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

FORM 10-Q


(Mark One)
ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended ~~September 30, 2011~~March 31, 2012
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). Yeso No o ýNo 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.

Table of Contents

(This page has been left blank intentionally)

Table of Contents

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED ~~SEPTEMBER 30, 2011~~MARCH 31, 2012

				Page No.

PART I—FINANCIAL INFORMATION
	Item 1.		Financial Statements		2
		Unaudited Condensed Balance Sheets as of ~~September 30, 2011~~ March 31, 2012 and December 31, ~~2010~~2011		2
		Unaudited Condensed Statements of Revenues and Expenses For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~		4
		Unaudited Condensed Statements of Comprehensive Margin For the Three Months ended March 31, 2012 and 2011		5
		Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the ~~Nine~~Three Months ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~		56
		Unaudited Condensed Statements of Cash Flows For the ~~Nine~~Three Months ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~		67
		Notes to Unaudited Condensed Financial Statements For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~		78
	Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations		21
	21
Item 3.		Quantitative and Qualitative Disclosures About Market Risk		32
	30
Item 4.		Controls and Procedures		3330
PART II—OTHER INFORMATION
	Item 1.		Legal Proceedings		34
	31
Item 1A.		Risk Factors		34
	31
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		34
	31
Item 3.		Defaults Upon Senior Securities		34
	31
Item 4.		~~Reserved~~Mine Safety Disclosures		34
	31
Item 5.		Other Information		34
	31
Item 6.		Exhibits		3532
SIGNATURES				3633

Table of Contents

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements

~~Item 1. Financial Statements~~

Oglethorpe Power Corporation
Condensed Balance Sheets
~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011


			(dollars in thousands)						(dollars in thousands)
		2011			2010			2012			2011
			(Unaudited)						(Unaudited)
Assets	Assets
Electric plant:	Electric plant:
In service								$	7,377,355		$	7,335,866
Less: Accumulated provision for depreciation									(3,364,573	)		(3,328,585	)

									4,012,782			4,007,281
Nuclear fuel, at amortized cost									300,736			284,205
Construction work in progress									1,890,264			1,784,264

									6,203,782			6,075,750

Investments and funds:
Nuclear decommissioning trust fund									287,930			268,597
Deposit on Rocky Mountain transactions									134,274			132,048
Investment in associated companies									57,407			57,626
Long-term investments									76,083			80,055
Restricted cash									51,741			43,070
Other, at cost									1,040			3,564

									608,475			584,960

Current assets:
Cash and cash equivalents									402,368			443,671
Restricted cash									613			613
Restricted short-term investments									110,526			106,676
Receivables									139,359			124,650
Inventories, at average cost									246,284			246,795
Prepayments and other current assets									14,037			15,562

									913,187			937,967

Deferred charges:
Deferred debt expense, being amortized									66,368			67,470
Regulatory assets									338,386			351,547
Other									34,609			61,135
	In service	$	7,319,697		$	6,672,253
	Less: Accumulated provision for depreciation		(3,299,200	)		(3,101,731	)		439,363			480,152

			4,020,497			3,570,522		$	8,164,807		$	8,078,829
	Nuclear fuel, at amortized cost		275,626			249,563
	Construction work in progress		1,614,300			1,195,475

			5,910,423			5,015,560

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

			519,471			527,963

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

			872,684			1,067,703

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

			452,331			385,836

		$	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 Balance Sheets
~~September 30, 2011~~March 31, 2012 and December 31, ~~2010~~2011


			(dollars in thousands)					(dollars in thousands)
		2011		2010			2012		2011
			(Unaudited)					(Unaudited)
Equity and Liabilities	Equity and Liabilities
Capitalization:	Capitalization:
Patronage capital and membership fees							$	647,209	$	633,689
Accumulated other comprehensive margin								1,327		618

								648,536		634,307
Long-term debt								5,604,783		5,562,925
Obligation under capital leases								144,243		146,781
Obligation under Rocky Mountain transactions								134,274		132,048

								6,531,836		6,476,061

Current liabilities:
Long-term debt and capital leases due within one year								159,737		172,818
Short-term borrowings								585,014		461,093
Accounts payable								80,159		134,095
Accrued interest								69,262		91,106
Accrued taxes								8,414		21,118
Member power bill prepayments, current								66,214		66,819
Other current liabilities								27,707		25,080

								996,507		972,129

Deferred credits and other liabilities:
Gain on sale of plant, being amortized								25,494		26,113
Asset retirement obligations								303,615		298,758
Member power bill prepayments, non-current								41,675		35,500
Power sale agreement, being amortized								51,201		54,816
Regulatory liabilities								161,478		164,000
Other								53,001		51,452
	Patronage capital and membership fees	$	635,188	$	595,952
	Accumulated other comprehensive margin (deficit)		864		(469	)		636,464		630,639

			636,052		595,483		$	8,164,807	$	8,078,829
	Long-term debt		5,519,630		4,657,127
	Obligation under capital leases		159,199		179,288
	Obligation under Rocky Mountain transactions		129,894		123,573

			6,444,775		5,555,471

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

			663,763		810,189

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

			646,371		631,402

		$	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 Nine~~ Months Ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~


				(dollars in thousands)												(dollars in thousands)
			Three Months						Nine Months						Three Months
			2011			2010			2011			2010			2012			2011
Operating revenues:	Operating revenues:
Sales to Members															$	295,230		$	269,448
Sales to non-Members																23,994			326
	Sales to Members		$	349,906		$	370,602		$	947,130		$	1,000,393
	Sales to non-Members			82,624			796			134,977			1,188

		Total operating revenues		432,530			371,398			1,082,107			1,001,581
Total operating revenues																319,224			269,774

Operating expenses:	Operating expenses:
Fuel																106,820			72,449
Production																98,499			89,189
Depreciation and amortization																44,544			34,405
Purchased power																14,523			11,555
Accretion																4,857			4,560
Deferral of Hawk Road and Murray Energy Facilities effect on net margin																(12,075	)		(8,319	)
	Fuel			188,983			160,174			422,789			383,750
	Production			90,101			82,717			269,154			245,953
	Depreciation and amortization			49,835			31,208			133,708			98,652
	Purchased power			20,925			24,721			46,080			60,346
	Accretion			4,562			4,282			13,687			12,848
	Deferral of effect on net margin for Hawk Road and Murray Energy facilities			13,240			4,382			2,168			10,453

		Total operating expenses		367,646			307,484			887,586			812,002
Total operating expenses																257,168			203,839

Operating margin	Operating margin			64,884			63,914			194,521			189,579			62,056			65,935

Other income:	Other income:
Investment income																8,255			7,394
Other																3,743			3,366
	Investment income			7,147			7,950			21,467			23,103
	Other			1,651			3,231			6,974			9,413

		Total other income		8,798			11,181			28,441			32,516
Total other income																11,998			10,760

Interest charges:	Interest charges:
Interest expense																76,007			70,666
Allowance for debt funds used during construction																(20,419	)		(15,228	)
Amortization of debt discount and expense																4,946			5,147
	Interest expense			75,704			65,946			218,649			197,089
	Allowance for debt funds used during construction			(17,835	)		(10,474	)		(50,816	)		(28,611	)
	Amortization of debt discount and expense			5,405			5,775			15,893			17,765

		Net interest charges		63,274			61,247			183,726			186,243
Net interest charges																60,534			60,585

Net margin	Net margin		$	10,408		$	13,848		$	39,236		$	35,852		$	13,520		$	16,110

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

Table of Contents

Oglethorpe Power Corporation
Condensed Statements of Comprehensive Margin (Unaudited)
For the Three Months Ended March 31, 2012 and 2011


		(dollars in thousands)
	Three Months
	2012		2011
Net margin	$	13,520	$	16,110

Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities		709		(21	)

Total comprehensive margin	$	14,229	$	16,089

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

Table of Contents

Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~

(dollars in thousands)

Patronage
Capital and
Membership
Fees

Accumulated
Other
Comprehensive
Margin (Deficit)

Total

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

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

Total comprehensive margin 36,937

Balance at September 30, 2010 $ 598,071 $ (168 ) $ 597,903

Balance at December 31, 2010

$
595,952

$
(469
)
$
595,483

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

Total comprehensive margin 40,569

Balance at September 30, 2011 $ 635,188 $ 864 $ 636,052

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

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

Components of comprehensive margin:
Net margin		16,110		—			16,110
Unrealized gain on available-for-sale securities		—		(21	)		(21	)

Balance at March 31, 2011	$	612,062	$	(490	)	$	611,572

Balance at December 31, 2011	$	633,689	$	618		$	634,307

Components of comprehensive margin:
Net margin		13,520					13,520
Unrealized gain on available-for-sale securities				709			709

Balance at March 31, 2012	$	647,209	$	1,327		$	648,536

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

Table of Contents

Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2012 and 2011 ~~and 2010~~


					(dollars in thousands)						(dollars in thousands)
				2011			2010			2012			2011
Cash flows from operating activities:	Cash flows from operating activities:
	Net margin			$	39,236		$	35,852
Net margin										$	13,520		$	16,110

