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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, 2014~~March 31, 2015
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 Companyo

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

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

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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED ~~SEPTEMBER 30, 2014~~MARCH 31, 2015

		Page No.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Condensed Balance Sheets as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014	1
	Unaudited Condensed Statements of Revenues and Expenses For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~	3
	Unaudited Condensed Statements of Comprehensive Margin For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~	4
	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, 2015 and 2014 ~~and 2013~~	5
	Unaudited Condensed Statements of Cash Flows For the ~~Nine~~Three Months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~	6
	Notes to Unaudited Condensed Financial Statements For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2422
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3327
Item 4.	Controls and Procedures	3327
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	3428
Item 1A.	Risk Factors	3528
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3528
Item 3.	Defaults Upon Senior Securities	3528
Item 4.	Mine Safety Disclosures	3528
Item 5.	Other Information	3528
Item 6.	Exhibits	3528
SIGNATURES		3629

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CAUTIONARY ~~STATEMENTS~~STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS ~~AND ASSOCIATED RISKS~~

This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under the heading "RISK FACTORS" ~~in our quarterly report for the quarterly period ended June 30, 2014 and under the heading "RISK FACTORS"~~ and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, ~~2013.~~2014. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•: cost increases and schedule delays with respect to our capital improvement and construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;
•: ~~legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;~~
•: costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;
•: the regulation of carbon dioxide emissions, such as the proposed Clean Power Plan or other potential legislative and regulatory responses to climate change initiatives ~~including the regulation of carbon dioxide and~~or efforts to reduce other greenhouse gas emissions;
•: legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;
•: increasing debt caused by significant capital expenditures which is weakening certain of our financial metrics;
•: commercial banking and financial market conditions;
•: our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;
•: uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy for construction of two additional nuclear units at Plant Vogtle;
•: actions by credit rating agencies;
•: risks and regulatory requirements related to the ownership and construction of nuclear facilities;

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•: adequate funding of our nuclear decommissioning trust fund including investment performance and projected decommissioning costs;
•: ~~weather conditions and other natural phenomena;~~
•: continued efficient operation of our generation facilities by us and third-parties;
•: the availability of an adequate and economical supply of fuel, water and other materials;
•: reliance on third-parties to efficiently manage, distribute and deliver generated electricity;
•: acts of sabotage, wars or terrorist activities, including cyber attacks;
•: litigation or legal and administrative proceedings and settlements;
•: the credit quality and/or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;
•: our members' ability to perform their obligations to us;
•: ~~litigation or legal and administrative proceedings and settlements;~~
•: changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;
•: changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our ~~competitors;~~members' service territories;
•: general economic conditions;
•: weather conditions and other natural phenomena;
•: unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation efforts and the general economy;
•: unanticipated changes in interest rates or rates of inflation;
•: significant changes in our relationship with our employees, including the availability of qualified personnel;
•: unanticipated changes in capital expenditures, operating expenses and liquidity needs;
•: significant changes in critical accounting policies material to us; and
•: hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.

iii

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

~~Oglethorpe Power Corporation~~
~~Condensed Balance Sheets (Unaudited)~~
~~September 30, 2014 and December 31, 2013~~

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
March 31, 2015 and December 31, 2014


		(dollars in thousands)						(dollars in thousands)
	2014			2013			2015			2014
Assets
Electric plant:
In service	$	8,307,346		$	8,050,103		$	8,368,040		$	8,345,241
Less: Accumulated provision for depreciation		(3,729,922	)		(3,615,375	)		(3,801,533	)		(3,762,690	)


		4,577,424			4,434,728			4,566,507			4,582,551
Nuclear fuel, at amortized cost		339,697			341,012			365,506			369,529
Construction work in progress		2,277,147			2,212,224			2,465,420			2,374,392


		7,194,268			6,987,964
								7,397,433			7,326,472

Investments and funds:
Nuclear decommissioning trust fund		355,832			343,698			374,575			366,004
Investment in associated companies		65,496			66,437			68,745			67,368
Long-term investments		83,689			81,720			87,836			85,728
Restricted cash and investments		96,432			34,975			118,976			118,390
Other		16,884			16,098			18,036			17,397


