		Restricted cash, at cost		613			6,300
	Restricted short-term investments		15,626			97,286		Restricted short-term investments		105,823			97,286
	Receivables		165,204			106,674		Receivables		141,143			106,674
	Inventories, at average cost		204,850			171,815		Inventories, at average cost		203,772			171,815
	Prepayments and other current assets		13,631			13,416		Prepayments and other current assets		10,872			13,416

			821,027			1,067,703				872,684			1,067,703

Deferred charges:	Deferred charges:							Deferred charges:
	Deferred debt expense, being amortized		62,492			59,202		Deferred debt expense, being amortized		64,627			59,202
	Regulatory assets		312,860			311,136		Regulatory assets		345,212			311,136
	Other		49,228			15,498		Other		42,492			15,498

			424,580			385,836				452,331			385,836

		$	7,592,470		$	6,997,062			$	7,754,909		$	6,997,062

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

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Oglethorpe Power Corporation
Condensed Balance Sheets
~~June~~September 30, 2011 and December 31, 2010


			(dollars in thousands)						(dollars in thousands)
		2011		2010				2011		2010
			(Unaudited)						(Unaudited)
Equity and Liabilities	Equity and Liabilities						Equity and Liabilities
Capitalization:	Capitalization:						Capitalization:
	Patronage capital and membership fees	$	624,780	$	595,952		Patronage capital and membership fees	$	635,188	$	595,952
	Accumulated other comprehensive margin (deficit)		123		(469	)	Accumulated other comprehensive margin (deficit)		864		(469	)

			624,903		595,483				636,052		595,483
	Long-term debt		5,244,443		4,657,127		Long-term debt		5,519,630		4,657,127
	Obligation under capital leases		161,661		179,288		Obligation under capital leases		159,199		179,288
	Obligation under Rocky Mountain transactions		127,740		123,573		Obligation under Rocky Mountain transactions		129,894		123,573

			6,158,747		5,555,471				6,444,775		5,555,471

Current liabilities:	Current liabilities:						Current liabilities:
	Long-term debt and capital leases due within one year		134,309		170,947		Long-term debt and capital leases due within one year		136,923		170,947
	Short-term borrowings		353,653		305,959		Short-term borrowings		275,757		305,959
	Accounts payable		189,949		139,614		Accounts payable		119,839		139,614
	Accrued interest		53,638		76,435		Accrued interest		45,935		76,435
	Accrued and withheld taxes		19,602		27,171		Accrued and withheld taxes		22,283		27,171
	Member power bill prepayments, current		40,620		71,496		Member power bill prepayments, current		50,097		71,496
	Other current liabilities		19,409		18,567		Other current liabilities		12,929		18,567

			811,180		810,189				663,763		810,189

Deferred credits and other liabilities:	Deferred credits and other liabilities:						Deferred credits and other liabilities:
	Gain on sale of plant, being amortized		27,350		28,587		Gain on sale of plant, being amortized		26,731		28,587
	Asset retirement obligations		289,736		280,496		Asset retirement obligations		294,298		280,496
	Member power bill prepayments, non-current		29,920		41,000		Member power bill prepayments, non-current		41,500		41,000
	Power sale agreement, being amortized		62,148		69,480		Power sale agreement, being amortized		58,482		69,480
	Regulatory liabilities		165,237		170,235		Regulatory liabilities		175,621		170,235
	Other		48,152		41,604		Other		49,739		41,604

			622,543		631,402				646,371		631,402

		$	7,592,470	$	6,997,062			$	7,754,909	$	6,997,062

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

Table of Contents

Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010


				(dollars in thousands)														(dollars in thousands)
			Three Months						Six Months								Three Months						Nine Months
			2011			2010			2011			2010					2011			2010			2011			2010
Operating revenues:	Operating revenues:														Operating revenues:
	Sales to Members		$	327,776		$	325,963		$	597,224		$	629,791		Sales to Members		$	349,906		$	370,602		$	947,130		$	1,000,393
	Sales to non-Members			52,027			147			52,353			392		Sales to non-Members			82,624			796			134,977			1,188

		Total operating revenues		379,803			326,110			649,577			630,183			Total operating revenues		432,530			371,398			1,082,107			1,001,581

Operating expenses:	Operating expenses:														Operating expenses:
	Fuel			161,355			121,459			233,804			223,551		Fuel			188,983			160,174			422,789			383,750
	Production			89,866			85,878			179,055			163,261		Production			90,101			82,717			269,154			245,953
	Depreciation and amortization			49,468			33,605			83,873			67,444		Depreciation and amortization			49,835			31,208			133,708			98,652
	Purchased power			13,600			18,217			25,155			35,625		Purchased power			20,925			24,721			46,080			60,346
	Accretion			4,565			4,282			9,125			8,566		Accretion			4,562			4,282			13,687			12,848
	Deferral of effect on net margin for Hawk Road and Murray Energy facilities			(2,753	)		2,900			(11,072	)		6,071		Deferral of effect on net margin for Hawk Road and Murray Energy facilities			13,240			4,382			2,168			10,453

		Total operating expenses		316,101			266,341			519,940			504,518			Total operating expenses		367,646			307,484			887,586			812,002

Operating margin	Operating margin			63,702			59,769			129,637			125,665		Operating margin			64,884			63,914			194,521			189,579

Other income:	Other income:														Other income:
	Investment income			6,926			7,497			14,320			15,153		Investment income			7,147			7,950			21,467			23,103
	Other			1,957			2,901			5,323			6,182		Other			1,651			3,231			6,974			9,413

		Total other income		8,883			10,398			19,643			21,335			Total other income		8,798			11,181			28,441			32,516

Interest charges:	Interest charges:														Interest charges:
	Interest expense			72,279			65,555			142,945			131,143		Interest expense			75,704			65,946			218,649			197,089
	Allowance for debt funds used during construction			(17,753	)		(8,676	)		(32,981	)		(18,137	)	Allowance for debt funds used during construction			(17,835	)		(10,474	)		(50,816	)		(28,611	)
	Amortization of debt discount and expense			5,341			5,888			10,488			11,990		Amortization of debt discount and expense			5,405			5,775			15,893			17,765

		Net interest charges		59,867			62,767			120,452			124,996			Net interest charges		63,274			61,247			183,726			186,243

Net margin	Net margin		$	12,718		$	7,400		$	28,828		$	22,004		Net margin		$	10,408		$	13,848		$	39,236		$	35,852

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

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Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010

		Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin (Deficit)			Total			Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin (Deficit)			Total

			(dollars in thousands)								(dollars in thousands)
Balance at December 31, 2009	Balance at December 31, 2009	$	562,219	$	(1,253	)	$	560,966	Balance at December 31, 2009	$	562,219	$	(1,253	)	$	560,966

Components of comprehensive margin:	Components of comprehensive margin:								Components of comprehensive margin:
	Net margin		22,004		—			22,004	Net margin		35,852		—			35,852
	Unrealized gain on available-for-sale securities		—		1,033			1,033	Unrealized gain on available-for-sale securities		—		1,085			1,085

Total comprehensive margin	Total comprehensive margin							23,037	Total comprehensive margin							36,937


Balance at June 30, 2010		$	584,223	$	(220	)	$	584,003
Balance at September 30, 2010									Balance at September 30, 2010	$	598,071	$	(168	)	$	597,903

Balance at December 31, 2010	Balance at December 31, 2010	$	595,952	$	(469	)	$	595,483	Balance at December 31, 2010	$	595,952	$	(469	)	$	595,483

Components of comprehensive margin:	Components of comprehensive margin:								Components of comprehensive margin:
	Net margin		28,828		—			28,828	Net margin		39,236		—			39,236
	Unrealized gain on available-for-sale securities		—		592			592	Unrealized gain on available-for-sale securities		—		1,333			1,333

Total comprehensive margin	Total comprehensive margin							29,420	Total comprehensive margin							40,569


Balance at June 30, 2011		$	624,780	$	123		$	624,903
Balance at September 30, 2011									Balance at September 30, 2011	$	635,188	$	864		$	636,052

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

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Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010


					(dollars in thousands)									(dollars in thousands)
				2011			2010						2011			2010
Cash flows from operating activities:	Cash flows from operating activities:									Cash flows from operating activities:
	Net margin			$	28,828		$	22,004		Net margin			$	39,236		$	35,852

Adjustments to reconcile net margin to net cash provided by (used in) operating activities:
Adjustments to reconcile net margin to net cash provided by operating activities:										Adjustments to reconcile net margin to net cash provided by operating activities:
		Depreciation and amortization, including nuclear fuel			144,131			123,717			Depreciation and amortization, including nuclear fuel			228,710			186,056
		Accretion cost			9,125			8,566			Accretion cost			13,687			12,848
		Amortization of deferred gains			(2,830	)		(2,830	)		Amortization of deferred gains			(4,245	)		(4,245	)
		Allowance for equity funds used during construction			(1,404	)		(994	)		Allowance for equity funds used during construction			(2,034	)		(1,707	)
		Deferred outage costs			(36,672	)		(25,080	)		Deferred outage costs			(43,827	)		(25,229	)
		Deferral of effect on net margin for Hawk Road and Murray Energy Facilities			(11,072	)		6,071			Deferral of effect on net margin for Hawk Road and Murray Energy Facilities			2,168			10,453
		Gain on sale of investments			(10,324	)		(9,015	)		Gain on sale of investments			(13,306	)		(12,013	)
		Regulatory deferral of costs associated with nuclear decommissioning			5,553			4,422			Regulatory deferral of costs associated with nuclear decommissioning			5,825			4,987
		Other			(3,622	)		(2,438	)		Other			(5,971	)		(4,216	)
	Change in operating assets and liabilities:									Change in operating assets and liabilities:
		Receivables			(54,078	)		(44,018	)		Receivables			(29,995	)		(25,622	)
		Inventories			1,171			15,153			Inventories			2,250			24,137
		Prepayments and other current assets			(215	)		(1,946	)		Prepayments and other current assets			2,544			(4,384	)
		Accounts payable			19,553			5,935			Accounts payable			10,407			(2,487	)
		Accrued interest			(22,796	)		(1,358	)		Accrued interest			(30,500	)		(13,498	)
		Accrued and withheld taxes			(7,920	)		(9,982	)		Accrued and withheld taxes			(5,197	)		(2,779	)
		Member power bill prepayments			(41,957	)		(90,357	)		Member power bill prepayments			(20,899	)		(115,831	)
		Other current liabilities			1,376			(5,197	)		Other current liabilities			(5,046	)		(2,782	)