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											77,580			63,304
Accretion cost											4,857			4,560
Amortization of deferred gains											(1,415	)		(1,415	)
Allowance for equity funds used during construction											(851	)		(547	)
Deferred outage costs											(12,604	)		(23,569	)
Deferral of Hawk Road and Murray Energy facilities effect on net margin											(12,075	)		(8,319	)
Gain on sale of investments											(2,362	)		(5,053	)
Regulatory deferral of costs associated with nuclear decommissioning											(622	)		2,348
Other											(1,923	)		(1,848	)
Change in operating assets and liabilities:
Receivables											(12,349	)		8,653
Inventories											511			(15,570	)
Prepayments and other current assets											1,525			1,038
Accounts payable											(25,594	)		(7,541	)
Accrued interest											(21,844	)		(30,225	)
Accrued taxes											(12,704	)		(16,838	)
Other current liabilities											1,227			6,017
Member power bill prepayments											5,570			(14,174	)
		Depreciation and amortization, including nuclear fuel			228,710			186,056
Total adjustments											(13,073	)		(39,179	)
		Accretion cost			13,687			12,848
		Amortization of deferred gains			(4,245	)		(4,245	)
		Allowance for equity funds used during construction			(2,034	)		(1,707	)
		Deferred outage costs			(43,827	)		(25,229	)
		Deferral of effect on net margin for Hawk Road and Murray Energy Facilities			2,168			10,453
		Gain on sale of investments			(13,306	)		(12,013	)
		Regulatory deferral of costs associated with nuclear decommissioning			5,825			4,987
		Other			(5,971	)		(4,216	)
	Change in operating assets and liabilities:
		Receivables			(29,995	)		(25,622	)
		Inventories			2,250			24,137
		Prepayments and other current assets			2,544			(4,384	)
		Accounts payable			10,407			(2,487	)
		Accrued interest			(30,500	)		(13,498	)
		Accrued and withheld taxes			(5,197	)		(2,779	)
		Member power bill prepayments			(20,899	)		(115,831	)
		Other current liabilities			(5,046	)		(2,782	)

			Total adjustments		104,571			23,688

Net cash provided by operating activities					143,807			59,540
Net cash provided by (used in) operating activities											447			(23,069	)

Cash flows from investing activities:	Cash flows from investing activities:
		Property additions			(634,955	)		(524,334	)
		Plant acquisition			(530,293	)		—
		Activity in decommissioning fund—Purchases			(828,008	)		(480,447	)
		—Proceeds			823,598			476,630
		Decrease in restricted cash and cash equivalents			5,687			16,106
		Increase in restricted short-term investments			(8,537	)		(181	)
		Activity in investment in associated organizations—Purchases			(4,634	)		(4,142	)
		—Proceeds			4,556			3,196
		Activity in other long-term investments—Purchases			(1,246	)		(4,313	)
		—Proceeds			1,100			3,100
		Other			(7,822	)		5,420
Property additions											(210,050	)		(208,479	)
Activity in decommissioning fund—Purchases											(288,010	)		(284,469	)
—Proceeds											287,040			283,188
Increase in restricted cash and cash equivalents											(8,671	)		(168,701	)
(Increase) decrease in restricted short-term investments											(3,850	)		82,162
Decrease (increase) in investment in associated organizations											202			(256	)
Activity in other long-term investments—Purchases											(486	)		(402	)
—Proceeds											8,600			300
Activity on interest rate options—Purchases											—			—
—Collateral received											8,670			—
Other											12,623			(1,185	)

Net cash used in investing activities	Net cash used in investing activities				(1,180,554	)		(508,965	)		(193,932	)		(297,842	)

Cash flows from financing activities:	Cash flows from financing activities:
		Long-term debt proceeds			1,093,399			222,631
		Long-term debt payments			(285,067	)		(222,265	)
		(Decrease) increase in short-term borrowings, net			(30,202	)		297,413
		Other			(3,134	)		5,373
Long-term debt proceeds											69,139			257,351
Long-term debt payments											(42,907	)		(54,931	)
Increase (decrease) in short-term borrowings, net											123,921			(12,719	)
Other											2,029			(138	)

Net cash provided by financing activities	Net cash provided by financing activities				774,996			303,152			152,182			189,563

Net decrease in cash and cash equivalents	Net decrease in cash and cash equivalents				(261,751	)		(146,273	)		(41,303	)		(131,348	)
Cash and cash equivalents at beginning of period	Cash and cash equivalents at beginning of period				672,212			579,069			443,671			672,212

Cash and cash equivalents at end of period	Cash and cash equivalents at end of period			$	410,461		$	432,796		$	402,368		$	540,864

Supplemental cash flow information:	Supplemental cash flow information:
Cash paid for—	Cash paid for—
		Interest (net of amounts capitalized)		$	189,258		$	173,307
Interest (net of amounts capitalized)										$	74,287		$	82,661
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		$	(27,810	)	$	95,797
Change in plant expenditures included in accounts payable										$	(27,699	)	$	29,663

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

Table of Contents

Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2012 and 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 nine-month~~three-month periods ended ~~September 30, 2011~~March 31, 2012 and ~~2010.~~2011. 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,~~2011, as filed with the SEC. The results of operations for the ~~three- and nine-month periods~~three-month period ended ~~September 30, 2011~~March 31, 2012 are not necessarily indicative of results to be expected for the full year. As noted in our ~~2010~~2011 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~~2011 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~~reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used ~~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.

Table of Contents

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

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

The tables below detail assets and liabilities measured at fair value on a recurring basis ~~for the periods ended September 30, 2011~~as of March 31, 2012 and December 31, ~~2010.~~2011.


					Fair Value Measurements at Reporting Date Using											Fair Value Measurements at Reporting Date Using
			September 30, 2011			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)			March 31, 2012			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:
	Domestic equity	$	90,014		$	90,014	$	—		$	—
	International equity		38,186			38,186		—			—
	Corporate bonds		45,827			45,827		—			—
	US Treasury and government agency securities		38,581			38,581		—			—
	Agency mortgage and asset backed securities		23,059			23,059		—			—
	Derivative instruments		(1,032	)		—		—			(1,032	)
	Other		17,757			17,757		—			—
Domestic equity													$	115,981		$	115,981	$	—		$	—
International equity														44,784			44,784		—			—
Corporate bonds														57,262			—		57,262			—
US Treasury and government agency securities														50,627			50,627		—			—
Agency mortgage and asset backed securities														10,916			—		10,916			—
Other														8,360			8,360					—
Bond, reserve and construction funds	Bond, reserve and construction funds		2,720			2,720		—			—			197			197		—			—
Long-term investments	Long-term investments		77,221			69,523		—			7,698	⁽¹⁾		76,083			76,083		—			—
Interest rate options														66,860			—		—			66,860	⁽¹⁾
Natural gas swaps	Natural gas swaps		(2,173	)		—		(2,173	)		—			(9,580	)		—		(9,580	)		—

Table of Contents


					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, 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:
	Domestic equity	$	105,523		$	105,523	$	—		$	—
	International equity		43,619			43,619		—			—
	Corporate bonds		53,847			53,847		—			—
	US Treasury and government agency securities		47,649			47,649		—			—
	Agency mortgage and asset backed securities		7,926			7,926		—			—
	Derivative instruments		(452	)		—		—			(452	)
	Other		7,371			7,371		—			—
Domestic equity													$	102,285		$	102,285	$	—		$	—
International equity														39,618			39,618		—			—
Corporate bonds														41,338			—		41,338			—
US Treasury and government agency securities														41,697			41,697		—			—
Agency mortgage and asset backed securities														28,519			—		28,519			—
Derivative instruments														(982	)		—		—			(982	)
Other														16,122			16,122		—			—
Bond, reserve and construction funds	Bond, reserve and construction funds		2,815			2,815		—			—			2,720			2,720		—			—
Long-term investments	Long-term investments		79,212			70,541		—			8,671	⁽¹⁾		80,055			72,342		—			7,713	⁽²⁾
Interest rate options														69,446			—		—			69,446	⁽¹⁾
Natural gas swaps	Natural gas swaps		(2,054	)		—		(2,054	)		—			(7,220	)		—		(7,220	)		—

⁽¹⁾: Interest rate options as reflected on the condensed Balance Sheets include the fair value of the interest rate options offset by $51,740,000 and $43,070,000 of collateral received by the counterparties at March 31, 2012 and December 31, 2011, respectively.
⁽²⁾: Represents auction rate securities investments we ~~hold.~~held.

The following tables present the changes in our Level 3 assets and liabilities measured at fair value on a recurring basis during the three ~~and nine~~ months ended ~~September 30, 2011~~March 31, 2012 and ~~2010.~~2011.