		618,333			542,928
								668,168			654,887

Current assets:
Cash and cash equivalents		312,206			408,193			271,704			237,391
Restricted cash and short-term investments		247,699			272,686
Restricted short-term investments								251,725			247,057
Receivables		134,573			128,992			119,895			130,366
Inventories, at average cost		263,795			286,168			252,818			270,849
Prepayments and other current assets		31,439			16,894			42,840			12,667


		989,712			1,112,933
								938,982			898,330

Deferred charges:
Deferred debt expense, being amortized		98,695			57,175			98,530			97,902
Regulatory assets		412,456			331,108			507,496			484,049
Other		51,786			63,104			86,646			84,603

								692,672			666,554

		562,937			451,387		$	9,697,255		$	9,546,243


	$	9,365,250		$	9,095,212

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

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~~Oglethorpe Power Corporation~~
~~Condensed Balance Sheets (Unaudited)~~
~~September 30, 2014 and December 31, 2013~~

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
March 31, 2015 and December 31, 2014


		(dollars in thousands)					(dollars in thousands)
	2014		2013			2015		2014
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	765,361	$	714,489		$	776,493	$	761,124
Accumulated other comprehensive margin (deficit)		160		(549	)

Accumulated other comprehensive margin							421		468

		765,521		713,940			776,914		761,592
Long-term debt		6,881,522		6,817,518			7,196,761		7,113,000
Obligation under capital leases		102,280		121,731			100,456		100,456
Other		16,166		15,379			16,708		16,434


		7,765,489		7,668,568
							8,090,839		7,991,482

Current liabilities:
Long-term debt and capital leases due within one year		299,960		152,153			161,502		160,754
Short-term borrowings		264,624		279,407			343,729		234,369
Accounts payable		67,809		101,529			39,071		98,337
Accrued interest		52,837		58,193			53,138		58,841
Member power bill prepayments, current		100,430		82,405			184,446		166,013
Other current liabilities		45,354		42,253			38,574		70,748


		831,014		715,940
							820,460		789,062

Deferred credits and other liabilities:
Gain on sale of plant, being amortized		21,047		22,157			20,306		20,676
Asset retirement obligations		426,212		408,050			438,510		432,260
Member power bill prepayments, non-current		71,819		32,313			37,240		31,941
Power sale agreement, being amortized		16,028		26,107			9,501		12,669
Regulatory liabilities		167,250		158,789			202,232		194,073
Other		66,391		63,288			78,167		74,080

							785,956		765,699

		768,747		710,704		$	9,697,255	$	9,546,243


	$	9,365,250	$	9,095,212

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

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~~Oglethorpe Power Corporation~~
~~Condensed Statements of Revenues and Expenses (Unaudited)~~
~~For the Three and Nine Months Ended September 30, 2014 and 2013~~

Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three Months Ended March 31, 2015 and 2014


		(dollars in thousands)												(dollars in thousands)
	Three Months						Nine Months						Three Months
	2014			2013			2014			2013			2015			2014
Operating revenues:
Sales to Members	$	338,740		$	315,646		$	1,011,615		$	908,490		$	308,776		$	334,759
Sales to non-Members		30,665			34,079			81,073			71,498			31,002			32,541


Total operating revenues		369,405			349,725			1,092,688			979,988			339,778			367,300


Operating expenses:
Fuel		147,314			138,252			413,566			351,467			108,409			132,276
Production		95,570			88,689			302,658			272,703			114,759			108,084
Depreciation and amortization		41,784			40,779			123,902			116,440			42,652			40,714
Purchased power		15,603			12,989			51,981			40,373			13,631			20,066
Accretion		6,198			5,755			18,324			17,062			6,382			6,018
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		(7,749	)		(7,005	)		(27,885	)		(25,672	)

Deferral of Hawk Road and Smith Energy
Facilities effect on net margin														(14,315	)		(9,715	)

Total operating expenses		298,720			279,459			882,546			772,373			271,518			297,443


Operating margin		70,685			70,266			210,142			207,615			68,260			69,857


Other income:
Investment income		8,494			8,353			26,921			23,778			9,849			9,282
Other		1,956			2,317			6,565			6,834			2,859			2,377