			Total adjustments		(11,981	)		(29,351	)			Total adjustments		104,571			23,688

Net cash provided by (used in) operating activities					16,847			(7,347	)
Net cash provided by operating activities										Net cash provided by operating activities				143,807			59,540

Cash flows from investing activities:	Cash flows from investing activities:									Cash flows from investing activities:
		Property additions			(397,229	)		(335,145	)		Property additions			(634,955	)		(524,334	)
		Plant acquisition			(529,310	)		—			Plant acquisition			(530,293	)		—
		Activity in decommissioning fund—Purchases			(557,748	)		(299,446	)		Activity in decommissioning fund—Purchases			(828,008	)		(480,447	)
		—Proceeds			554,710			296,933			—Proceeds			823,598			476,630
		Decrease in restricted cash and cash equivalents			2,530			14,383			Decrease in restricted cash and cash equivalents			5,687			16,106
		Decrease (increase) in restricted short-term investments			81,660			(42,282	)		Increase in restricted short-term investments			(8,537	)		(181	)
		Activity in investment in associated organizations—Purchases			(4,371	)		(4,012	)		Activity in investment in associated organizations—Purchases			(4,634	)		(4,142	)
		—Proceeds			3,768			2,505			—Proceeds			4,556			3,196
		Activity in other long-term investments—Purchases			(824	)		(2,367	)		Activity in other long-term investments—Purchases			(1,246	)		(4,313	)
		—Proceeds			700			2,700			—Proceeds			1,100			3,100
		Other			(3,955	)		6,349			Other			(7,822	)		5,420

Net cash used in investing activities	Net cash used in investing activities				(850,069	)		(360,382	)	Net cash used in investing activities				(1,180,554	)		(508,965	)

Cash flows from financing activities:	Cash flows from financing activities:									Cash flows from financing activities:
		Long-term debt proceeds			793,999			222,631			Long-term debt proceeds			1,093,399			222,631
		Long-term debt payments			(260,981	)		(200,197	)		Long-term debt payments			(285,067	)		(222,265	)
		Increase in short-term borrowings, net			47,694			127,245			(Decrease) increase in short-term borrowings, net			(30,202	)		297,413
		Other			(1,756	)		1,930			Other			(3,134	)		5,373

Net cash provided by financing activities	Net cash provided by financing activities				578,956			151,609		Net cash provided by financing activities				774,996			303,152

Net decrease in cash and cash equivalents	Net decrease in cash and cash equivalents				(254,266	)		(216,120	)	Net decrease in cash and cash equivalents				(261,751	)		(146,273	)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period				672,212			579,069		Cash and cash equivalents at beginning of period				672,212			579,069

Cash and cash equivalents at end of period	Cash and cash equivalents at end of period			$	417,946		$	362,949		Cash and cash equivalents at end of period			$	410,461		$	432,796

Supplemental cash flow information:	Supplemental cash flow information:									Supplemental cash flow information:
Cash paid for—	Cash paid for—									Cash paid for—
		Interest (net of amounts capitalized)		$	126,758		$	108,629			Interest (net of amounts capitalized)		$	189,258		$	173,307
Supplemental disclosure of non-cash investing and financing activities:	Supplemental disclosure of non-cash investing and financing activities:									Supplemental disclosure of non-cash investing and financing activities:
		Change in plant expenditures included in accounts payable		$	30,335		$	73,221			Change in plant expenditures included in accounts payable		$	(27,810	)	$	95,797

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

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Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three and ~~Six~~Nine Months ended ~~June~~September 30, 2011 and 2010

(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 ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010. 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. Certain prior year amounts have been reclassified to conform with the current year presentation. 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, 2010, as filed with the SEC. The results of operations for the three- and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 are not necessarily indicative of results to be expected for the full year. As noted in our 2010 Form 10-K, our revenues consist primarily of sales to our 39 electric distribution cooperative members and, thus, the receivables on the condensed balance sheets are principally from our members. (See "Notes to Financial Statements" in our 2010 Form 10-K.)
(B): Fair Value Measurement. 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 measurement 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 without adjustment 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.

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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 ~~June~~September 30, 2011 and December 31, 2010.


					Fair Value Measurements at Reporting Date Using												Fair Value Measurements at Reporting Date Using
			June 30, 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)				September 30, 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)

			(dollars in thousands)												(dollars in thousands)
Decommissioning funds:	Decommissioning funds:												Decommissioning funds:
	Domestic equity	$	109,215		$	109,215	$	—		$	—		Domestic equity	$	90,014		$	90,014	$	—		$	—
	International equity		49,300			49,300		—			—		International equity		38,186			38,186		—			—
	Corporate bonds		43,139			43,139		—			—		Corporate bonds		45,827			45,827		—			—
	US Treasury and government agency securities		31,983			31,983		—			—		US Treasury and government agency securities		38,581			38,581		—			—
	Agency mortgage and asset backed securities		36,178			36,178		—			—		Agency mortgage and asset backed securities		23,059			23,059		—			—
	Derivative instruments		(505	)		—		—			(505	)	Derivative instruments		(1,032	)		—		—			(1,032	)
	Other		8,925			8,925		—			—		Other		17,757			17,757		—			—
Bond, reserve and construction funds	Bond, reserve and construction funds		2,753			2,753		—			—		Bond, reserve and construction funds		2,720			2,720		—			—
Long-term investments	Long-term investments		81,342			73,294		—			8,048	⁽¹⁾	Long-term investments		77,221			69,523		—			7,698	⁽¹⁾
Natural gas swaps	Natural gas swaps		(2,152	)		—		(2,152	)		—		Natural gas swaps		(2,173	)		—		(2,173	)		—

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					Fair Value Measurements at Reporting Date Using												Fair Value Measurements at Reporting Date Using
			December 31, 2010			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)				December 31, 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)												(dollars in thousands)
Decommissioning funds:	Decommissioning funds:												Decommissioning funds:
	Domestic equity	$	105,523		$	105,523	$	—		$	—		Domestic equity	$	105,523		$	105,523	$	—		$	—
	International equity		43,619			43,619		—			—		International equity		43,619			43,619		—			—
	Corporate bonds		53,847			53,847		—			—		Corporate bonds		53,847			53,847		—			—
	US Treasury and government agency securities		47,649			47,649		—			—		US Treasury and government agency securities		47,649			47,649		—			—
	Agency mortgage and asset backed securities		7,926			7,926		—			—		Agency mortgage and asset backed securities		7,926			7,926		—			—
	Derivative instruments		(452	)		—		—			(452	)	Derivative instruments		(452	)		—		—			(452	)
	Other		7,371			7,371		—			—		Other		7,371			7,371		—			—
Bond, reserve and construction funds	Bond, reserve and construction funds		2,815			2,815		—			—		Bond, reserve and construction funds		2,815			2,815		—			—
Long-term investments	Long-term investments		79,212			70,541		—			8,671	⁽¹⁾	Long-term investments		79,212			70,541		—			8,671	⁽¹⁾
Natural gas swaps	Natural gas swaps		(2,054	)		—		(2,054	)		—		Natural gas swaps		(2,054	)		—		(2,054	)		—

⁽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 ~~six~~nine months ended ~~June~~September 30, 2011 and 2010.


										Three Months Ended September 30, 2011
		Three Months Ended June 30, 2011
			Decommissioning funds			Long-term investments				Decommissioning funds			Long-term investments

			(dollars in thousands)							(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):							Assets (Liabilities):
Balance at March 31, 2011		$	(548	)	$	8,408
Balance at June 30, 2011								Balance at June 30, 2011	$	(505	)	$	8,048
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):							Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		43			40		Included in earnings (or changes in net assets)		(527	)		—
	Impairment included in other comprehensive deficit		—			—		Impairment included in other comprehensive deficit		—			50
Liquidations	Liquidations		—			(400	)	Liquidations		—			(400	)

Balance at June 30, 2011		$	(505	)	$	8,048
Balance at September 30, 2011								Balance at September 30, 2011	$	(1,032	)	$	7,698

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										Three Months Ended September 30, 2010
		Three Months Ended June 30, 2010
			Decommissioning funds			Long-term investments				Decommissioning funds			Long-term investments

			(dollars in thousands)							(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):							Assets (Liabilities):
Balance at March 31, 2010		$	(435	)	$	26,376
Balance at June 30, 2010								Balance at June 30, 2010	$	(311	)	$	24,485
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):							Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		124			—		Included in earnings (or changes in net assets)		(212	)		—
	Impairment included in other comprehensive deficit		—			109		Impairment included in other comprehensive deficit		—			9
Liquidations	Liquidations		—			(2,000	)	Liquidations		—			(400	)

Balance at June 30, 2010		$	(311	)	$	24,485
Balance at September 30, 2010								Balance at September 30, 2010	$	(523	)	$	24,094


										Nine Months Ended September 30, 2011
		Six Months Ended June 30, 2011
			Decommissioning funds			Long-term investments				Decommissioning funds			Long-term investments

			(dollars in thousands)							(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):							Assets (Liabilities):
Balance at January 1, 2011		$	(452	)	$	8,671
Balance at December 31, 2010								Balance at December 31, 2010	$	(452	)	$	8,671
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):							Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(53	)		77		Included in earnings (or changes in net assets)		(580	)		—
	Impairment included in other comprehensive deficit		—			—		Impairment included in other comprehensive deficit		—			127
Liquidations	Liquidations		—			(700	)	Liquidations		—			(1,100	)

Balance at June 30, 2011		$	(505	)	$	8,048
Balance at September 30, 2011								Balance at September 30, 2011	$	(1,032	)	$	7,698


										Nine Months Ended September 30, 2010
		Six Months Ended June 30, 2010
			Decommissioning funds			Long-term investments				Decommissioning funds			Long-term investments

			(dollars in thousands)							(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):							Assets (Liabilities):
Balance at January 1, 2010		$	(260	)	$	27,010
Balance at December 31, 2009								Balance at December 31, 2009	$	(260	)	$	27,010
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):							Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(51	)		—		Included in earnings (or changes in net assets)		(263	)		—
	Impairment included in other comprehensive deficit		—			175		Impairment included in other comprehensive deficit		—			184
Liquidations	Liquidations		—			(2,700	)	Liquidations		—			(3,100	)

Balance at June 30, 2010		$	(311	)	$	24,485
Balance at September 30, 2010								Balance at September 30, 2010	$	(523	)	$	24,094

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 interest rates, which was adjusted for illiquidity premiums based on discussions with market participants. At ~~June~~September 30, 2011, we held auction rate securities with maturity dates ranging from November 1, 2044 to December 1, 2045.