			Three Months Ended September 30, 2011						Three Months Ended March 31, 2012

			Decommissioning funds			Long-term investments			Decommissioning funds			Long-term investments			Interest rate options

			(dollars in thousands)						(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):
Balance at June 30, 2011		$	(505	)	$	8,048
Balance at January 1, 2012								$	(982	)	$	7,713		$	69,446
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(527	)		—
	Impairment included in other comprehensive deficit		—			50
Included in earnings (or changes in net assets)									982			—			(2,586	)
Impairment included in other comprehensive deficit									—			887			—
Liquidations	Liquidations		—			(400	)		—			(8,600	)		—

Balance at September 30, 2011		$	(1,032	)	$	7,698
Balance at March 31, 2012								$	—		$	—		$	66,860

Table of Contents

Three Months Ended
September 30, 2010

Decommissioning
funds Long-term
investments

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

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

Nine Months Ended
September 30, 2011

Decommissioning
funds Long-term
investments

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

Balance at September 30, 2011 $ (1,032 ) $ 7,698


			Nine Months Ended September 30, 2010						Three Months Ended March 31, 2011

			Decommissioning funds			Long-term investments			Decommissioning funds			Long-term investments

			(dollars in thousands)						(dollars in thousands)
Assets (Liabilities):	Assets (Liabilities):
Balance at December 31, 2009		$	(260	)	$	27,010
Balance at January 1, 2011								$	(452	)	$	8,671
Total gains or losses (realized/unrealized):	Total gains or losses (realized/unrealized):
	Included in earnings (or changes in net assets)		(263	)		—
	Impairment included in other comprehensive deficit		—			184
Included in earnings (or changes in net assets)									(96	)		—
Impairment included in other comprehensive deficit									—			37
Liquidations	Liquidations		—			(3,100	)		—			(300	)

Balance at September 30, 2010		$	(523	)	$	24,094
Balance at March 31, 2011								$	(548	)	$	8,408

~~The assets included in the "Long-term investments" column in each~~On February 15, 2012, we sold our remaining $8,600,000 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 September 30, 2011, we held auction rate securities with maturity dates ranging from November 1, 2044 to December 1, 2045.

~~Table of Contents~~

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 September 30, 2011, we recorded a ($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 September 30, 2011, would have resulted in ~~an additional decrease in the fair value~~a loss of ~~our auction rate securities investments by approximately $509,000.~~

~~As of September 30, 2011, these investments were rated A3 by Moody's Investors Service~~$1,075,000. The loss was recorded as a regulatory asset and ~~AAA by Fitch. Therefore, it~~ is ~~expected that the investments will not be settled at~~being charged to income over 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 September 30, 2011.~~four years.

(C): Disclosures about Derivative Instruments and Hedging Activities. Our risk management and compliance committee provides general oversight over all risk management activities, including but not limited to, commodity trading, ~~and~~ investment portfolio management and interest rate risk 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. To hedge the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, we have entered into interest rate options. Hedge accounting is not applied to our interest rate options. Consistent with our rate-making treatment, unrealized gains or losses from the interest rate options are recorded to the related regulatory asset. Within our nuclear decommissioning trust fund, derivatives including options, swaps and credit default swaps which are non-speculative, ~~are~~could be utilized to mitigate volatility associated with duration, default, yield curve and the interest rate risks of the portfolio. We do not hold or enter into derivative transactions for trading or speculative purposes. Consistent with our rate-making treatment, unrealized gains or losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset or liability.

Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.

At September 30, 2011, the estimated fair value of our natural gas contracts was an unrealized loss of approximately $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 have established policies and procedures to manage credit risk ~~with policies and procedures for, among other things,~~through counterparty analysis, exposure ~~measurement,~~calculation and monitoring, exposure ~~monitoring~~limits, collateralization and ~~mitigation in our natural gas hedging portfolio.~~certain other contractual provisions.

It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more natural gas counterparties, and we currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of ~~September 30, 2011,~~March 31, 2012, all of the counterparties with transaction amounts outstanding inunder our hedging ~~portfolio~~programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

Table of Contents

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, 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 certain of our 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.~~and condition. 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.

Gas hedges. 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 March 31, 2012 and December 31, 2011 the estimated fair value of our natural gas contracts was an unrealized loss of approximately $9,580,000 and $7,220,000, respectively.

As of ~~September 30, 2011,~~March 31, 2012, neither we nor any counterparties were required to post credit support or collateral under ~~any of these~~the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on ~~September 30, 2011~~March 31, 2012 due to our credit rating being downgraded below investment grade, we ~~could~~would have been required to post ~~collateral or~~letters of credit ~~support~~ totaling up to ~~$2,173,000~~$9,580,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of ~~September 30, 2011~~March 31, 2012 that is expected to settle or mature each year:



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

2011	0.57
2012	2.60	5.08
2013	0.54	1.37
2014		0.67

Total	3.71	7.12

Interest rate options. We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to 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

Table of Contents

to construct Vogtle Units No. 3 and No. 4. 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. In fourth quarter of 2011, we purchased interest rate options at a cost of $100,000,000 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.

The interest rate options, commonly known as LIBOR swaptions, give us the right, but not the obligation, to enter into a swap in which we would pay a fixed rate and receive a floating LIBOR rate. However, the swaptions are required to be cash settled based on their value on the expiration date, thereby effectively capping our interest rates by offsetting the present value cost of an increase in interest rates above the fixed rate. The cash settlement value depends on the extent to which prevailing LIBOR swap rates exceed the fixed rate on the underlying swap, and the value would be zero if swap rates are at or below the fixed rate upon expiration. The fixed rates on the LIBOR swaptions we purchased are in the range of 100 to 200 basis points above current LIBOR swap rates and the weighted average fixed rate is 4.17%. The swaptions' expiration dates, which range from 2013 through 2017, are timed to match the expected quarterly draw dates of the Department of Energy-guaranteed loan advances to be hedged. As the interest rate options' value is independent from the Department of Energy-guaranteed loan, the interest rate options could also serve as a hedge of interest rates on an alternative source of financing.

We paid the entire premiums at the time we entered into these interest rate option transactions and have no additional payment obligations. However, upon expiration of the interest rate options, each counterparty will be obligated to pay us the cash value of the interest rate options, if any. These derivatives are recorded at fair value and hedge accounting is not applied. At March 31, 2012 and December 31, 2011, the fair value of these interest rate options was approximately $66,860,000 and $69,446,000, respectively. To manage our credit exposure to these counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the interest rate options outstanding for that counterparty exceeds a certain threshold. The collateral thresholds range from $0 to $10,000,000 depending on each counterparty's credit rating. As of March 31, 2012 and December 31, 2011, we held $51,740,000 and $43,070,000 of funds posted as collateral by the counterparties, respectively. The collateral received is recorded as long-term restricted cash on our balance sheets. The liability associated with the collateral is recorded as an offset to the fair values of the interest rate options, which are recorded within other deferred charges on the condensed balance sheets, results in a net carrying amount of the interest rate options of $15,120,000 and $26,376,000 at March 31, 2012 and December 31, 2011, respectively.

We are deferring gains or losses from the change in fair value of each interest rate option and related carrying and other incidental costs in accordance with our rate-making treatment. The deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the expected Department of Energy-guaranteed loan or alternative financing.

We estimate the value of the LIBOR swaptions utilizing an option pricing model based on several inputs including the notional amount, the forward LIBOR swap rates, the option volatility, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, as well as credit attributes, including the credit spread of the counterparty and the amount of credit support that is available for each swaption. The fair value of the swaptions is sensitive to certain of these inputs, especially option volatility. We are able to effectively observe all of these factors using a variety of market sources except for the credit spreads of certain counterparties and the option volatility. We are able to estimate option volatility implied by valuations we obtain from various sources, but the valuations, and therefore the implied option

Table of Contents

volatilities vary considerably from one source to another. Since valuations of comparable instruments are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We considered both any intrinsic value and the remaining time value associated with the derivatives and considered counterparty credit risk in our determination of all estimated fair values. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts.

The following table reflects the notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31, 2012:



Year		LIBOR Swaption Notional Dollar Amount (in thousands)

2013	$	754,452
2014		563,425
2015		470,625
2016		310,533
2017		80,169

Total	$	2,179,204

The table below reflects the fair value of derivative instruments and their effect on our unaudited condensed balance sheet as of ~~September 30, 2011.~~March 31, 2012.

Balance Sheet Location

Fair
Value

Balance Sheet Location

Fair
Value

(dollars in
thousands)

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

Assets

Natural Gas Swaps

Receivables

2,173

Total assets designated as hedges under authoritative guidance related to derivatives and hedging activities

2,173

Liabilities

Natural Gas Swaps

Other current liabilities

2,173

Total liabilities designated as hedges under authoritative guidance related to derivatives and hedging activities

2,173

Natural Gas Swaps

Other current liabilities

9,580

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

Assets

Interest rate options

Other deferred charges

66,860

Nuclear decommissioning trust

Decommissioning fund

911

Nuclear decommissioning trust

Decommissioning fund

(1,943

)

Nuclear decommissioning trust

Deferred asset associated with retirement obligations

985

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

(1,503

)

Table of Contents

The following table presents the gains and (losses) on derivative instruments recognized in ~~net~~ margin or deferred on the balance sheet for the three ~~and nine~~ months ended ~~September 30, 2011.~~March 31, 2012.