Total other income		10,450			10,670			33,486			30,612			12,708			11,659


Interest charges:
Interest expense		88,395			80,569			256,277			232,597			87,707			81,917
Allowance for debt funds used during construction		(25,921	)		(23,597	)		(76,035	)		(73,013	)		(26,253	)		(23,729	)
Amortization of debt discount and expense		4,208			3,860			12,514			12,013			4,145			4,105


Net interest charges		66,682			60,832			192,756			171,597			65,599			62,293


Net margin	$	14,453		$	20,104		$	50,872		$	66,630		$	15,369		$	19,223

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

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~~Oglethorpe Power Corporation~~
~~Condensed Statements of Comprehensive Margin (Unaudited)~~
~~For the Three and Nine Months Ended September 30, 2014 and 2013~~

Oglethorpe Power Corporation
Condensed Statements of Comprehensive Margin (Unaudited)
For the Three Months Ended March 31, 2015 and 2014


		(dollars in thousands)										(dollars in thousands)
	Three Months					Nine Months					Three Months
	2014			2013		2014		2013			2015			2014
Net margin	$	14,453		$	20,104	$	50,872	$	66,630		$	15,369		$	19,223


Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities		(118	)		205		709		(1,097	)

Unrealized (loss) gain on available-for-sale securities												(47	)		396

Total comprehensive margin	$	14,335		$	20,309	$	51,581	$	65,533		$	15,322		$	19,619

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

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~~Oglethorpe Power Corporation~~
~~Condensed Statements of Patronage Capital and Membership Fees~~
~~and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)~~
~~For the Nine Months Ended September 30, 2014 and 2013~~

Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the Three Months Ended March 31, 2015 and 2014

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

		(dollars in thousands)								(dollars in thousands)
Balance at December 31, 2012	$	673,009	$	903		$	673,912

Components of comprehensive margin:
Net margin		66,630		—			66,630
Unrealized (loss) on available-for-sale securities		—		(1,097	)		(1,097	)

Balance at September 30, 2013	$	739,639	$	(194	)	$	739,445

Balance at December 31, 2013	$	714,489	$	(549	)	$	713,940		$	714,489	$	(549	)	$	713,940


Components of comprehensive margin:
Net margin		50,872		—			50,872			19,223		—			19,223
Unrealized gain on available-for-sale securities		—		709			709			—		396			396

Balance at September 30, 2014	$	765,361	$	160		$	765,521


Balance at March 31, 2014									$	733,712	$	(153	)	$	733,559

Balance at December 31, 2014									$	761,124	$	468		$	761,592

Components of comprehensive margin:
Net margin										15,369		—			15,369
Unrealized loss on available-for-sale securities										—		(47	)		(47	)

Balance at March 31, 2015									$	776,493	$	421		$	776,914

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

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~~Oglethorpe Power Corporation~~
~~Condensed Statements of Cash Flows (Unaudited)~~
~~For the Nine Months Ended September 30, 2014 and 2013~~

Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the Three Months Ended March 31, 2015 and 2014


		(dollars in thousands)						(dollars in thousands)
	2014			2013			2015			2014
Cash flows from operating activities:
Net margin	$	50,872		$	66,630		$	15,369		$	19,223


Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		233,041			218,425			76,642			74,880
Accretion cost		18,324			17,062			6,382			6,018
Amortization of deferred gains		(1,341	)		(1,341	)		(447	)		(447	)
Allowance for equity funds used during construction		(968	)		(1,938	)		(173	)		(389	)
Deferred outage costs		(41,931	)		(33,347	)		(17,169	)		(25,845	)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		(27,885	)		(25,672	)		(14,315	)		(9,715	)
Gain on sale of investments		(13,384	)		(21,694	)		(4,687	)		(3,996	)
Regulatory deferral of costs associated with nuclear decommissioning		2,690			10,652			1,222			(84	)
Other		11,967			(5,416	)		6,448			1,384
Change in operating assets and liabilities:
Receivables		(5,300	)		(2,995	)		10,471			(1,799	)
Inventories		22,373			(13,684	)		18,031			24,827
Prepayments and other current assets		(15,299	)		(234	)		(30,174	)		1,892
Accounts payable		4,493			(76,892	)		(39,364	)		(33,330	)
Accrued interest		(5,356	)		(9,292	)		(5,703	)		(8,804	)
Accrued taxes		4,628			19,601			(8,914	)		(13,144	)
Other current liabilities		(4,109	)		(4,264	)		(10,545	)		(2,075	)
Member power bill prepayments		57,531			2,091			23,732			12,105