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At December 31, 2010, we had a temporary impairment on our auction rate securities of $1,029,000. Based on the fair value of the auction rate securities held at ~~June~~September 30, 2011, we recorded a ($~~77,000)~~127,000) incremental adjustment to the temporary impairment. The temporary impairment is reflected in "Accumulated other comprehensive margin (deficit)" on the condensed balance sheet. The various assumptions we utilized 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 ~~June~~September 30, 2011, would have resulted in an additional decrease in the fair value of our auction rate securities investments by approximately ~~$540,000.~~$509,000.

As of ~~June~~September 30, 2011, these investments were rated A3 by Moody's Investors Service and AAA by Fitch. Therefore, it is expected that the investments will not be settled at a price less than par value. Because we do not intend to sell these securities unless we can recover our cost basis in a relatively short period of time, and it is not more likely than not that we will be required to sell the securities, we considered the investments to be temporarily impaired at ~~June~~September 30, 2011.

(C): Disclosures about Derivative Instruments and Hedging Activities. Our 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, 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 ~~June~~September 30, 2011, the estimated fair value of our natural gas contracts was an unrealized loss of approximately ~~$2,152,000.~~$2,173,000. 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 in our natural gas hedging portfolio.

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 a financial loss. However, as of ~~June~~September 30, 2011, all of the counterparties with transaction amounts outstanding in our hedging portfolio are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

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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. As of ~~June~~September 30, 2011, 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 ~~June~~September 30, 2011 due to our credit rating being downgraded below investment grade, we could have been required to post collateral or credit support totaling up to ~~$2,152,000~~$2,173,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of ~~June~~September 30, 2011 that is expected to settle or mature each year:



Year	Natural Gas Swaps (MMBTUs) (in millions)	Natural Gas Swaps (MMBTUs) (in millions)

2011	3.30	0.57
2012	1.88	2.60
2013	0.19	0.54

Total	5.37	3.71

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The table below reflects the fair value of derivative instruments and their effect on our unaudited condensed balance sheet ~~for the period ended June~~as of September 30, 2011.


							Balance Sheet Location		Fair Value
		Balance Sheet Location	Fair Value
				(dollars in thousands)					(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities:	Designated as hedges under authoritative guidance related to derivatives and hedging activities:					Designated as hedges under authoritative guidance related to derivatives and hedging activities:
Assets	Assets					Assets
	Natural Gas Swaps	Receivables	$	2,293		Natural Gas Swaps	Receivables	$	2,173
	Natural Gas Swaps	Receivables		(141	)

Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities	Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities		$	2,152		Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities		$	2,173

Liabilities	Liabilities					Liabilities
	Natural Gas Swaps	Other current liabilities	$	2,293
	Natural Gas Swaps	Other current liabilities		(141	)	Natural Gas Swaps	Other current liabilities	$	2,173

Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities	Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities		$	2,152		Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities		$	2,173

Not designated as hedges under authoritative guidance related to derivatives and hedging activities:	Not designated as hedges under authoritative guidance related to derivatives and hedging activities:					Not designated as hedges under authoritative guidance related to derivatives and hedging activities:
Assets	Assets					Assets
	Nuclear decommissioning trust	Decommissioning fund	$	657		Nuclear decommissioning trust	Decommissioning fund	$	911
	Nuclear decommissioning trust	Decommissioning fund		(1,162	)	Nuclear decommissioning trust	Decommissioning fund		(1,943	)
	Nuclear decommissioning trust	Deferred asset associated with retirement obligations		381		Nuclear decommissioning trust	Deferred asset associated with retirement obligations		985
	Nuclear decommissioning trust	Deferred asset associated with retirement obligations		(452	)	Nuclear decommissioning trust	Deferred asset associated with retirement obligations		(1,456	)

Total not designated as hedges under authoritative guidance related to derivatives and hedging activities	Total not designated as hedges under authoritative guidance related to derivatives and hedging activities		$	(576	)	Total not designated as hedges under authoritative guidance related to derivatives and hedging activities		$	(1,503	)

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The following table presents the gains and (losses) on derivative instruments recognized in ~~margins~~net margin for the three and ~~six~~nine months ended ~~June~~September 30, 2011.

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

Statement of
Revenues and
Expenses Location

Three months
ended

Nine months
ended

Statement of
Revenues and
Expenses Location

Three months
ended

Six months
ended

(dollars in thousands)

Designated as hedges under authoritative guidance related to derivatives and hedging activities

Natural Gas Swaps

Purchase power

Natural Gas Swaps

Purchase power

195

Natural Gas Swaps

Purchase power

(972

)

(1,255

)

Natural Gas Swaps

Purchase power

(2,169

)

(3,424

)

Not designated as hedges under authoritative guidance related to derivatives and hedging activities

Nuclear decommissioning trust

Investment income

830

1,070

Nuclear decommissioning trust

Investment income

927

1,997

Nuclear decommissioning trust

Investment income

(322

)

(572

)

Nuclear decommissioning trust

Investment income

(661

)

(1,233

)

Total losses on derivatives

(390

)

(661

)

Total losses on derivatives

(1,804

)

(2,465

)

(D): Investments in Debt and Equity Securities. Under the accounting guidance for 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. We owned no held-to-maturity securities as of ~~June~~September 30, 2011 and December 31, 2010. All realized and unrealized gains and losses were determined using the specific identification method. Approximately ~~60%~~84% of these gross unrealized losses were in effect for less than one year. These losses were primarily due to investments in ~~fixed income~~equity 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 associated regulatory asset.

For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of ~~June~~September 30, 2011 and December 31, 2010:


		(dollars in thousands)									(dollars in thousands)
			Gross Unrealized									Gross Unrealized
June 30, 2011	Cost		Gains		Losses			Fair Value
September 30, 2011										Cost		Gains		Losses			Fair Value

Equity	$	147,061	$	43,976	$	(2,648	)	$	188,389	$	147,602	$	20,430	$	(14,928	)	$	153,104
Debt		161,122		9,040		(4,627	)		165,535		156,235		10,779		(4,508	)		162,506
Other		8,476		382		(452	)		8,406		17,164		1,080		(1,520	)		16,724

Total	$	316,659	$	53,398	$	(7,727	)	$	362,330	$	321,001	$	32,289	$	(20,956	)	$	332,334

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			Gross Unrealized
December 31, 2010		Cost		Gains		Losses			Fair Value

Equity	$	137,492	$	42,622	$	(2,482	)	$	177,632
Debt		158,706		9,130		(4,879	)		162,957
Other		7,035		3		(118	)		6,920

Total	$	303,233	$	51,755	$	(7,479	)	$	347,509

(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. Effective March 31, 2011, the standard requires a reporting entity to present separately information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than a net basis) in the reconciliation for fair value measurements using significant unobservable inputs (Level 3). Our adoption of the standard did not have a material effect on our disclosures.

In April 2011, the FASB issued Fair Value Measurements: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments clarify the FASB's intent about the application of existing fair value measurement and disclosure requirements and include those that change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. The standard is effective for our fiscal ~~years~~year ending December 31, 2011. The adoption of the standard is not expected to have any impact on our results of operations, cash flows or financial condition.

In May 2011, the FASB issued Comprehensive Income: Presentation of Comprehensive Income. The standard requires that an entity present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of other comprehensive income along with a total for other comprehensive income, and a total amount for comprehensive income. The standard is effective for our fiscal ~~years~~year ending December 31, ~~2011.~~2012. Our adoption of the standard will not have a material effect on our disclosures.

In August 2011, the FASB issued Intangibles, Goodwill and Other: Testing Goodwill for Impairment. The amendments provide that an entity has the option to first assess qualitative factors to determine whether the existence of events or circumstances lead to a determination that is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after assessing events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, performing the two-step goodwill impairment test is unnecessary. If an entity concludes otherwise, the entity is required to perform the first step of the two-step goodwill impairment test by calculating the fair value of the reporting unit and comparing it with the carrying amount of the reporting unit. If the carrying amount exceeds the fair value, the second step of the goodwill impairment test to measure the amount of the loss is required. The standard is effective for our fiscal year ending December 31, 2011. We do not expect this standard to have an impact on our financial statements.

(F): Accumulated Comprehensive Margin (Deficit). The table below provides detail of the beginning and ending balance for each classification of accumulated other comprehensive margin (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

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Accumulated Other Comprehensive Margin (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 2010 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 Margin (Deficit) Three Months Ended						Accumulated Other Comprehensive Margin (Deficit) Three Months Ended

		(dollars in thousands)						(dollars in thousands)
		Available-for-sale Securities			Total			Available-for-sale Securities			Total

Balance at March 31, 2010	$	(1,004	)	$	(1,004	)
Balance at June 30, 2010							$	(220	)	$	(220	)

Unrealized gain		784			784			52			52

Balance at June 30, 2010	$	(220	)	$	(220	)
Balance at September 30, 2010							$	(168	)	$	(168	)

Balance at March 31, 2011	$	(490	)	$	(490	)
Balance at June 30, 2011							$	123		$	123

Unrealized gain		613			613			741			741

Balance at June 30, 2011	$	123		$	123
Balance at September 30, 2011							$	864		$	864

	Accumulated Other Comprehensive Margin (Deficit) Six Months Ended						Accumulated Other Comprehensive Margin (Deficit) Nine Months Ended

		(dollars in thousands)						(dollars in thousands)
		Available-for-sale Securities			Total			Available-for-sale Securities			Total

Balance at December 31, 2009	$	(1,253	)	$	(1,253	)	$	(1,253	)	$	(1,253	)

Unrealized gain		1,033			1,033			1,085			1,085

Balance at June 30, 2010	$	(220	)	$	(220	)
Balance at September 30, 2010							$	(168	)	$	(168	)

Balance at December 31, 2010	$	(469	)	$	(469	)	$	(469	)	$	(469	)

Unrealized gain		592			592			1,333			1,333

Balance at June 30, 2011	$	123		$	123
Balance at September 30, 2011							$	864		$	864

(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.