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

Statement of
Revenues and
Expenses Location

Three months
ended

Nine months
ended

(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities

Natural Gas Swaps

Purchase power

$
99
$
195

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

927
1,997

Nuclear decommissioning trust

Investment income

(661
)
(1,233
)

Total losses on derivatives

$
(1,804
)
$
(2,465
)


Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
	Statement of Revenues and Expenses or Balance Sheet Location		Three months ended

			(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities
Natural Gas Swaps	Purchased power	$	(2,407	)
Natural Gas Swaps	Receivables		(9,580	)
Not designated as hedges under authoritative guidance related to derivatives and hedging activities
Nuclear decommissioning trust	Regulatory asset	$	1,226
Nuclear decommissioning trust	Regulatory asset		(1,643	)
Interest rate options	Regulatory asset		(33,140	)

Total losses on derivatives		$	(45,544	)

(D): Investments in Debt and Equity Securities. Under the accounting guidance for ~~investments in debt~~Investments—Debt and ~~equity securities,~~Equity Securities, investment securities we hold are classified as ~~either available-for-sale or held-to-maturity.~~available-for-sale. 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~~other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning trust fund ~~which are also classified as available-for-sale,~~ are directly added to or deducted from ~~deferred~~the regulatory asset for asset retirement ~~obligations costs. Held-to-maturity securities~~obligations. Realized gains and losses on the nuclear decommissioning trust fund are ~~carried at cost. We owned no held-to-maturity securities as of September 30, 2011 and December 31, 2010.~~also recorded to the regulatory asset. All realized and unrealized gains and losses ~~were~~are determined using the specific identification method. Approximately ~~84%~~95% of these gross unrealized losses were in effect for less than one year. These losses were primarily due to investments in 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.

Table of Contents

For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010:~~2011:


		(dollars in thousands)									(dollars in thousands)
			Gross Unrealized									Gross Unrealized
September 30, 2011	Cost		Gains		Losses			Fair Value
March 31, 2012										Cost		Gains		Losses			Fair Value

Equity	$	147,602	$	20,430	$	(14,928	)	$	153,104	$	148,898	$	43,951	$	(3,804	)	$	189,045
Debt		156,235		10,779		(4,508	)		162,506		165,476		9,843		(3,588	)		171,731
Other		17,164		1,080		(1,520	)		16,724		3,447		—		(13	)		3,434

Total	$	321,001	$	32,289	$	(20,956	)	$	332,334	$	317,821	$	53,794	$	(7,405	)	$	364,210

~~Table of Contents~~


			Gross Unrealized									Gross Unrealized
December 31, 2010		Cost		Gains		Losses			Fair Value
December 31, 2011											Cost		Gains		Losses			Fair Value

Equity	$	137,492	$	42,622	$	(2,482	)	$	177,632	$	149,263	$	29,789	$	(9,996	)	$	169,056
Debt		158,706		9,130		(4,879	)		162,957		160,218		18,021		(11,063	)		167,176
Other		7,035		3		(118	)		6,920		15,646		1,035		(1,541	)		15,140

Total	$	303,233	$	51,755	$	(7,479	)	$	347,509	$	325,127	$	48,845	$	(22,600	)	$	351,372

(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~~May 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. These changes were effective for us on January 1, 2012. Our adoption of this standard did not have a material effect on our financial statements.

In June 2011, the FASB issued Accounting Standards ~~(IFRSs)~~Update 2011-05 "Comprehensive Income Presentation of Financial Statements" which amended certain provisions of ASC 220 "Comprehensive Income". These provisions change the presentation requirements for other comprehensive income and total comprehensive income and require one continuous statement or two separate but consecutive statements. Presentation of other comprehensive income in the statement of stockholders' equity is no longer permitted. These provisions are effective for fiscal and interim periods beginning after December 15, 2011. The ~~amendments clarify~~adoption of these provisions did not have a material effect on our consolidated financial statements. a material effect on our financial statements.

In December 2011, the ~~FASB's intent~~FASB issued "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities," which modifies the ~~application of existing fair value measurement and~~ disclosure requirements for offsetting financial instruments and ~~include those that change a particular principle or requirement for measuring fair value or for disclosing~~derivative instruments. The update requires an entity to disclose information about ~~fair value measurements. The standard~~offsetting and related arrangements and the effect of those arrangements on its financial position. This guidance is effective for our fiscal 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 year ending December 31, 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, 2011.2013. We do not expect the adoption of this standard to have ana material 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

~~Table of Contents~~

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~~2011 Form 10-K.

Table of Contents

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

Accumulated Other
Comprehensive Margin
(Deficit)
Three Months Ended

(dollars in thousands)

Available-for-sale
Securities

Total

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

Unrealized gain

52
52

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

Balance at June 30, 2011

$
123
$
123

Unrealized gain

741
741

Balance at September 30, 2011
$ 864 $ 864

	Accumulated Other Comprehensive Margin (Deficit) Nine 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

Balance at December 31, 2009	$	(1,253	)	$	(1,253	)
Balance at December 31, 2010							$	(469	)

Unrealized loss								(21	)

Balance at March 31, 2011							$	(490	)

Balance at December 31, 2011							$	618

Unrealized gain		1,085			1,085			709

Balance at September 30, 2010	$	(168	)	$	(168	)
Balance at March 31, 2012							$	1,327

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

Unrealized gain		1,333			1,333

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.

~~Table of Contents~~

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~~States, which represent significant future risks and uncertainties. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, ~~(including~~including carbon ~~dioxide), through the Prevention of Significant Deterioration preconstruction permitting program. As a result,~~dioxide, for certain new and modified facilities. Finally, 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~~Any new requirements in the future but not in existence now 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~~any new 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. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Should we fail to be in compliance with these requirements, or any new 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.

At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.

Table of Contents

We are currently not subject to any environmental or other loss contingencies for which we believe it is probable or reasonably possible that a loss has been incurred that would be material to our financial position, results of operations or cash flows.

(H): Restricted Cash. At March 31, 2012 and December 31, 2011, we had restricted cash totaling $52,354,000 and $43,683,000, respectively, of which $51,741,000 and $43,070,000 was classified as long-term. The long-term restricted cash balance at March 31, 2012 and December 31, 2011 consisted of funds posted as collateral by counterparties to our interest rate options. The current portion of restricted cash at March 31, 2012 and December 31, 2011 primarily consisted of clean renewable energy bond proceeds on deposit with CoBank, ACB to fund a qualifying project at the Rocky Mountain Pumped Storage Hydroelectric Facility.
(I): Restricted Short-term Investments. At ~~September 30,~~March 31, 2012 and December 31, 2011, we had ~~$105,823,000~~$110,526,000 and $106,676,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.
~~(I)~~(J): 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.

Table of Contents

The following regulatory assets and liabilities are reflected on the accompanying condensed balance sheets as of ~~September 30, 2011~~March 31, 2012 and December 31, ~~2010.~~2011.


				2011		2010		2012		2011
				(dollars in thousands)				(dollars in thousands)

Regulatory Assets:	Regulatory Assets:
Premium and loss on reacquired debt							$	95,483	$	98,538	^(a)
Amortization on capital leases								41,431		46,627	^(b)
Outage costs								45,656		42,866	^(c)
Interest rate swap termination fees								20,318		21,316	^(d)
Asset retirement obligations								10,357		29,341	^(e)
Depreciation expense								50,853		51,209	^(f)
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs								19,487		17,602	^(g)
Interest rate options cost								33,589		30,735	^(h)
Deferral of effects on net margin—Murray Energy facility								10,792		3,536	^(k)
Other regulatory assets								10,420		9,777	⁽ⁱ⁾
	Premium and loss on reacquired debt		$	101,661	$	111,570
Total Regulatory Assets							$	338,386	$	351,547
Regulatory Liabilities:
Accumulated retirement costs for other obligations							$	32,795	$	32,687	^(e)
Net benefit of Rocky Mountain transactions								46,984		47,783	^(j)
Deferral of effects on net margin—Hawk Road Energy facility								10,992		15,811	^(k)
Major maintenance sinking fund								29,115		28,524	^(l)
Deferred debt service adder								40,062		37,586	^(m)
Other regulatory liabilities								1,530		1,609	⁽ⁱ⁾
	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
Total Regulatory Liabilities							$	161,478	$	164,000
Net regulatory assets	Net regulatory assets		$	169,591	$	140,901	$	176,908	$	187,547

~~The deferral~~

^(a): Represents premiums paid, together with unamortized transaction costs related to reacquired debt amortized over the period of ~~effects~~the refunding debt, which range up to 31 years.
^(b): Recovery over the remaining life of the leases through 2021.
^(c): Consists of both coal-fired and nuclear refueling outage costs. These outage costs are amortized 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 bea straight-line basis to expense over an 18 to 24-month period.
^(d): Represents amount paid on settled interest rate swaps arrangements that are being amortized over the remaining life of the ~~plants. For information regarding~~refunded variable rate bonds or 2016 and 2019, respectively.
^(e): Accounting and reporting performed in accordance with authoritative guidance related to asset retirement obligations. We record an offsetting regulatory asset or liability to reflect the ~~deferral~~difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes.
^(f): Prior to Nuclear Regulatory Commission (NRC) approval of a 20 year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant.
^(g): Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit which is expected to be 2016 and 2017, respectively, and amortized over the life of the units.
^(h): Deferral of net ~~margins~~loss (gains) associated with the change in fair value of the interest rate options to hedge interest rates on a portion of expected borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence effective with the expected principal repayment of the Department of Energy (DOE)-guaranteed loan in 2017 and amortized over the expected remaining life of DOE-guaranteed loan.
⁽ⁱ⁾: The amortization period for other regulatory assets range up to 37 years and the amortization period of other regulatory liabilities range up to 7 years.
^(j): Net benefit associated with Rocky Mountain lease transactions is amortized to income over the 30-year lease-back period.
^(k): Effects on net margin for Hawk Road and Murray ~~see Note L.~~will be deferred until the end of 2015 and amortized over the remaining life of each plant.
^(l): Represents collections for future major maintenance costs that will offset by deferred revenues when incurred.
^(m): Collections to fund debt payments in excess of depreciation expense through the end of 2025; deferred revenues will be amortized over the remaining useful life of the plants.