Total adjustments		239,474			71,062			11,437			21,478


Net cash provided by operating activities		290,346			137,692			26,806			40,701


Cash flows from investing activities:
Property additions		(428,585	)		(414,493	)		(165,397	)		(134,354	)
Activity in decommissioning fund—Purchases		(101,090	)		(479,622	)
Activity in nuclear decommissioning trust fund—Purchases								(111,750	)		(101,894	)
—Proceeds		97,475			475,446			110,666			100,648
Decrease (increase) in restricted cash and investments		(61,457	)		(22,111	)
Decrease (increase) in restricted cash and short-term investments		24,987			(190,184	)
(Increase) decrease in restricted cash and investments								(586	)		24,239
Increase in restricted cash and short-term investments								(4,668	)		(16,783	)
Activity in other long-term investments—Purchases		(17,006	)		(34,510	)		(12,045	)		(12,220	)
—Proceeds		17,394			36,753			11,214			12,413
Activity on interest rate options—Collateral returned		(81,070	)		(146,730	)		—			(46,940	)
—Collateral received		46,100			168,840			—			22,700
Other		(3,053	)		11,563			(5,278	)		(401	)


Net cash used in investing activities		(506,305	)		(595,048	)		(177,844	)		(152,592	)


Cash flows from financing activities:
Long-term debt proceeds		1,009,320			875,640			113,718			734,608
Long-term debt payments		(369,253	)		(313,983	)		(37,319	)		(295,740	)
(Decrease) increase in short-term borrowings, net		(479,783	)		34,332
Increase (decrease) in short-term borrowings, net								109,360			(474,720	)
Other		(40,312	)		(559	)		(408	)		(41,957	)


Net cash provided by financing activities		119,972			595,430

Net cash provided by (used in) financing activities								185,351			(77,809	)

Net decrease in cash and cash equivalents		(95,987	)		138,074
Net increase (decrease) in cash and cash equivalents								34,313			(189,700	)
Cash and cash equivalents at beginning of period		408,193			298,565			237,391			408,193


Cash and cash equivalents at end of period	$	312,206		$	436,639		$	271,704		$	218,493





Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	182,059		$	165,388		$	69,258		$	65,816
Supplemental disclosure of non-cash investing and financing activities:
Change in plant expenditures included in accounts payable	$	(33,157	)	$	19,488		$	(22,510	)	$	6,463

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

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Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three ~~and Nine~~ Months ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~

(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, 2014~~March 31, 2015 and ~~2013.~~2014. 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, ~~2013,~~2014, as filed with the SEC. The results of operations for the ~~three- and nine- month~~three-month periods ended ~~September 30, 2014~~March 31, 2015 are not necessarily indicative of results to be expected for the full year. As noted in our ~~2013~~2014 Form 10-K, our revenues consist primarily of sales to our 38 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 ~~2013~~2014 Form 10-K.)

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

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

•: Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.
•: Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.
•: Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:
1.Market ~~approach~~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 at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013.~~2014.

Fair Value Measurements at Reporting Date Using

March 31,
2015

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

Significant Other
Observable
Inputs

(Level 2)

Significant
Unobservable
Inputs

(Level 3)

Fair Value Measurements at Reporting Date Using

September 30,
2014

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)
Nuclear decommissioning trust funds:

Domestic equity
$ 151,485 $ 151,485 $ — $ — $ 163,991 $ 163,991 $ — $ —
International equity trust
72,518 — 72,518 — 74,705 — 74,705 —
Corporate bonds
39,713 — 39,713 — 18,298 — 18,298 —
US Treasury and government agency securities
62,440 62,440 — — 70,197 70,197 — —
Agency mortgage and asset backed securities
16,736 — 16,736 — 14,957 — 14,957 —
Municipal bonds
19,565 — 19,565 —
Other
12,940 12,940 — — 12,862 12,862 — —
Long-term investments:

International equity trust
11,166 — 11,166 — 11,508 — 11,508 —
Corporate bonds
6,558 — 6,558 — 6,135 — 6,135 —
US Treasury and government agency securities
13,933 13,933 — — 17,129 17,129 — —
Agency mortgage and asset backed securities
570 — 570 — 870 — 870 —
Mutual funds
51,045 51,045 — — 51,932 51,932 — —
Other
417 417 — — 262 262 — —
Interest rate options
13,110 — — 13,110 ⁽¹⁾ 2,702 — — 2,702
Natural gas swaps
(1,764 ) — (1,764 ) — 21,096 — 21,096 —

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Fair Value Measurements at Reporting Date Using

December 31,
2013

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

Significant Other
Observable
Inputs

(Level 2)

Significant
Unobservable
Inputs

(Level 3)

(dollars in thousands)
Nuclear decommissioning trust funds:

Domestic equity
$ 143,929 $ 143,929 $ — $ —
International equity trust
72,466 — 72,466 —
Corporate bonds
39,863 — 39,863 —
US Treasury and government agency securities
44,846 44,846 — —
Agency mortgage and asset backed securities
30,133 — 30,133 —
Municipal Bonds
641 — 641 —
Other
11,820 11,820 — —
Long-term investments:

Corporate bonds
6,487 — 6,487 —
US Treasury and government agency securities
8,563 8,563 — —
Agency mortgage and asset backed securities
3,679 — 3,679 —
International equity trust
11,148 — 11,148 —
Mutual funds
51,559 51,559 — —
Other
284 284 — —
Interest rate options
63,471 — — 63,471 ⁽¹⁾
Natural gas swaps
1,011 — 1,011 —

⁽¹⁾
Interest rate options as reflected on the unaudited condensed Balance Sheet include the fair value of the interest rate options offset by $0 and $34,970,000 of collateral received from the counterparties at September 30, 2014 and December 31, 2013, respectively.

Fair Value Measurements at Reporting Date Using

December 31,
2014

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

Significant Other
Observable
Inputs

(Level 2)

Significant
Unobservable
Inputs

(Level 3)

(dollars in thousands)
Nuclear decommissioning trust funds:

Domestic equity
$ 159,536 $ 159,536 $ — $ —
International equity trust
72,474 — 72,474 —
Corporate bonds
34,446 — 34,446 —
US Treasury and government agency securities
68,854 68,854 — —
Agency mortgage and asset backed securities
16,148 — 16,148 —
Municipal Bonds
743 — 743 —
Other
13,803 13,803 — —
Long-term investments:

Corporate bonds
5,445 — 5,445 —
US Treasury and government agency securities
16,619 16,619 — —
Agency mortgage and asset backed securities
643 — 643 —
International equity trust
11,162 — 11,162 —
Mutual funds
51,741 51,741 — —
Other
118 118 — —
Interest rate options
4,371 — — 4,371
Natural gas swaps
18,914 — 18,914 —

The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.

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The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 and ~~2013.~~2014.

Three Months Ended
March 31, 2015

Three Months Ended
September 30, 2014
Interest rate options

Interest rate options

(dollars in thousands) (dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2014 $ 18,535
Balance at December 31, 2014 $ 4,371
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)
(5,425 ) (1,669 )

Balance at September 30, 2014 $ 13,110

Balance at March 31, 2015 $ 2,702

Three Months Ended
September 30, 2013

Interest rate options

(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2013 $ 43,680
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)
(149 )

Balance at September 30, 2013 $ 43,531

Nine Months Ended
September 30, 2014

Interest rate options

(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2013 $ 63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)
(50,361 )

Balance at September 30, 2014 $ 13,110

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Three Months Ended
March 31, 2014

Nine Months Ended
September 30, 2013
Interest rate options

Interest rate options

(dollars in thousands) (dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2012 $ 25,783
Balance at December 31, 2013 $ 63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)
17,748 (32,008 )

Balance at September 30, 2013 $ 43,531

Balance at March 31, 2014 $ 31,463

We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. 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. For additional information regarding our interest rate options, see Note C.