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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. Beginning in 2011, we have become

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subject to climate change regulations that impose restrictions on emissions of greenhouse gases (including carbon dioxide), through the Prevention of Significant Deterioration preconstruction permitting program. As a result, we will have to evaluate any major modifications that we plan to undertake at our plants to determine whether they will need to undergo new source review permitting for greenhouse gases, and, if they do, whether any control technology will need to be added. 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. See "Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity Sources of Capital—Environmental Regulations" in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 and "Item 1—BUSINESS—ENVIRONMENTAL AND OTHER REGULATION" in our 2010 Form 10-K for a more detailed discussion of current and potential future regulation. 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 and credit agreements 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 and credit agreements. 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 June 30, 2011 of $3,770,000 primarily consisted of clean renewable energy bond proceeds on deposit with CoBank, N.A. to fund a clean renewable energy project at the Rocky Mountain Pumped Storage Hydroelectric facility.
~~(I)~~: Restricted Short-term Investments. At ~~June~~September 30, 2011, we had ~~$15,626,000~~$105,823,000 on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities ~~Service/~~Service Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.
~~(J)~~(I): Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the accompanying condensed balance sheets as of ~~June~~September 30, 2011 and December 31, 2010.

2011
2010

(dollars in thousands)

Premium and loss on reacquired debt $ 105,052 $ 111,570
Deferred amortization on capital leases 55,555 64,561
Deferred outage costs 42,441 23,796
Deferred interest rate swap termination fees 23,310 25,306
Asset retirement obligations 9,803 15,699
Deferred depreciation expense 51,921 52,632
Deferred investment impairment losses 4,692 5,214
Deferred charges related to Plant Vogtle Units 3 and 4 training costs 13,460 9,707
Deferral of effects on net margin—Murray Energy Facility 4,014 —
Other regulatory assets 2,612 2,651
Accumulated retirement costs for other obligations (37,546 ) (39,205 )
Net benefit of Rocky Mountain transactions (49,373 ) (50,965 )
Deferral of effects on net margin—Hawk Road Energy Facility (14,898 ) (21,956 )
Major maintenance sinking fund (29,009 ) (28,500 )
Deferred debt service adder (32,639 ) (27,678 )
Other regulatory liabilities (1,772 ) (1,931 )

Net regulatory assets $ 147,623 $ 140,901


				2011		2010
				(dollars in thousands)

Regulatory Assets:
	Premium and loss on reacquired debt		$	101,661	$	111,570
	Deferred amortization on capital leases			51,001		64,561
	Deferred outage costs			39,978		23,796
	Deferred interest rate swap termination fees			22,313		25,306
	Asset retirement obligations			43,939		15,699
	Deferred depreciation expense			51,565		52,632
	Deferred investment impairment losses			4,432		5,214
	Deferred charges related to Plant Vogtle Units 3 and 4 training costs			15,441		9,707
	Other regulatory assets			14,882		2,651

		Total Regulatory Assets	$	345,212	$	311,136
Regulatory Liabilities:
	Accumulated retirement costs for other obligations		$	36,834	$	39,205
	Net benefit of Rocky Mountain transactions			48,578		50,965
	Deferral of effects on net margin—Hawk Road and Murray Energy facilities			24,123		21,956
	Major maintenance sinking fund			29,283		28,500
	Deferred debt service adder			35,113		27,678
	Other regulatory liabilities			1,690		1,931

		Total Regulatory Liabilities	$	175,621	$	170,235
Net regulatory assets			$	169,591	$	140,901

The deferral of effects on net margins for the Murray and Hawk Road energy facilities presented in the table above represent the net of revenues and expenses associated with owning and operating the assets until our members require the power in 2016. The amounts will be deferred until 2016, at which time the amounts will be amortized over the remaining life of the plants. For information regarding the deferral of net margins for Murray, see Note L.

~~(K)~~(J): Member Power Bill Prepayments. We have 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 against the power bills and are recorded as a reduction to member revenues. At ~~June~~September 30, 2011, member power bill prepayments as reflected on the unaudited condensed balance sheet, including unpaid discounts, were ~~$70,540,000,~~$91,597,000, of which, ~~$40,620,000~~$50,097,000 is classified as a current liability and ~~$29,920,000~~$41,500,000 as deferred credits and other liabilities. The prepayments are being applied against members' power bills through ~~May 2015,~~November 2017, with the majority of the remaining balance scheduled to be applied by the end of 2012.
~~(L)~~(K): Debt. In March 2011, the Development Authority of Appling County (Georgia), the Development Authority of Burke County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $180,380,000 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. The Series 2011 bonds are

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term rate bonds with a 2.5% interest rate which is fixed through February 28, 2013. $168,700,000 in proceeds of the 2011 bonds were used to refund a like amount of Series 2007 and 2008 pollution control revenue bonds that were subject to remarketing and interest rate reset on April 1, 2011. In conjunction with this refunding, we provided notice of optional redemption of the prior bonds in March 2011 and redeemed the bonds on April 1, 2011. The remaining proceeds of the 2011 bond issue were used to refund $11,680,000 of commercial paper that was used to refund a like amount of pollution control revenue bonds that matured on January 1, 2011.

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On April 6, 2011, we closed a $260,000,000 three-year term loan with three banks to provide a portion of the interim financing for the Murray acquisition on April 8, 2011. The ~~initial~~current interest rate on the ~~term~~ loan is ~~set at a 1.25% spread to the 6-month LIBOR (1.69%) with interest payments due in July~~1.50% and ~~October 2011.~~is based on one-month LIBOR. The term loan is set to mature in April 2014. For a discussion of the Murray acquisition, see Note M.L.

On August 19, 2011, we issued $300,000,000 of 5.25% First Mortgage Bonds, Series 2011 A primarily for the purpose of repaying outstanding commercial paper issued in connection with funding a portion of the cost of constructing Vogtle Units No. 3 and No. 4. The first mortgage bonds are secured under our first mortgage indenture.

As of ~~June~~September 30, 2011, we received advances on Rural Utilities ~~Service-guaranteed~~ Service-guaranteed/Federal Financing Bank loans totaling ~~$353,571,000~~$353,619,000 to permanently finance the Hartwell and Hawk Road acquisitions and for general improvements at existing plants.

~~(M)~~(L): Plant Acquisition. On April 8, 2011, we acquired 100% of KGen Murray I and II LLC, a wholly owned subsidiary of KGen Power Corporation. KGen Murray I and II LLC, subsequently renamed Murray I and II, LLC, owns the Murray Energy Facility, located near Dalton, Georgia. This facility consists of two natural gas-fired combined cycle units that have an aggregate summer planning reserve generation capacity of approximately 1,250 megawatts. As part of the acquisition, we assumed an existing power purchase and sale agreement with Georgia Power Company for the entire output of Murray Unit No. 1 through May 31, 2012. Our members currently plan to take the output of Murray on or before January 2016. Prior to our members' use of Murray, energy may be sold into the wholesale market.

We accounted for the transaction as a purchase business combination. In connection with the acquisition, which included acquisition related costs of approximately $1,962,000 (consisting primarily of legal and professional services which ~~are~~was recorded in the ~~accompanying~~ statement of revenues and expenses for the quarter ended June 30, 2011), we funded the entire ~~$531,272,000~~$532,255,000 cash outlay by closing a $260,000,000 three-year term loan and by financing the remaining ~~$271,272,000~~$272,255,000 through the issuance of commercial paper and draws under existing credit facilities.

The cash outlay of $532,255,000 includes a net working capital adjustment of $982,919 which was recorded in July 2011.

The following amounts represent the ~~preliminary estimates of~~ identifiable assets acquired and liabilities assumed in the Murray acquisition:

Recognized fair value amounts of identifiable assets acquired and liabilities assumed:	(in millions)			(in millions)



Property, plant and equipment	$	456.7		$	456.7
Inventory		34.0			34.0
Other current assets		4.5			4.6
Power purchase and sale agreement		40.4			40.4
Emission Credits		0.2
Emission credits					0.2
Current liabilities		(6.5	)		(5.6	)

Total identifiable net assets	$	529.3		$	530.3

There was no goodwill associated with this acquisition.

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We have consolidated the financial position and results of operations of Murray as of April 8, 2011. Our revenues for the ~~quarter~~three-month and nine-month periods ended ~~June~~September 30, 2011 include ~~$51,921,000~~$82,573,000 and $134,494,000, respectively, related to capacity and energy sales from Murray. Prior to our members taking the output from Murray, the effect on net ~~results of operations~~margins from Murray, including related interest costs, are being deferred as a regulatory ~~asset. This~~asset or liability. The regulatory asset or liability will be amortized over the remaining life of the plant (estimated to be 30 years) beginning January 2016. For the ~~quarter~~three-month and nine-month periods ended ~~June~~September 30, 2011, we deferred ~~$4,014,000~~$13,494,000 and $9,479,000, respectively, in excess ~~costs~~revenues from Murray.

~~(N)~~(M): Sales to Non-Members. For the ~~six-months~~three-month and nine-month periods ended ~~June~~September 30, 2011, we had ~~$52,353,000~~$82,624,000 and $134,977,000, respectively, of sales to non-members consisting primarily of capacity and energy sales to Georgia Power under an agreement to sell the entire output of the recently acquired Murray Unit No. 1 through May 31, 2012. In addition, ~~sales to non-members were derived from sales of~~we sold energy generated at Murray Unit No. 2.2 to non-members.

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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 "Item1A—RISK FACTORS" in our 2010 Form 10-K. 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 ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010

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 our 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 expansion, our board approved budgets for 2010 and 2011 to achieve a 1.14 margins for interest ratio. As our generation expansion program evolves, our board 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-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 was ~~$12.7~~$10.4 million and ~~$28.8~~$39.2 million compared to ~~$7.4~~$13.8 million and ~~$22.0~~$35.9 million for the same periods of 2010. ~~We expect a~~Through September 30, 2011, we collected 103.7% of our targeted net margin of ~~$38.0~~$37.8 million for the year ending December 31, ~~2011, which~~2011. 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 purchased resources or member-owned resources over which we have dispatch rights, and members'

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decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

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Sales to Members. Total revenues from sales to members ~~increased 0.6%~~decreased 5.6% and ~~decreased 5.2%~~5.3% in the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. Megawatt-hour sales to members decreased ~~6.9%~~8.6% and ~~13.7%~~11.7% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 versus the same periods of 2010. The average total revenue per megawatt-hour from sales to members increased ~~8.1%~~3.4% and ~~9.9%~~7.3% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010.