Table of Contents

~~(J)~~(K): 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 ~~September 30, 2011,~~March 31, 2012, member power bill prepayments as reflected on the unaudited condensed balance sheet, including unpaid discounts, were ~~$91,597,000,~~$107,889,000, of which, ~~$50,097,000~~$66,214,000 is classified as a current liability and ~~$41,500,000~~$41,675,000 as deferred credits and other liabilities. The prepayments are being applied against members' power bills through November 2017, with the majority of the remaining balance scheduled to be applied by the end of ~~2012.~~2013.
~~(K)~~(L): Debt. InDuring 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

~~Table of Contents~~

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.

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 current interest rate on the loan is 1.50% and 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 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 September 30, 2011,~~2012, we received advances on Rural Utilities Service-guaranteed/Federal Financing Bank loans totaling ~~$353,619,000 to permanently finance the Hartwell~~$69,139,000 for general and ~~Hawk Road acquisitions and for general~~environmental improvements at existing plants.

~~(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 was recorded in the statement of revenues and expenses for the quarter ended June 30, 2011), we funded the entire $532,255,000 cash outlay by closing a $260,000,000 three-year term loan and by financing the remaining $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 identifiable assets acquired and liabilities assumed in the Murray acquisition:~~

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

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

Total identifiable net assets $ 530.3

~~There was no goodwill associated with this acquisition.~~

~~Table of Contents~~

We have consolidated the financial position and results of operations of Murray as of April 8, 2011. Our revenues for the three-month and nine-month periods ended September 30, 2011 include $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 margins from Murray, including related interest costs, are being deferred as a regulatory 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 three-month and nine-month periods ended September 30, 2011, we deferred $13,494,000 and $9,479,000, respectively, in excess revenues from Murray.

(M): Sales to Non-Members. For the three-month ~~and nine-month periods~~period ended ~~September 30, 2011,~~March 31, 2012, we had ~~$82,624,000 and $134,977,000, respectively,~~$23,994,000 of sales to ~~non-members consisting~~non-members. These sales consisted 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, we sold~~These sales also included energy generated at Murray Unit No. 2 sold to non-members.

Table of Contents

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~~Annual Report on Form ~~10-K.~~10-K for the fiscal year ended December 31, 2011. In light of these risks and uncertainties, there can be no assurance that events anticipated by the forward-looking statements contained in this Quarterly Report on Form 10-Q will in fact transpire.

Results of Operations

For the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2012 and 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,~~facility construction and acquisition, our board of directors approved budgets for ~~2010~~2011 and ~~2011~~2012 to achieve a 1.14 margins for interest ratio. As our ~~generation expansion~~construction and acquisition program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below the 1.10 margins for interest ratio required under our first mortgage indenture.

Our net margin for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 was ~~$10.4 million and $39.2~~$13.5 million compared to ~~$13.8 million and $35.9~~$16.1 million for the same ~~periods~~period of ~~2010. Through September 30, 2011, we collected 103.7% of our targeted~~2011. We expect a net margin of ~~$37.8~~$39.7 million for the year ending December 31, ~~2011. This is typical as our management generally budgets conservatively and makes adjustments to the budget throughout the year so that net margins~~2012 which 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'

~~Table of Contents~~

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

Table of Contents

Sales to Members. Total revenues from sales to members ~~decreased 5.6% and 5.3%~~increased 9.6% in the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011. Megawatt-hour sales to members ~~decreased 8.6% and 11.7%~~increased 18.1% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011 versus~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011. The average total revenue per megawatt-hour from sales to members ~~increased 3.4% and 7.3%~~decreased 7.2% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011.

The components of member revenues for the three-month ~~and nine-month~~ periods ended ~~September 30,~~March 31, 2012 and 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 March 31,

	2011		2010		2011		2010		2012		2011
Capacity revenues	$	171,582	$	172,217	$	515,061	$	514,435	$	174,187	$	171,261
Energy revenues		178,324		198,385		432,069		485,958		121,043		98,187

Total	$	349,906	$	370,602	$	947,130	$	1,000,393	$	295,230	$	269,448

Kilowatt-hours sold to members		6,077,054		6,649,453		15,401,272		17,451,164		4,702,799		3,982,856
Cents per kilowatt-hour		5.76¢		5.57¢		6.15¢		5.73¢		6.28¢		6.77¢

Energy revenues were ~~10.1% and 11.1% lower~~23.3% higher for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011. Our average energy revenue per megawatt-hour from sales to members ~~were 1.6% lower and 0.7% higher~~increased 4.4% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 as compared to the same ~~periods~~period of ~~2010.~~2011. The ~~decrease~~increase in energy revenues resulted primarily from ~~lower~~higher megawatt-hour sales to our members primarily as a result of ~~a planned outage~~higher generation at ~~Plant Scherer and~~the Chattahoochee Energy Facility in 2012. Chattahoochee had an unplanned outage ~~at Chattahoochee which resulted~~ in ~~lower generation from these plants in~~the first quarter of 2011 ~~compared to 2010.~~and was not placed back into service until April 2011. 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 nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 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, we sold energy generated at Murray Unit No. 2 to non-members. ~~See Note L of Notes to Unaudited Condensed Financial Statements for further discussion of our acquisition of Murray.~~We acquired Murray in April 2011.

Operating Expenses

Operating expenses for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 increased ~~19.6% and 9.3%~~26.2% compared to the same ~~periods~~period of ~~2010.~~2011. The increase in operating expenses was primarily due to higher fuel, production, ~~and~~ depreciation and amortization ~~costs offset somewhat by lower~~and purchased power costs.

Table of Contents

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

Three Months
Ended September 30,

2011 2010

Fuel Source
Cost Generation Cost Generation
(thousands) (Mwh) (thousands) (Mwh)
Coal
$ 73,377 2,488,052 $ 81,437 2,835,756
Nuclear
19,869 2,486,884 18,092 2,669,806
Gas
94,599 2,332,508 60,158 1,305,749
Pumped Storage
1,138 346,849 487 346,313

$ 188,983 7,654,293 $ 160,174 7,157,624

Cost
Purchased Cost Purchased
(thousands) (Mwh) (thousands) (Mwh)
Purchased Power
$ 20,925 196,147 $ 24,721 64,711



		Nine Months Ended September 30,								Three Months Ended March 31,

		2011				2010				2012					2011

Fuel Source	Cost		Generation		Cost		Generation		Cost		Generation			Cost		Generation
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)			(thousands)		(Mwh)
Coal	$	196,283		6,485,543	$	226,518		8,117,061	$	52,995		1,679,195		$	50,564		1,682,119
Nuclear		54,385		7,192,838		47,901		7,358,843		20,331		2,433,717			16,143		2,396,999
Gas		169,727		4,088,376		107,977		2,271,983		32,878		1,396,212			5,091		22,911
Pumped Storage		2,394		776,713		1,354		767,306		616		(79,149	)		651		(74,042	)

	$	422,789		18,543,470	$	383,750		18,515,193	$	106,820		5,429,975		$	72,449		4,027,987

	Cost		Purchased		Cost		Purchased		Cost		Purchased			Cost		Purchased
		(thousands)		(Mwh)		(thousands)		(Mwh)		(thousands)		(Mwh)			(thousands)		(Mwh)
Purchased Power	$	46,080		256,825	$	60,346		291,339	$	14,523		45,104		$	11,555		21,027

For the three-month ~~and nine-month periods~~period ended ~~September 30, 2011,~~March 31, 2012, total fuel costs increased ~~18.0% and 10.2%~~47.4% and total megawatt-hour generation increased ~~6.9% and 0.2%~~34.8% compared to the same ~~periods~~period of ~~2010.~~2011. Average fuel costs per megawatt-hour increased ~~10.3% and 10.0%~~16.4% in the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011. The increase in total fuel costs and generation resulted primarily from increased natural gas-fired generation of ~~1,027,000~~1,373,000 megawatt-hours ~~and 1,816,000 megawatt-hours for the three-months and nine-months ended September 30, 2011 compared to the same periods of 2010 primarily~~ due to generation from Murray which was sold to ~~non-members. This increase~~non-members and generation from Chattahoochee which was ~~offset somewhat by a decrease~~sold to our members. As discussed previously, Murray was acquired in ~~generation for the three-month~~April 2011 and ~~nine-month periods ended September 30, 2011 compared to the same periods~~Chattahoochee was unavailable during first quarter of 2010 of 348,000 megawatt-hours and 1,632,000 megawatt-hours in coal-fired generation primarily due to a scheduled outage at Plant Scherer for the installation of environmental compliance equipment and general maintenance in 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 in natural gas-fired generation was the primary contributor to the increase in average fuel costs per megawatt-hour of ~~generation.~~

~~Table~~generation; however, during the first quarter of ~~Contents~~2012, natural gas prices continued to decline and nearly reached recent historical lows, which has made natural gas-fired generation resources a more economical and cost-effective source of energy generation than in prior years.