The components of member revenues for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 and 2010 were as follows (amounts in thousands except for cents per kilowatt-hour):



										Three Months Ended September 30,				Nine Months Ended September 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010		2011		2010		2011		2010
Capacity revenues	$	171,478	$	171,443	$	343,479	$	342,218	$	171,582	$	172,217	$	515,061	$	514,435
Energy revenues		156,298		154,520		253,745		287,573		178,324		198,385		432,069		485,958

Total	$	327,776	$	325,963	$	597,224	$	629,791	$	349,906	$	370,602	$	947,130	$	1,000,393

Kilowatt-hours sold to members		5,341,362		5,735,490		9,324,218		10,801,711		6,077,054		6,649,453		15,401,272		17,451,164
Cents per kilowatt-hour		6.14¢		5.68¢		6.41¢		5.83¢		5.76¢		5.57¢		6.15¢		5.73¢

Energy revenues were ~~1.2% higher~~10.1% and ~~11.8%~~11.1% lower for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. Our average energy revenue per megawatt-hour from sales to members were ~~8.6%~~1.6% lower and ~~2.2%~~0.7% higher for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 as compared to the same periods of 2010. The ~~changes~~decrease in energy revenues resulted primarily from ~~the pass-through~~lower megawatt-hour sales to our members primarily as a result of ~~fuel costs associated with higher gas-fired generation during the second quarter of 2011 as compared to the same quarter of 2010 and from substantially lower coal-fired generation due to~~ a ~~scheduled~~planned outage at Plant Scherer ~~for the six-month period ended June 30,~~and an unplanned outage at Chattahoochee which resulted in lower generation from these plants in 2011 as compared to ~~the same period of~~ 2010. For a discussion of fuel costs and total generation, see "—Operating Expenses."

Sales to Non-Members. Sales to non-members for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 consisted primarily of capacity and energy sales to Georgia Power Company under an agreement to sell the entire output of the recently acquired Murray Unit No. 1 through May 31, 2012. In addition, ~~sales to non-members were derived from sales of~~we sold energy generated at Murray Unit No. 2.2 to non-members. See Note ML of Notes to Unaudited Condensed Financial Statements for further discussion of our acquisition of Murray.

Operating Expenses

Operating expenses for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 increased ~~18.7%~~19.6% and ~~3.1%~~9.3% compared to the same periods of 2010. ~~This~~The increase in operating expenses was primarily due to higher fuel, production and depreciation and amortization costs offset somewhat by lower purchased power costs.

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The following table summarizes our megawatt-hour generation and fuel costs by generating source and purchased power costs.



										Three Months Ended September 30,

	Three Months Ended June 30,									2011				2010
	2011				2010
Fuel Source	Cost		Generation		Cost		Generation		Cost		Generation		Cost		Generation
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)
Coal	$	72,342		2,315,372	$	76,486		2,719,658	$	73,377		2,488,052	$	81,437		2,835,756
Nuclear		18,373		2,308,955		16,860		2,505,589		19,869		2,486,884		18,092		2,669,806
Gas		70,037		1,732,957		27,853		604,876		94,599		2,332,508		60,158		1,305,749
Pumped Storage		603		246,712		286		265,768		1,138		346,849		487		346,313

	$	161,355		6,603,996	$	121,485		6,095,891	$	188,983		7,654,293	$	160,174		7,157,624

	Cost		Purchased		Cost		Purchased		Cost		Purchased		Cost		Purchased
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)
Purchased Power	$	13,600		39,471	$	18,217		103,505	$	20,925		196,147	$	24,721		64,711


										Nine Months Ended September 30,

	Six Months Ended June 30,									2011				2010
	2011				2010
Fuel Source	Cost		Generation		Cost		Generation		Cost		Generation		Cost		Generation
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)
Coal	$	122,906		3,997,491	$	145,081		5,281,305	$	196,283		6,485,543	$	226,518		8,117,061
Nuclear		34,516		4,705,954		29,809		4,689,037		54,385		7,192,838		47,901		7,358,843
Gas		75,128		1,755,868		47,819		966,234		169,727		4,088,376		107,977		2,271,983
Pumped Storage		1,256		429,864		867		420,993		2,394		776,713		1,354		767,306

	$	233,806		10,889,177	$	223,576		11,357,569	$	422,789		18,543,470	$	383,750		18,515,193

	Cost		Purchased		Cost		Purchased		Cost		Purchased		Cost		Purchased
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)
Purchased Power	$	25,155		60,678	$	35,625		226,628	$	46,080		256,825	$	60,346		291,339

For the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011, total fuel costs increased ~~32.8%~~18.0% and ~~4.6%~~10.2% and total megawatt-hour generation increased ~~8.3%~~6.9% and ~~decreased 4.1%~~0.2% compared to the same periods of 2010. Average fuel costs per megawatt-hour increased ~~22.6%~~10.3% and ~~9.1%~~10.0% in the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. The increase in total fuel costs ~~(as well the increase in~~and generation ~~for the current quarter)~~ resulted primarily from increased natural gas-fired generation of ~~186.5% or 1,128,000~~1,027,000 megawatt-hours and ~~81.7% or 790,000~~1,816,000 megawatt-hours for the three-months and ~~six-months~~nine-months ended ~~June~~September 30, 2011 as compared to the same periods of 2010 primarily due to generation from Murray ~~(which~~which was ~~utilized for sales~~sold to ~~non-members). In addition, generation from Chattahoochee (which~~non-members. This increase was ~~placed back into operation in April 2011 after completion of an unplanned outage) contributed to the increased generation during the current quarter. These increases were~~ offset somewhat by a decrease in generation for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010 of ~~17.2% or 319,000~~348,000 megawatt-hours and ~~30.8% or 1,176,000~~1,632,000 megawatt-hours in coal-fired generation primarily ~~at Plant Scherer~~ due to a scheduled outage at Plant Scherer for the installation of environmental compliance equipment and general maintenance in ~~2011.The~~2011. The average fuel cost per megawatt-hour of gas-fired generation is substantially higher than nuclear generation and is also higher than coal generation; thus, the increase

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

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Total production costs increased ~~4.6%~~8.9% and ~~9.7%~~9.4% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. The increase in production costs for the ~~current~~ quarter ended ~~June~~September 30, 2011 compared to the same period of 2010 was ~~primarily~~partly due to operation and maintenance expenses incurred at ~~Murray.~~Murray and partly due to costs incurred to repair a damaged transformer at the Hawk Road Energy Facility. For the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 compared to the same period of 2010 the increase resulted from, in addition to Murray, a planned major maintenance outage at Hawk Road and increased general operations and maintenance expenses at Plants Vogtle, Hatch, Scherer and ~~Scherer. These increases were~~Wansley. The increase for the nine months ended September 30, 2011 as compared to the same period of 2010 was offset somewhat by lower operations and maintenance costs at ~~Hartwell;~~the Hartwell Energy Facility; 2010 operations and maintenance costs for Hartwell ~~were higher due to~~included major maintenance outage ~~costs incurred for a hot gas path inspection.~~costs.

Depreciation and amortization costs increased ~~47.2%~~59.7% and ~~24.4%~~35.5% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. This increase resulted primarily from depreciation of Murray, in addition to higher depreciation for Plants Scherer and Wansley related to environmental compliance projects recently placed in service.

Total purchased power costs decreased ~~25.3%~~15.4% and ~~29.4%~~23.6% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. Purchased megawatt-hours increased 203.1% and decreased ~~61.9% and 73.2%~~11.8% for the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. The ~~decrease~~increase in purchased ~~power costs~~megawatt-hours for the third quarter of 2011 as compared to the same quarter of 2010 resulted from ~~a decrease~~an increase in megawatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with energy purchased at lower prices in the spot ~~market~~market. Megawatt-hours acquired under our energy replacement program were lower for the nine-months ended September 30, 2011 as compared to the same period of 2010. The decrease in purchased power costs for the three-month and ~~from~~nine-month periods ended September 30, 2011 compared to the same periods of 2010 was primarily due to lower realized losses incurred for natural gas financial contracts utilized for managing exposure to fluctuations in the market prices of natural gas.

The effect on net margin for Murray and Hawk Road is being deferred until 2016 at which time the amounts will be amortized over the remaining life of the plants. In implementing the deferral plans, we assumed that our members would generally not require energy from the plants until 2016. If any of our members subscribed to Murray elect to take energy from Murray prior to 2016, the deferral of the effect on net margin would terminate for that member and the amortization of that members' deferral would commence immediately. The ~~increased~~changes in cost deferrals in 2011 compared to 2010 resulted from the Murray and Hawk Road costs discussed above in production costs. For further discussion regarding the deferral plan, see "—Capital Requirements and Liquidity—Future Power Resources—Rate Matters."

Other Income

The decrease in the other income for the three-month and nine-month periods ended September 30, 2011 compared to the same periods of 2010 is primarily due to the amortization of project costs associated with the construction of a combined cycle plant that was canceled due to the Murray acquisition in April 2011.

Interest charges

Interest expense increased by ~~10.3%~~14.8% and ~~9.0%~~10.9% in the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010. This increase is primarily due to the increased debt issued for the purpose of financing the construction of Vogtle Units No. 3 and No. 4.

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Allowance for debt funds used during construction increased by ~~104.6%~~70.3% and ~~81.8%~~77.6% in the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010 primarily due to construction expenditures for Vogtle Units No. 3 and No. 4.

Amortization of debt discount and expense decreased ~~9.3%~~6.4% and ~~12.5%~~10.5% in the three-month and ~~six-month~~nine-month periods ended ~~June~~September 30, 2011 compared to the same periods of 2010 primarily due to the ~~completion of~~completed amortization (in December 2010) of issuance costs associated with transactions in 2009 to provide supplemental credit enhancement for the Rocky Mountain lease arrangements.

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Financial Condition

Balance Sheet Analysis as of ~~June~~September 30, 2011

Assets

Cash used for property additions for the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 totaled ~~$397.2~~$635.0 million. Of this amount, ~~$208.7~~$352.1 million was associated with construction expenditures for 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 ~~$254.3~~$261.8 million in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011. The decrease can be attributed primarily to capital expenditures of ~~$397.2~~$635.0 million for property additions and principal and interest payments of ~~$387.7~~$474.5 million, which were partially offset by ~~increased borrowings and the use of restricted short-term investments.~~long-term debt proceeds. In addition, ~~$529.3~~we financed the $530.3 million ~~of cash was utilized for the~~ Murray ~~acquisition; however, the~~ acquisition ~~was entirely financed by~~through the issuance of commercial paper and a three-year term loan. For information regarding financing of the Murray acquisition, see "—Capital Requirements and Liquidity and Sources of Capital—Financing Activities."

The $3.8 million restricted cash balance at June 30, 2011 primarily consisted of clean renewable energy bond proceeds on deposit with CoBank, N.A. to fund a clean renewable energy project at the Rocky Mountain Pumped Storage Hydroelectric facility.

The ~~$15.6~~$105.8 million of restricted short-term investments at ~~June~~September 30, 2011 represented funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury that earns interest at a guaranteed rate of 5% per annum. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. For information regarding the Rural Utilities Service Cushion of Credit Account, see Note IH of Notes to Unaudited Condensed Financial Statements and "—Capital Requirements and Liquidity and Sources of Capital—Liquidity."

Receivables increased by ~~$58.5~~$34.5 million in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011. The December 31, 2010 receivables balance included approximately $10.3 million of credits available to the members for a board approved reduction to 2010 revenue requirements as a result of margins collected in excess of our 2010 target. A portion of the increase in receivables was due to these credits being utilized by the members during the first half of 2011. ~~The receivable for amounts billed or billable to~~In addition, $17.4 million of the ~~members for their monthly power bills also increased by approximately $20.4 million in June 2011 compared to December 2010. This~~ increase was ~~primarily due~~related to ~~higher~~non-member energy ~~costs during the period, which was a result~~sales. For information regarding non-member energy sales, see Note M of ~~increased generation. Receivables from Smarr EMC for costs incurred for operation of its facilities also increased by $5.0 million.~~Notes to Unaudited Condensed Financial Statements.

Inventories, at average cost, increased ~~$33.0~~$32.0 million in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 due to inventory acquired in connection with the Murray acquisition.

Other deferred charges increased ~~$33.7~~$27.0 million in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 primarily due to the ~~$29.7~~$19.1 million amortized value of the intangible asset ~~associated with~~recorded for the Georgia Power purchase and sale agreement ~~with Georgia Power, acquired~~assumed as part of the Murray acquisition. In addition, $5.3 million of the increase was attributed to Georgia Power related deferred equipment prepayments that will be expensed or capitalized once utilized.

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Equity and Liabilities

Long-term debt increased ~~$587.3~~$862.5 million for the ~~six-month~~nine-month period ended ~~June~~September 30, 2011. The increase was due in part to a $260.0 million three-year term loan which closed in April 2011 to provide interim financing for the Murray ~~acquisition. During the second quarter of 2011, we received~~acquisition and $353.6 million in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans ~~totaling $276.6 million~~ to permanently finance the Hartwell and Hawk Road ~~acquisitions.~~

~~Table~~acquisitions and other general improvements. In August 2011, we issued $300.0 million in first mortgage bonds for the purpose of ~~Contents~~repaying outstanding commercial paper issued in connection with funding a portion of constructing Vogtle Units No. 3 and No. 4. The first mortgage bonds are secured under our first mortgage indenture.

Long-term debt and capital leases due within one year decreased ~~$36.6~~$34.0 million primarily as a result of scheduled debt maturities and the reclassification of certain long-term debt.

Short-term borrowings for the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 ~~increased $47.7~~decreased $30.2 million. The ~~increase~~decrease was primarily due to the ~~issuance~~repayment of commercial paper issued to fund capital expenditures ~~for~~related to Vogtle Units No. 3 and No. 4 and ~~the Murray acquisition. Largely offsetting these increases was the repayment of commercial paper issued~~ to provide interim financing of the 2009 Hartwell and Hawk Road acquisitions.

Accounts payable ~~increased $50.3~~decreased $19.8 million in the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 primarily due to ~~an $18.7~~a $35.2 million ~~increase~~decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs primarily associated with Vogtle Units No. 3 and No. 4 construction. ~~In addition, there~~Offsetting the decrease was a ~~$26.1~~$13.0 million increase in the payable for natural gas, primarily due to an increase in natural gas-fired generation at Murray and ~~Chattahoochee.~~the Chattahoochee Energy Facility. At December 31, 2010, Chattahoochee was in an unplanned outage and did not resume operation until April 2011.

The ~~$22.8~~$30.5 million decrease in accrued interest for the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 was due to the normal timing differences between interest payments and interest expense accruals.

Accrued and withheld taxes decreased ~~$7.6~~$4.9 million for the ~~six-month~~nine-month period ended ~~June~~September 30, 2011 as a result of payments made, when due, for 2010 property taxes, which exceeded normal 2011 property tax accruals.

Member power bill prepayments represent funds received from the members for prepayment of their monthly power bills. At ~~June~~September 30, 2011, ~~$40.6~~$50.1 million of member power bill prepayments was classified as a current liability and ~~$29.9~~$41.5 million of member power bill prepayments was classified as a long-term liability. During the ~~six-month~~nine-month period ended ~~June~~September 30, 2011, approximately ~~$13.8~~$49.3 million of prepayments were received from the members and approximately ~~$55.7~~$70.2 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note KJ of Notes to Unaudited Condensed Financial Statements and "—Capital Requirements and Liquidity and Sources of Capital—Liquidity."

Capital Requirements and Liquidity and Sources of Capital

Future Power Resources

To meet the energy needs of our members, we are in a period of generation expansion. In addition to acquiring more than 2,000 megawatts of capacity through the ~~purchase~~purchases of the Hawk Road, Hartwell and Murray energy facilities, members have subscribed to a 30% interest in Vogtle Units No. 3 and No. 4 (660 megawatts), which are currently under construction. We continue to evaluate additional generation resource development opportunities to help meet our members' projected power supply needs over the next ten years. For further discussion of our planned future generation resources and projected capital expenditures, see "Item 1—BUSINESS—Our Power Supply Resources—Future Power Resources" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

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RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2010 Form 10-K.

Vogtle Units No. 3 and No. 4. ~~In June 2011, Westinghouse Electric Company, LLC submitted an AP1000 Design Certification Amendment to the Nuclear Regulatory Commission. In a letter dated August 2,~~On September 27 and 28, 2011, the Nuclear Regulatory Commission ~~clarified~~held the ~~timeframe~~mandatory hearing for ~~approval of~~ the combined construction permits and operating licenses for Vogtle Units No. 3 and No. 4 ~~which continues~~and for Georgia Power's request for a second limited work authorization. On October 18, 2011, the Atomic Safety and Licensing Board denied the remaining motions seeking to ~~allow for issuance in late 2011. On August 5,~~re-open the Vogtle Units No. 3 and No. 4 licensing proceeding; however, on October 27, 2011, the petitioners requested reconsideration of this decision and, on November 2, 2011, further appealed to the Nuclear Regulatory Commission ~~announced that it had completed~~to admit their contentions, should they again be denied by the ~~Final~~Atomic Safety ~~Evaluation Report for both~~and Licensing Board. The remaining steps in the ~~Westinghouse~~regulatory process are to address the status of these petitions and obtain Nuclear Regulatory Commission approvals of the AP1000 Design Certification ~~Document~~Amendment and the combined construction permits and operating ~~licenses. Based on this positive development,~~licenses which Georgia Power expects ~~the Nuclear Regulatory Commission to~~

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~~approve the Design Certification Amendment~~ in late 2011. However, due to certain administrative procedural requirements, it is possible that the effective date of the ~~Design Certification Amendment~~design certification amendment and issuance of the combined construction permits and operating licenses could occur in early 2012. In this case, the Nuclear Regulatory Commission could approve ~~Georgia Power's request for a~~the second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in ~~fall~~late 2011 and obtain commercial operation in 2016 and 2017 for Vogtle Units No. 3 and No. 4, respectively.

During the course of construction, issues have materialized that may impact the budget and schedule for Vogtle Units No. 3 and No. 4, including potential costs associated with compressing the current project schedule to avoid delays in the respective commercial operation dates of the units. This potential schedule compression relates to making up time due to a delay in obtaining regulatory approval for the design certification document. We, along with Georgia Power, the Municipal Electric Authority of Georgia and the City of Dalton, the "Co-Owners," and Westinghouse and Stone & Webster, Inc., the "Consortium," have agreed to informal and formal processes with respect to submitting and negotiating any such issues. If the parties are unable to resolve any disputes through informal negotiations, the disputes, including the potential schedule compression, will be resolved through the formal dispute resolution procedures agreed to by the parties. The Co-Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

There are other pending technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4, ~~and~~including petitions filed at the Nuclear Regulatory Commission in response to the events in Japan. Similar additional challenges at both the state and federal level are expected as construction proceeds. The ultimate outcome of these matters cannot be determined at this time.

As of ~~June~~September 30, 2011, our total capitalized costs to date for Vogtle Units No. 3 and No. 4 ~~was $1.1~~were $1.2 billion.

~~Recent~~ Events in Japan. OnIn March ~~11,~~ 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. Both Georgia Power, on behalf of the Co-Owners, and we continue to monitor the ~~situation~~response to this event and have not identified any immediate impact to the licensing and construction of Vogtle Units No. 3 and No. 4 or the operation of our existing nuclear facilities.

The events in Japan have created broader economic uncertainties that may affect the availability of equipment from Japanese manufacturers and future operating costs, including fuel, for our nuclear and other generating facilities. The Nuclear Regulatory Commission ~~plans to perform~~is performing additional operational and safety reviews of nuclear facilities in the United States, which could potentially impact future operations and capital requirements. ~~As a first step in this review, in~~In July 2011, a special Nuclear Regulatory Commission task force issued a report with initial recommendations for enhancing nuclear reactor safety in the United States, including potential changes in emergency planning, onsite backup generation and spent fuel pools for existing reactors. ~~The~~However, the final form and resulting impact of any changes to safety requirements for existing nuclear reactors will be dependent on further review and action by the Commission and cannot be determined

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at this time. The task force report supported completion of the certification of the AP1000 reactor design being used at Vogtle Units No. 3 and No. 4, noting that the design includes many of the features necessary to address the task force's recommendations.