Total production costs increased ~~8.9% and 9.4%~~10.4% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011 compared to the same periods of 2010. The increase in production costs for the quarter ended September 30, 2011~~March 31, 2012 compared to the same period of ~~2010~~2011. The increase in production was ~~partly~~primarily due to operation and maintenance expenses incurred at Murray, and partly due to costs incurred to repair a damaged transformer at the Hawk Road Energy Facility. For the nine-month period ended 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 and Hatch ~~Scherer~~ and ~~Wansley. The increase~~higher operations and maintenance expenses at Chattahoochee. These increases were offset somewhat by lower production costs for the ~~nine months~~Hawk Road Energy Facility in the first quarter of 2012 as production costs for Hawk Road in the first quarter of 2011 included expenses for planned outage work and for repair of a damaged transformer.

Depreciation and amortization costs increased 29.5% for the three-month period ended ~~September 30, 2011 as~~March 31, 2012 compared to the same period of ~~2010 was offset somewhat by lower operations and maintenance costs at the Hartwell Energy Facility; 2010 operations and maintenance costs for Hartwell included major maintenance outage costs.~~

~~Depreciation and amortization costs increased 59.7% and 35.5% for the three-month and nine-month periods ended September 30, 2011 compared to the same periods of 2010.~~2011. 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.~~Murray.

Total purchased power costs ~~decreased 15.4% and 23.6%~~increased 25.7% for the three-month ~~and nine-month periods~~period ended September 30, 2011 compared to the same periods of 2010. Purchased megawatt-hours increased 203.1% and decreased 11.8% for the three-month and nine-month periods ended September 30, 2011 compared to the same periods of 2010. The increase in purchased megawatt-hours for the third quarter of 2011 as compared to the same quarter of 2010 resulted from 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. Megawatt-hours acquired under our energy replacement program were lower for the nine-months ended September 30, 2011 asMarch 31, 2012 compared to the same period of ~~2010.~~2011. The ~~decrease~~increase in purchased power costs ~~for the three-month and nine-month periods ended September 30, 2011 compared to the same periods of 2010~~ was primarily due to ~~lower~~higher 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'~~member's deferral

Table of Contents

would commence immediately. The changes in cost deferrals in ~~2011~~2012 compared to ~~2010~~2011 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~~Other income increased 11.5% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010 is~~2011 primarily due to increased investment income resulting from higher funds deposited in the ~~amortization~~Rural Utilities Service Cushion of ~~project costs associated with the construction of a combined cycle plant that was canceled due to the Murray acquisition in April 2011.~~Credit Account.

Interest charges

Interest expense increased by ~~14.8% and 10.9%~~7.6% in the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010.~~2011. 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.

~~Table of Contents~~

Allowance for debt funds used during construction increased by ~~70.3% and 77.6%~~34.1% in the three-month ~~and nine-month periods~~period ended ~~September 30, 2011~~March 31, 2012 compared to the same ~~periods~~period of ~~2010~~2011 primarily due to construction expenditures for Vogtle Units No. 3 and No. 4.

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

Financial Condition

Balance Sheet Analysis as of ~~September 30, 2011~~March 31, 2012

Assets

Cash used for property additions for the ~~nine-month~~three-month period ended ~~September 30, 2011~~March 31, 2012 totaled ~~$635.0~~$210.0 million. Of this amount, ~~$352.1~~approximately $102.0 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4.4, $34.3 million for purchases of nuclear fuel and $27.3 million was related to environmental control systems being installed primarily at Plant Scherer. 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.~~facilities.

Cash and cash equivalents decreased by ~~$261.8~~$41.3 million in the ~~nine-month~~three-month period ended ~~September 30, 2011.~~March 31, 2012. The decrease ~~can be~~was primarily attributed ~~primarily~~ to capital expenditures ~~of $635.0 million~~ for property additions, ~~and principal and interest payments of $474.5 million, which~~that were ~~partially~~ offset by ~~long-term debt proceeds. In addition, we financed~~$123.9 million in cash received from short-term borrowings and $69.1 million in advances received from the ~~$530.3 million Murray acquisition through the issuance of commercial paper~~Rural Utilities Service for environmental 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.~~"general improvements.

The ~~$105.8~~$110.5 million of restricted short-term investments at ~~September 30, 2011~~March 31, 2012 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~~Decisions regarding how to apply the ~~Rural Utilities Service Cushion of Credit Account, see Note H of Notes to Unaudited Condensed Financial Statements~~funds are guided by the interest rate environment and ~~"—Capital Requirements and Liquidity and Sources of Capital—~~~~Liquidity.~~"our anticipated liquidity needs.

Receivables increased by ~~$34.5~~$14.7 million in the ~~nine-month~~three-month period ended ~~September 30, 2011.~~March 31, 2012. The December 31, ~~2010~~2011 receivables balance included approximately ~~$10.3~~$17.7 million of credits available to the members for a board approved reduction to ~~2010~~2011 revenue requirements as a result of margins collected in excess of our ~~2010~~2011 target. A portion of the increase in receivables was due to these credits being utilized by the members during the first ~~half~~quarter of ~~2011. In addition, $17.4 million of~~2012. Partially offsetting the increase was ~~related to non-member energy sales. For information regarding non-member energy sales, see Note M of Notes to Unaudited Condensed Financial Statements.~~

~~Inventories, at average cost, increased $32.0 million~~a decrease in the ~~nine-month period ended September 30, 2011 due to inventory acquired~~receivable balance for certain project costs written off in ~~connection with the Murray acquisition.~~December 2011.

Other deferred charges ~~increased $27.0~~decreased $26.5 million in the ~~nine-month~~three-month period ended ~~September 30, 2011 primarily~~March 31, 2012 due to an $11.3 million decrease in the ~~$19.1 million amortized~~fair value of ~~the intangible asset recorded for the Georgia Power purchase~~our interest rate options and ~~sale agreement assumed as part of the Murray acquisition. In addition, $5.3~~a $10.2 million ~~of the increase was attributed to~~decrease in Georgia Power related deferred equipment prepayments that ~~will be~~were expensed or capitalized ~~once utilized.~~in connection with a planned outage at Hatch Unit No. 1 in the first quarter of 2012. Also contributing to the decrease was a $5.1 million decrease in the amortized value of the intangible asset associated with

Table of Contents

the purchase and sale agreement with Georgia Power that was acquired as part of the 2011 Murray acquisition.

Equity and Liabilities

Long-term debt increased $862.5 million for the nine-month period ended 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 and $353.6 million in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans to permanently finance the Hartwell and Hawk Road acquisitions and other general improvements. In August 2011, we issued $300.0 million in first mortgage bonds for the purpose of 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 $34.0 million primarily as a result of scheduled debt maturities and the reclassification of certain long-term debt.~~

Short-term borrowings for the ~~nine-month~~three-month period ended ~~September 30, 2011 decreased $30.2~~March 31, 2012 increased $123.9 million. The ~~decrease~~increase was primarily due to the ~~repayment~~issuance of commercial paper ~~issued~~ to fund capital expenditures related to Vogtle Units No. 3 and No. ~~4 and to provide interim financing of the 2009 Hartwell and Hawk Road acquisitions.~~4.

Accounts payable decreased ~~$19.8~~$53.9 million in the ~~nine-month~~three-month period ended ~~September 30, 2011~~March 31, 2012 primarily due to a ~~$35.2 million~~ 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. ~~Offsetting the decrease was a $13.0~~

The $21.8 million increase in the payable for natural gas, primarily due to an increase in natural gas-fired generation at Murray and the Chattahoochee Energy Facility. At December 31, 2010, Chattahoochee was in an unplanned outage and did not resume operation until April 2011.

~~The $30.5 million decrease~~ in accrued interest for the ~~nine-month~~three-month period ended ~~September 30, 2011~~March 31, 2012 was due to the normal timing differences between interest payments and interest expense accruals.

Accrued ~~and withheld~~ taxes decreased ~~$4.9~~$12.7 million for the ~~nine-month~~three-month period ended ~~September 30, 2011~~March 31, 2012 as a result of payments made, when due, for ~~2010~~2011 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 ~~September 30, 2011, $50.1~~March 31, 2012, $66.2 million of member power bill prepayments was classified as a current liability and ~~$41.5~~$41.7 million of member power bill prepayments was classified as a long-term liability. During the ~~nine-month~~three-month period ended ~~September 30, 2011,~~March 31, 2012, approximately ~~$49.3~~$14.8 million of prepayments were received from the members and approximately ~~$70.2~~$9.3 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note JK 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 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

~~Table of Contents~~

RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our ~~2010~~2011 Form 10-K.