The ultimate outcome of these matters, including ~~any~~ petitions filed with the Nuclear Regulatory Commission in response to the events in Japan, cannot be determined at this time. See "Item 1A—RISK FACTORS" in our 2010 ~~annual report~~Form 10-K for a discussion of certain risks associated with the licensing, construction and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

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Rate Matters. ~~Based on member requests, we are currently developing~~Our board of directors has approved two rate management programs, ~~that could be offered to~~which we developed based on requests from members that have ~~subscriptions in~~subscribed to the Plant Vogtle units under construction and Murray. The first program ~~would provide~~allows members ~~with an opportunity~~ to expense rather than capitalize interest during construction on the Plant Vogtle units and the second program ~~would allow~~allows members to expense rather than defer the ~~carrying~~net costs associated with Murray. See Note JL of Notes to Unaudited Condensed Financial Statements for a discussion of the ~~deferred carrying costs~~deferral associated with Murray. Each subscribing member ~~would be able to~~may elect to participate in one or both of these programs. The Plant Vogtle rate management program ~~would~~will be available starting in 2012 and ~~would allow~~allows each subscribing member to make an annual election to expense ~~some or all~~a percentage of its allocated portion of interest during construction for the ~~following~~ year, although only current year costs ~~could~~may be expensed. The Murray rate management program ~~would~~will be available ~~by or before 2012~~starting on December 31, 2011 and ~~would allow~~allows each subscribing member to make ~~a monthly~~an annual election to expense ~~some or all~~a percentage of its allocated portion of Murray's ~~carrying~~monthly net costs for that year that would otherwise be ~~deferred. These~~deferred, and to elect once a year to expense any previously deferred net costs. The rate ~~management~~schedule changes required to implement these programs are ~~subject to approval by our board of directors and member elections to participate, and the associated rate change is~~ subject to approval by the Rural Utilities Service. Any effect of these rate management programs on our financial statements is subject to member elections to participate.

Environmental Regulations

~~Recently, the~~The Environmental Protection Agency ~~has proposed or finalized~~continues to develop a number of rules that would significantly expand the scope of ~~regulations governing~~regulation of air emissions, water intake and waste management at power plants. See "Item 1A—RISK FACTORS" in our 2010 ~~Annual Report~~Form 10-K for further discussion regarding potential effects on our business from environmental regulation.

~~In July~~On August 8, 2011, EPA finalized the Cross-State Air Pollution Rule, ~~that~~which contains new sulfur dioxide and nitrogen oxides emission reduction requirements for existing electric generating units ~~located~~ in most ~~states east~~ of the ~~Mississippi,~~eastern United States, including Georgia. ~~The~~For 2012, compliance with the rule ~~which replaced~~may necessitate some combination of the Clean Air Interstate Rule, imposes emission caps in each affected state. Georgia is affected by the rule's summer ozone season nitrogen oxides allowance trading program and the annual sulfur dioxide and nitrogen oxides allowance trading programs for particulate matter. In order to comply with this rule in 2012, we may need to either purchase of emission allowances and/or ~~limit~~the limiting of operations at Plant Scherer during off-peak ~~periods or some combination of the two. We expect that~~periods. Such steps should become unnecessary in 2013 and beyond, due to additional emission control equipment scheduled for installation and operation at Plant Scherer starting in that year. EPA proposed certain technical amendments to the rule in October 2011, including a postponement of the assurance penalty provisions until 2014 from 2012, which may allow for increased interstate trading of allowances in the first two years, 2012 and 2013, of the program. Various challenges to the rule have been filed with EPA and the U.S. Court of Appeals for the District of Columbia Circuit, in some cases accompanied by a request for a stay of the rule, raising doubt as to whether the program will ~~be installed and operational beginning in 2013 and that emission allowance purchases or limiting of operations will cease to be necessary. The~~begin as currently scheduled on January 1, 2012. Although the ultimate outcome of ~~this~~the rule will depend on further rulemaking or the ~~result~~results of ~~any legal challenges; however, it~~such challenges, the Cross-State Air Pollution Rule is not expected to have a significant impact on the operation of our plants or financial condition.

EPA has also proposed stringent new maximum achievable control technology (MACT) emission limits for certain hazardous air pollutants, including mercury, from coal- and oil-fired electric generating units (EGUs) in the EGU MACT rule. ~~These regulations could require~~Recently, all parties to the ~~installation~~relevant consent decree and the court

Table of additional emission control technologies, including activated carbon injection and baghouses at Plant Wansley. Emission control projects are already underway at Plant Scherer and were included in our projected capital expenditures disclosed in our 2010 Form 10-K. The Plant Scherer projects are expected to be completed by 2014 and cost approximately $820 million, which includes approximately $230 million spent to date. If required, baghouses at Plant Wansley, which were not included in the projected capital expenditures disclosed in our 2010 Form 10-K, would likely be installed from 2014 through 2016 at an approximate cost to us of $150 million. Although EPA has Contents

agreed to ~~a consent decree~~extend the deadline by which itEPA must issue a final EGU MACT rule by 30 days, from November 16, 2011 ~~the court could extend this deadline.~~to December 16, 2011. The total cost of compliance will depend on the final rule and the outcome of any legal challenges ~~and~~ cannot be determined with certainty at this time.

In April 2011, EPA proposed new national requirements to reduce the impact on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. Termed the 316(b) rule, thisAfter its 2010 proposal ~~focuses primarily on requiring utilities to add cooling towers at~~

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power plants that currently have "once-through" cooling systems. The 316(b) rule would affect existing power generating facilities permitted to withdraw more than two million gallons per day from waters of the United States and using at least 25% of the water exclusively for cooling. The proposed regulations would likely apply to Plants Hatch, Scherer, Vogtle and Wansley; however, each of these plants already has operational cooling towers and any effects are not expected to be significant. EPA has agreed to issue a final rule in July 2012 and its ultimate effects will depend on the final rule and any legal challenges.

~~Finally, in 2010 EPA proposed~~ two alternative ~~proposals~~approaches for regulating coal combustion byproducts from electric ~~utilities:~~utilities, regulation ~~listed~~ as either (i) "special wastes" under hazardous waste rules or (ii) as solid ~~wastes.~~wastes, EPA ~~received~~continues to consider the numerous comments received from ~~utilities~~interested stakeholders and ~~industry groups regarding the potential costs and operating effects associated with the adoption~~other members of the ~~proposed rules and has delayed release of~~public. In October, EPA asked for further comments on certain data submitted during the final rule until it can consider all of the comments. Adoption of either approach may require closure of or significant changes to existing storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities, and additional material management and financial assurance requirements. Depending upon which method of regulation EPA selects, if any, preliminary assessments indicate that our share of capital costs at Plants Scherer and Wansley could be approximately half of a billion dollars or potentially more. Estimated costs are based on pre-screening figures that should be distinguished from the more formalized cost estimates provided for projects that are more definite as to scope and timing and theoriginal comment period. The ultimate impacts associated with ~~either~~EPA's coal combustion proposal cannot be determined with certainty at this ~~time.~~time, and will depend on future rulemakings and possible Congressional action.

We cannot predict at this time the ultimate effects these proposed and final regulations may have on the operations and costs of our existing or future power plants, including capital costs. We, along with the other owners of our co-owned facilities, continue to review the potential effects of ~~these new~~recent environmental regulations. For further discussion regarding environmental regulations and potential capital requirements, see "Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity Sources of Capital—Environmental Regulations" in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 and "Item 1—BUSINESS—ENVIRONMENTAL AND OTHER REGULATION" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2010 Form 10-K.

Liquidity

At ~~June~~September 30, 2011, we had ~~$1.68~~$1.8 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$418~~$410 million in cash and cash equivalents and ~~$1.26~~$1.4 billion of unused and available committed credit arrangements.

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~~As discussed in our Form 8-K dated June 9,~~On September 30, 2011, we ~~recently~~ completed ~~a major~~the last component of our planned liquidity restructuring ~~which increased our liquidity~~for 2011 by ~~over $600 million. At June~~closing on a new $110 million, five-year unsecured line of credit facility with National Rural Utilities Cooperative Finance Corporation. As a result, at September 30, 2011 we had in excess of ~~$1.86~~$1.9 billion of committed credit arrangements in place comprised of the five separate facilities reflected in the table below. We believe this amount of liquidity will be sufficient to cover our interim funding needs through the period of generation expansion and to provide a reasonable cushion for our normal business operations.


Committed Credit Facilities	Committed Credit Facilities							Committed Credit Facilities

			Authorized Amount		Available 6/30/2011		Expiration Date			Authorized Amount		Available 9/30/2011		Expiration Date

			(dollars in millions)							(dollars in millions)
*Unsecured Facilities:*	*Unsecured Facilities:*							*Unsecured Facilities:*
	Syndicated Line of Credit⁽¹⁾	$	1,265	$	778	⁽²⁾	June 2015	Syndicated Line of Credit⁽¹⁾	$	1,265	$	856	⁽²⁾	June 2015
	CFC Line of Credit		50		50		October 2011	CFC Line of Credit		110		110		September 2016
	JPMorgan Chase Line of Credit		150		33	⁽³⁾	December 2013	JPMorgan Chase Line of Credit		150		33	⁽³⁾	December 2013
*Secured facilities:*	*Secured facilities:*							*Secured facilities:*
	CoBank Line of Credit		150		150		November 2012	CoBank Line of Credit		150		150		November 2012
	CFC Line of Credit		250		250		December 2013	CFC Line of Credit		250		250		December 2013

Total	Total	$	1,865	$	1,261			Total	$	1,925	$	1,399

⁽¹⁾: This credit facility is syndicated among fourteen banks led by Bank of America as administrative agent.
⁽²⁾: Of the portion of this facility that is unavailable, ~~$352~~$274 million is dedicated to support commercial paper we have issued and $135 million relates to letters of credit issued under this facility to support variable rate demand bonds.
⁽³⁾: Of the portion of this facility that is unavailable, $114 million relates to letters of credit issued under this facility to support variable rate demand bonds and $3 million relates to letters of credit issued to post collateral to third parties.

The final component of our liquidity restructuring plan is to renew and upsize our $50 million unsecured line of credit with National Rural Utilities Cooperative Finance Corporation (CFC) as a new five-year $110 million unsecured line of credit. Both our board of directors and CFC's board of directors have approved this new facility, and we expect to have it in place before the existing credit facility expires on October 1, 2011. When completed, we will have credit facilities in place that in the aggregate total $1.93 billion. We believe this amount of liquidity will be more than sufficient to cover our interim funding needs through the period of generation expansion and to provide a reasonable cushion for our normal business operations.

Due to the significant expenditures we are incurring relating to environmental compliance projects and acquiring and constructing new generation facilities, we ~~are currently~~have been funding our capital requirements through a combination of funds generated from operations and interim and long-term borrowings. In particular, we are ~~currently~~ using commercial paper, backed by the syndicated line of credit, to provide interim financing for the environmental compliance expenditures, for a portion of the cost to acquire Murray and for construction of Vogtle Units No. 3 and No. 4 until permanent financing for these projects is put in place.

In the third quarter of 2011, we plan to issue at least $300 million of long-term first mortgage bonds to fund a portion of the cost of constructing the additional units at Plant Vogtle and use the bond proceeds to repay commercial paper providing interim funding for this same purpose. A similar repayment of commercial paper and other interim borrowings relating to the Plant Vogtle construction occurred in connection with the issuances of $450 million and $400 million of long-term first mortgage

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~~bonds in November 2010 and November 2009, respectively. For a more detailed discussion of our plans regarding financing of these facilities, see "—~~~~Financing Activities~~."

Under the commercial paper program, we can issue commercial paper in amounts that do not exceed the amount of any committed lines of credit we have 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. In connection with the increase in the size of our main revolving credit facility to $1.265 billion, we also increased the size of our commercial paper program to that level.

Like the lines of credit from CFC, JPMorgan Chase Bank and CoBank, funds may be advanced under the syndicated line of credit for general working capital purposes. In addition, under some of our committed credit facilities we have the ability to issue letters of credit totaling ~~$850~~$910 million in the aggregate, of which ~~$597~~$658 million remained available at ~~June~~September 30, 2011. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working

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capital needs. Also, any amounts drawn under the syndicated 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 financial covenant that requires us to maintain minimum levels of patronage capital. At ~~June~~September 30, 2011, the required minimum level was $575 million and our actual patronage capital was ~~$625~~$635 million. Additional covenants contained in several of our credit facilities limit the amount of secured indebtedness and unsecured indebtedness we can have outstanding. At ~~June~~September 30, 2011, the most restrictive of these covenants limits our secured indebtedness to $9.5 billion and our unsecured indebtedness to $4.0 billion. At ~~June~~September 30, 2011, we had ~~$5.3~~$5.6 billion of secured indebtedness and ~~$424~~$627 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.

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 ~~June~~September 30, 2011, the balance of member prepayments received but not yet credited to their power bills was ~~$70.5~~$91.6 million. We expect to apply the prepayments against the participating members' power bills through ~~May 2015,~~November 2017, with the majority of the remaining balance scheduled to be applied by the end of 2012. For more information regarding the power bill prepayment program, see Note KJ of Notes to Unaudited Condensed Financial Statements.

At ~~June~~September 30, 2011, current assets included ~~$15.6~~$105.8 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. Our decisions regarding how to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.

Financing Activities

First Mortgage Indenture. At ~~June~~September 30, 2011, we had ~~$5.1~~$5.4 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our tangible

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and some of our intangible assets, including those we acquire in the future. See "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—First Mortgage Indenture" in our 2010 Form 10-K for a further discussion of our first mortgage indenture.

Bond Financing. ~~In the third quarter of~~As disclosed in a Current Report on Form 8-K filed on August 17, 2011, in August we ~~plan to issue at least~~issued $300 million of taxable first mortgage bonds primarily for the purpose of repaying outstanding commercial paper issued in connection with funding a portion of the cost of constructing Vogtle Units No. 3 and No. 4. The first mortgage bonds ~~will be~~are secured under our first mortgage indenture.

~~Interim Financing for the Murray Acquisition.~~ On April 6, 2011, we closed a $260 million three-year term loan with three banks to provide funds for a portion of the cost of acquiring Murray. The balance of the purchase price, $269 million, was funded with commercial paper.

Rural Utilities Service-Guaranteed Loans. We ~~currently~~ have ~~five~~six approved Rural Utilities Service-guaranteed loans, being funded through the Federal Financing Bank, totaling ~~$1.17~~$1.67 billion that are in the process of being drawn down, with ~~$681 million~~$1.1 billion remaining to be advanced.

We also have two Rural Utilities Service-guaranteed loan applications pending, totaling $994 million, including loan applications related to the Warren County biomass plant, which has been deferred, and Murray. Action on the Murray loan is anticipated in 2011.

The Federal budget for fiscal year 2011, which began on October 1, 2010, was adopted in April 2011. Rural Utilities Service funding levels and loan type eligibility for fiscal year 2011 remain unchanged from that in fiscal year 2010. However, the President's proposed budget for fiscal year 2012 does include a modest reduction to the overall funding level as well as prohibitions against funding for (i) improvements to fossil-fueled generation unless the improvements are related to carbon-capture projects, except up to $2 billion may be used for environmental improvements that would reduce emissions, and (ii) construction of new fossil-fueled generation facilities. Nonetheless we have submitted a loan application for Murray, and should members subscribe to any additional fossil-fueled facilities, we anticipate filing loan applications for those facilities to the extent Rural Utilities Service lending authority in place at that time allow us to do so. For any amounts not funded through the Rural Utilities Service, we would most likely issue taxable bonds.

~~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.

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Department of Energy-Guaranteed Loans. We have 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~~interest in Vogtle Units No. 3 and No. 4, not to exceed $3.057 billion. This loan would be funded by the Federal Financing Bank, guaranteed by the Department of Energy and secured under our first mortgage indenture.

We are working with the Department of Energy to finalize the loan ~~guarantee.~~guarantee, including the negotiation of definitive loan agreements. 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 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 Units No. 3 and No. 4 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~~$1.15 billion through the issuance of first mortgage bonds. ~~As discussed above, we expect to issue at least another $300 million of first mortgage bonds for this purpose in the third quarter of 2011.~~

For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2010 Form 10-K. For a discussion of our activities to mitigate the risk of rising interest rates associated with this financing, see "Quantitative and Qualitative Disclosures About Market Risk."

Newly Adopted or Issued Accounting Standards

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

~~Our market risks~~We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we will incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. We have entered into a conditional term sheet with the Department of Energy to finance up to $3.057 billion of the cost to construct the new Vogtle units. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Financing Activities—Department of Energy-Guaranteed Loans." The term sheet provides for quarterly draws from 2012 through 2017 and interest rates that will be based on U.S. Treasury rates at the time of each draw, plus a fixed spread. To mitigate the risk of rising interest rates, we initiated a hedging program in October 2011, which we expect to complete in November 2011. Under this program, we expect to make upfront premium payments of up to $100 million to purchase interest rate options to hedge the interest rates on approximately $2.2 billion of the Department of Energy-guaranteed loan, representing a substantial portion of the expected borrowings from 2013 through 2017. Expected borrowings in 2012 will not ~~changed materially~~be hedged. As of November 14, 2011, we have hedged interest rates on $1.4 billion of expected borrowings.

The interest rate options we are purchasing, commonly known as LIBOR swaptions, are designed to cap our effective interest rate by providing us a lump-sum cash payment on the expiration date of the swaption based on its value on that date. This value depends on the extent to which prevailing LIBOR swap rates exceed the option rate, and the value would be zero if swap rates are at or below the option rate. The swaptions' expiration dates are timed to match the expected quarterly draw dates of the

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Department of Energy-guaranteed loan advances to be hedged; however, as the swaptions' value is independent from the ~~risks reported~~Department of Energy-guaranteed loan, the swaptions could also serve as a hedge of interest rates on an alternative source of financing.

We pay the entire premium at the time we enter into these swaption transactions and have no additional payment obligations. However, upon expiration of the swaptions, each counterparty will be obligated to pay us the cash value of the swaption, if any. In order to diversify counterparty risk, we plan to enter into these transactions with up to seven large banks with average ratings ranging from A+ to AA. To manage our credit exposure to these counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in ~~our 2010 Form 10-K.~~the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds range from $0 to $10 million depending on each counterparty's credit rating.

We expect to defer any gains or losses from the change in fair value of each swaption and related carrying and other incidental costs. The deferred costs, which are not expected to exceed $135 million, and deferred gains, if any, from the sale or settlement of the swaptions will then be amortized and collected in rates over the life of the expected Department of Energy-guaranteed loan.

Item 4. Controls and Procedures

As of ~~June~~September 30, 2011, 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.

As a result of our acquisition of Murray on April 8, 2011, our internal control over financial reporting, subsequent to the date of the acquisition, includes certain additional internal controls relating to Murray. Except for these additional controls as described above, there have been no changes in our internal control over financial reporting or other factors that occurred during the quarter ended June 30, 2011 that have materially affected, or are reasonably likely to materially 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 2010 Form 10-K.

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

	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).
	101		XBRL Interactive Data File.

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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: ~~August 11,~~November 14, 2011	By:	/s/ Thomas A. Smith Thomas A. Smith President and Chief Executive Officer (Principal Executive Officer)
Date: ~~August 11,~~November 14, 2011		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

	2011			2010

		(dollars in thousands)

Premium and loss on reacquired debt	$	105,052		$	111,570
Deferred amortization on capital leases		55,555			64,561
Deferred outage costs		42,441			23,796
Deferred interest rate swap termination fees		23,310			25,306
Asset retirement obligations		9,803			15,699
Deferred depreciation expense		51,921			52,632
Deferred investment impairment losses		4,692			5,214
Deferred charges related to Plant Vogtle Units 3 and 4 training costs		13,460			9,707
Deferral of effects on net margin—Murray Energy Facility		4,014			—
Other regulatory assets		2,612			2,651
Accumulated retirement costs for other obligations		(37,546	)		(39,205	)
Net benefit of Rocky Mountain transactions		(49,373	)		(50,965	)
Deferral of effects on net margin—Hawk Road Energy Facility		(14,898	)		(21,956	)
Major maintenance sinking fund		(29,009	)		(28,500	)
Deferred debt service adder		(32,639	)		(27,678	)
Other regulatory liabilities		(1,772	)		(1,931	)

Net regulatory assets	$	147,623		$	140,901