Vogtle Units No. 3 and No. 4. On September 27 and 28, 2011, the Nuclear Regulatory Commission held the mandatory hearing for the combined construction permits and operating licenses for Vogtle Units No. 3 and No. 4 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 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 to admit their contentions, should they again be denied by the Atomic Safety and Licensing Board. The remaining steps in the regulatory process are to address the status of these petitions and obtain Nuclear Regulatory Commission approvals of the AP1000 Design Certification Amendment and the combined construction permits and operating licenses which Georgia Power expects in late 2011. However, due to certain administrative procedural requirements, it is possible that the effective date of the 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 the second limited work authorization, which would allow Georgia Power to perform additional construction activities related to the nuclear island in 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,~~"Co-owners," and Westinghouse Electric Company LLC and Stone & Webster, Inc., the "Consortium," have ~~agreed to~~established both 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~~in accordance with the Engineering, Procurement and Construction Contract to bydesign, engineer, procure, construct, and test Vogtle Units No. 3 and No. 4 in order to resolve issues arising during the ~~parties. The Co-Owners~~course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, and the Consortium have successfully ~~used~~initiated both ~~the~~formal and informal ~~and formal~~claims through these procedures, including ongoing claims, to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

Table of Contents

During the course of construction activities, issues have arisen that may impact the project budget and schedule, including costs associated with design changes to the Westinghouse AP1000 Design Certification Document (DCD), and costs associated with delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses. Georgia Power, on behalf of the Co-owners, and the Consortium have begun negotiations regarding these issues, including the assertion by the Consortium that the Co-owners are responsible for these costs under the terms of the contract. In preliminary discussions, the Consortium provided its initial estimate of its proposed adjustment to the contract price. Based on our ownership interest, the Consortium's estimated adjustment attributable to us is approximately $250 million in 2008 dollars with respect to these issues, which includes an initial estimate of costs for efforts to maintain the projected in-service dates of 2016 and 2017 for Vogtle Units No. 3 and No. 4, respectively. Georgia Power, on behalf of the Co-owners, has not agreed with the amount of these proposed adjustments or that the Co-owners have responsibility for any costs related to these issues. Georgia Power expects negotiations with the Consortium to continue over the next several months during which time the parties will attempt to reach a mutually acceptable compromise of their positions. If a compromise cannot be reached, formal dispute resolution, including litigation, may follow. Georgia Power, on behalf of the Co-owners, intends to vigorously defend its positions. Additional claims by the Consortium or Georgia Power, on behalf of the Co-owners, are expected to arise throughout the construction of Vogtle Units No. 3 and No. 4.

In addition, there are processes in place to assure compliance with the design requirements specified in the DCD and the combined licenses, including rigorous inspection by Southern Nuclear Operating Company and the Nuclear Regulatory Commission that occurs throughout construction. A recent routine Nuclear Regulatory Commission inspection identified that certain details of the rebar construction in the Vogtle Unit No. 3 nuclear island were not consistent with the DCD. Georgia Power expects to receive official notice of these findings from the Nuclear Regulatory Commission. Georgia Power, on behalf of the Co-owners, is currently engaged in constructive discussions with the Consortium to identify appropriate corrective actions. Various inspection issues are expected as construction proceeds.

On February 16, 2012, a group of four plaintiffs who had intervened in the Nuclear Regulatory Commission's combined license proceedings for Vogtle Units No. 3 and No. 4 filed a petition in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review and a stay of the Commission's issuance of the combined licenses. In addition, on February 16, 2012, a group of nine plaintiffs filed a petition with the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the Commission's certification of the DCD. On April 3, 2012, the Court granted a motion filed by these two groups to consolidate their challenges. On April 18, 2012, another group of petitioners filed a motion to stay the effectiveness of the order issuing the combined licenses for Vogtle Units No. 3 and No. 4 with the U.S. District Court for the District of Columbia. Georgia Power, on behalf of the Co-owners, has filed a motion to intervene in these proceedings and intends to vigorously contest these petitions.

There are other pending technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. ~~4, including petitions filed at the Nuclear Regulatory Commission in response to the events in Japan.~~4. 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 September 30, 2011, our total capitalized costs to date for Vogtle Units No. 3 and No. 4 were $1.2 billion.~~

~~Events in Japan.~~ In March 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 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 Nuclear Regulatory Commission is performing additional operational and safety reviews of nuclear facilities in the United States, which could potentially impact future operations and capital requirements. 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. 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

~~Table of Contents~~

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 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~~2011 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.

~~Rate Matters.~~ ~~Our board~~As of ~~directors has approved two rate management programs, which we developed based on requests from members that have subscribed~~March 31, 2012, our total capitalized costs to ~~the Plant~~date for Vogtle ~~units under construction~~Units No. 3 and Murray. The first program allows members to expense rather than capitalize interest during construction on the Plant Vogtle units and the second program allows members to expense rather than defer the net costs associated with Murray. See Note LNo. 4 were $1.4 billion.

Table of Notes to Unaudited Condensed Financial Statements for a discussion of the deferral associated with Murray. Each subscribing member may elect to participate in one or both of these programs. The Plant Vogtle rate management program will be available starting in 2012 and allows each subscribing member to make an annual election to expense a percentage of its allocated portion of interest during construction for the year, although only current year costs may be expensed. The Murray rate management program will be available starting on December 31, 2011 and allows each subscribing member to make an annual election to expense a percentage of its allocated portion of Murray's monthly net costs for that year that would otherwise be deferred, and to elect once a year to expense any previously deferred net costs. The rate schedule changes required to implement these programs are 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.Contents

Environmental Regulations

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

On ~~August 8, 2011,~~April 13, 2012, EPA ~~finalized the Cross-State Air Pollution Rule, which contains~~published a proposed rule to create new ~~sulfur dioxide and nitrogen oxides emission reduction requirements~~source performance standards (NSPS) for ~~existing~~greenhouse gas emissions (specifically carbon dioxide) from certain new electric generating units ~~in most~~under section 111(b) of the ~~eastern United States,~~Clean Air Act. The proposed rule would apply to certain large, new fossil fuel-fired electric utility units, including ~~Georgia. For 2012, compliance with the~~boilers, integrated gasification combined cycle units and stationary combined cycle units. New units—those that commence construction after April 13, 2012—are covered, although a special exemption is provided to transitional sources, defined as those that have received certain air quality permit approvals and commence construction by April 13, 2013. The rule ~~may necessitate some combination of the purchase of emission allowances and/~~does not apply to existing units that undergo modifications or ~~the limiting of operations at Plant Scherer during off-peak 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 begin as currently scheduled on January 1, 2012. Although the ultimate outcome of the rule will depend on further rulemaking or the results of such challenges, the Cross-State Air Pollution Rulereconstructed sources. Hence, it is not expected to ~~have a significant~~ impact ~~on the operation of~~ our existing coal-fired plants or ~~financial condition.~~

combined cycle facilities. However, once EPA ~~has also proposed stringent~~promulgates a NSPS for a category of new ~~maximum achievable control technology (MACT)~~sources, it is required to establish guidelines requiring states to develop emission ~~limits~~standards for ~~certain hazardous air pollutants, including mercury, from coal- and oil-fired electric generating units (EGUs)~~the same category of existing sources. Thus, greenhouse gas NSPS for existing sources may be issued at some point in the ~~EGU MACT rule. Recently, all parties to the relevant consent decree and the court~~

~~Table of Contents~~

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

After its 2010 proposal of two alternative approaches for regulating coal combustion byproducts from electric utilities, regulation as either (i) "special wastes" under hazardous waste rules or (ii) as solid wastes, EPA continues to consider the numerous comments received from interested stakeholders and other members of the public. In October, EPA asked for further comments on certain data submitted during the original comment period. The ultimate impacts associated with EPA's coal combustion proposal cannot be determined with certainty at this time, and will depend on future rulemakings and possible Congressional action.future.

We cannot predict at this time the ultimate effects ~~these~~this proposed ~~and final regulations~~regulation 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 recent environmental regulations.~~ For further discussion regarding potential effects on our business from environmental regulations, ~~and~~including 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"~~REGULATION," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital ~~Requirements~~—Requirements—Capital Expenditures" in our ~~2010~~2011 Form 10-K.

Liquidity

At ~~September 30, 2011,~~March 31, 2012, we had ~~$1.8~~$1.5 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$410~~$402 million in cash and cash equivalents and ~~$1.4~~$1.1 billion of unused and available committed credit arrangements.

~~Table of Contents~~

On September 30, 2011, we completed the last component of our planned liquidity restructuring for 2011 by 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, 2011March 31, 2012, we had in excess of $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 9/30/2011		Expiration Date			Authorized Amount		Available 3/31/2012		Expiration Date

			(dollars in millions)							(dollars in millions)
*Unsecured Facilities:*	*Unsecured Facilities:*
	Syndicated Line of Credit⁽¹⁾	$	1,265	$	856	⁽²⁾	June 2015
	CFC Line of Credit		110		110		September 2016
	JPMorgan Chase Line of Credit		150		33	⁽³⁾	December 2013
Syndicated Line of Credit⁽¹⁾									$	1,265	$	544	⁽²⁾	June 2015
CFC Line of Credit										110		110		September 2016
JPMorgan Chase Line of Credit										150		33	⁽³⁾	December 2013
*Secured facilities:*	*Secured facilities:*
	CoBank Line of Credit		150		150		November 2012
	CFC Line of Credit		250		250		December 2013
CoBank Line of Credit										150		150		November 2012
CFC Line of Credit⁽⁴⁾										250		250		December 2013

Total	Total	$	1,925	$	1,399				$	1,925	$	1,087

⁽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, ~~$274~~$585 million is dedicated to support commercial paper we have issued and ~~$135~~$136 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.
⁽⁴⁾: This facility has a term loan option that can extend the maturity out to December 31, 2043.

Table of Contents

Between projected cash on hand and these credit arrangements, we believe we have sufficient liquidity to cover our normal operations and to provide interim financing for Vogtle Units No. 3 and No. 4.

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

~~Under~~We have the flexibility to use the syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up outstanding commercial ~~paper program, we~~paper. We can issue commercial paper in amounts that do not exceed the amount of any committed ~~lines~~backup line 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.~~outstanding.

Like the lines of credit from ~~CFC,~~National Rural Utilities Cooperative Finance Corporation (CFC), JPMorgan Chase Bank and CoBank, ACB, 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 $910 million in the aggregate, of which $658 million remained available at ~~September 30, 2011.~~March 31, 2012. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working

~~Table of Contents~~

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 ~~September 30, 2011,~~March 31, 2012, the required minimum level was $575 million and our actual patronage capital was ~~$635~~$647 million. Additional covenants contained in several of our credit facilities limit the amount of secured indebtedness and unsecured indebtedness we can have outstanding. At ~~September 30, 2011,~~March 31, 2012, the most restrictive of these covenants limits our secured indebtedness to $9.5 billion and our unsecured indebtedness to $4.0 billion. At ~~September 30, 2011,~~March 31, 2012, we had ~~$5.6~~$5.5 billion of secured indebtedness and ~~$627~~$845 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 ~~September 30, 2011,~~March 31, 2012, the balance of member prepayments received but not yet credited to their power bills was ~~$91.6~~$107.9 million. We expect to apply the prepayments against the participating members' power bills through November 2017, with the majority of the remaining balance scheduled to be applied by the end of ~~2012.~~2013. For more information regarding the power bill prepayment program, see Note JK of Notes to Unaudited Condensed Financial Statements.

At ~~September 30, 2011,~~March 31, 2012, current assets included ~~$105.8~~$110.5 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. On April 2, 2012, the account balance was reduced to $61.9 million as we utilized $48.6 million to pay our quarterly debt service payment due on that date.

Table of Contents

Financing Activities

First Mortgage Indenture. At ~~September 30, 2011,~~March 31, 2012, we had ~~$5.4~~$5.5 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our tangible and some of our intangible assets, including those we acquire in the future. See "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—First Mortgage Indenture" in our ~~2010~~2011 Form 10-K for a further discussion of our first mortgage indenture.

Bond Financing. ~~As disclosed in~~On April 2, 2012, we closed a ~~Current Report~~$32.4 million financing transaction that included two components. In one component the Development Authority of Monroe County issued, on ~~Form 8-K filed on August 17, 2011, in August we issued $300~~our behalf, $10.1 million of ~~taxable first mortgage~~term rate pollution control revenue bonds ~~primarily~~ for the purpose of ~~repaying outstanding commercial paper~~refinancing a like amount of pollution control revenue bonds previously issued ~~in connection with funding a portion of~~by the ~~cost of constructing Vogtle Units No. 3 and No. 4. The first mortgage bonds are~~authority on our behalf that had matured. This tax-exempt debt is secured under our first mortgage indenture. The second component entails a remarketing of $22.3 million of pollution control bonds issued previously on our behalf by the Development Authority of Burke County due to a mandatory tender of these bonds which were originally issued in a term rate period that ended March 31, 2012. Both components now bear interest in a term rate period that ends on February 28, 2013.

In a separate transaction on April 2, 2012, Georgia Transmission Corporation refinanced $40.2 million of pollution control bonds for which we were secondarily obligated. Upon this refinancing, we are no longer obligated for these bonds or any other of Georgia Transmission's debt obligations. For further discussion regarding our prior obligations related to Georgia Transmission, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION—Financial Condition—Off-Balance Sheet Arrangements—Georgia Transmission Debt Assumption" and Note 10 to "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2011 Form 10-K.

Rural Utilities Service-Guaranteed Loans. We have six approved Rural Utilities Service-guaranteed loans, being funded through the Federal Financing Bank, totaling ~~$1.67~~$1.7 billion that are in ~~the process~~various stages of being drawn down, with ~~$1.1~~$1.0 billion remaining to be advanced. ~~The~~When advanced, the debt will be secured under our first mortgage indenture.

~~Table of Contents~~

Department of Energy-Guaranteed ~~Loans.~~Loan. ~~We have~~The Department of Energy loan guarantee program was authorized pursuant to Title XVII of the Energy Policy Act of 2005, which is intended to support innovative technologies to reduce air pollutants, including greenhouse gases. Pursuant to this program, in May 2010 we signed a conditional term sheet with the Department of Energy that sets forth the general terms of a loan and related loan guarantee that would fund ~~approximately~~ 70% of the estimated $4.2 billion cost to construct our 30% undivided ~~interest in~~share of Vogtle Units No. 3 and No. 4, not to exceed $3.057 billion. ~~This~~The loan structure would beentail a loan that is funded by the Federal Financing Bank ~~guaranteed~~carrying a federal loan guarantee provided by the Department of Energy, ~~and~~with the debt secured under our first mortgage indenture.

~~We are working with the Department of Energy to finalize the loan guarantee, including the negotiation of definitive loan agreements. However, final~~Final approval and issuance of a loan guarantee by the Department of Energy is subject to ~~receipt~~negotiation of ~~the combined construction permits and operating licenses for Vogtle Units No. 3 and No. 4 from the Nuclear Regulatory Commission,~~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 ~~Vogtle Units No. 3 and No. 4~~project costs not funded under the Department of Energy loan guarantee program would be financed through the issuance of taxable bonds.

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 $1.15 billion through the issuance of first mortgage bonds.

Table of Contents

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~~and 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."~~"Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—Interest Rate Risk" in our 2011 Form 10-K.

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

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 be hedged. As of November 14, 2011, we have hedged interest rates on $1.4 billion of expected borrowings.Not Applicable.

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

~~Table of Contents~~

Department of Energy-guaranteed loan advances to be hedged; however, as the swaptions' value is independent from the 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 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 ~~September 30, 2011,~~March 31, 2012, 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.

Table of Contents

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.~~operations or cash flows.

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~~2011 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~~Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

Not Applicable.

Table of Contents

Item 6. Exhibits

		Description

~~31.1~~4.1		Sixty-Second Supplemental Indenture, dated as of April 1, 2012, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2012 A (Monroe) Note.
10.1	⁽¹⁾	Amendment No. 4, dated as of May 2, 2011, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(2) of Georgia Power Company's Form 10-Q for the quarterly period ended June 30, 2011, filed with the SEC on August 5, 2011.)
10.2	⁽¹⁾	Amendment No. 5, dated as of February 7, 2012, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(2) of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2012, filed with the SEC on May 7, 2012.)
31.1		Rule 13a-14(a)/15d-14(a) Certification, by Thomas A. Smith (Principal Executive Officer).
31.2		Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
32.1		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Thomas A. Smith (Principal Executive Officer).
32.2		Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
99.1		Member Financial and Statistical Information (for calendar years 2009-2011).
101		XBRL Interactive Data File.

⁽¹⁾: Confidential treatment has been requested for certain confidential portions of this exhibit pursuant to Rule 24b-2 under the Securities Exchange Act of 1934. In accordance with Rule 24b-2, these confidential portions have been omitted from this exhibit and filed separately with the SEC.

Table of Contents

SIGNATURES

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


		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: ~~November 14, 2011~~May 11, 2012	By:	/s/ Thomas A. Smith Thomas A. Smith President and Chief Executive Officer (Principal Executive Officer)
Date: ~~November 14, 2011~~May 11, 2012		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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

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

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

Total comprehensive margin								36,937


Balance at September 30, 2010		$	598,071	$	(168	)	$	597,903

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

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

Total comprehensive margin								40,569


Balance at September 30, 2011		$	635,188	$	864		$	636,052


			Three Months Ended September 30, 2010

			Decommissioning funds			Long-term investments

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

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


			Nine Months Ended September 30, 2011

			Decommissioning funds			Long-term investments

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

Balance at September 30, 2011		$	(1,032	)	$	7,698


Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses
		Statement of Revenues and Expenses Location		Three months ended			Nine months ended

				(dollars in thousands)
Designated as hedges under authoritative guidance related to derivatives and hedging activities
	Natural Gas Swaps	Purchase power	$	99		$	195
	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		927			1,997
	Nuclear decommissioning trust	Investment income		(661	)		(1,233	)

Total losses on derivatives			$	(1,804	)	$	(2,465	)

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



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

Total identifiable net assets	$	530.3