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The estimated fair values of our long-term debt, including current maturities at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 were as follows (in thousands):

2014

2013

Carrying
Value Fair
Value Carrying
Value Fair
Value

Long-term debt $ 7,157,870 $ 7,983,009 $ 6,954,293 $ 7,317,476

2015

2014

Carrying
Value Fair
Value Carrying
Value Fair
Value

Long-term debt $ 7,344,321 $ 8,713,348 $ 7,256,995 $ 8,460,685

The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party ~~subscription service,~~data provider, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of ~~September 30, 2014~~March 31, 2015 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. ~~We use an interest rate quote sheet provided by~~

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~~CoBank for valuation of the CoBank debt, which reflects current rates for a similar loan.~~ The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for a similar loan.
For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.
(C)
Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on long-term debt in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.
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 through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and 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 counterparties. 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, 2014,~~March 31, 2015, all of the counterparties with transaction amounts outstanding under our hedging 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.
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

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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 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 ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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Gas hedges.Under our 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, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, the fair value of our natural gas contracts ~~were~~was a net liability of approximately ~~$1,764,000~~$21,096,000 and ~~$1,011,000,~~$18,914,000, respectively.
As of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, neither we nor any counterparties were required to post credit support or collateral under these natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on ~~September 30, 2014~~March 31, 2015 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit in the amount of ~~$2,022,000~~$21,096,000 with our counterparties.
The following table reflects the volume activity of our natural gas derivatives as of ~~September 30, 2014~~March 31, 2015 that is expected to settle or mature each year:

Year

Natural Gas Swaps
(MMBTUs)
(in millions)

Natural Gas Swaps
(MMBTUs)
(in millions)

2014
0.4

2015
7.9 19.0
2016
5.4 11.0

2017
2.8

Total
14.3 32.8

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Interest rate options.    We are exposed to the risk of rising interest rates ~~when we incur~~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. In ~~the~~ fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since ~~2013,~~inception, swaptions having a notional amount of approximately ~~$1,174,248,000~~$1,433,078,000 have expired and as of ~~September 30, 2014,~~March 31, 2015 the remaining notional amount of our outstanding swaptions was approximately ~~$1,004,955,000.~~$746,126,000.
The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average ~~107~~177 basis points above the corresponding LIBOR swap rates that were in effect as of ~~September 30, 2014~~March 31, 2015, and the weighted average fixed rate is ~~4.08%~~4.02%. Swaptions having notional amounts totaling ~~$419,796,000~~$115,201,000 expired without value during the ~~nine~~three months ended ~~September 30, 2014.~~March 31, 2015. The remaining swaptions expire quarterly through 2017.
We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these ~~transactions and have no additional payment obligations. These derivatives are recorded at fair~~

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~~value.~~transactions. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, the fair value of these swaptions was approximately ~~$13,110,000~~$2,702,000 and ~~$63,471,000,~~$4,371,000, respectively. To manage our credit exposure to our 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 can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of ~~September 30, 2014,~~March 31, 2015 and December 31, ~~2013, we held $0 and $34,970,000 of funds posted as~~2014, there were no collateral postings made by the counterparties, respectively. The collateral received is recorded as restricted cash on our balance sheet. The liability associated with the collateral is recorded as an offset to the fair values of the swaptions, which are recorded within other deferred charges on the balance sheet, resulting in a net carrying amount of the interest rate options of $13,110,000 and $28,501,000 at September 30, 2014 and December 31, 2013, respectively.
We are deferring unrealized gains or losses from the change in fair value of each LIBOR swaption and related carrying and other incidental costs in accordance with our rate-making treatment. The realized 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 ~~$2.2 billion~~$2,200,000,000 of debt that we hedged with the swaptions.
The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of ~~September 30, 2014.~~March 31, 2015.

Year

LIBOR Swaption
Notional Dollar
Amount
(in thousands)

LIBOR Swaption
Notional Dollar
Amount
(in thousands)

2014
$ 143,629

2015
470,624 $ 355,424
2016
310,533 310,533
2017
80,169 80,169

Total
$ 1,004,955 $ 746,126

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The table below reflects the fair value of derivative instruments and their effect on our ~~condensed~~consolidated balance sheets at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013.~~2014.

Balance Sheet
Location

Fair Value

Balance Sheet
Location

Fair Value

2014 2013 2015 2014

(dollars in thousands)

(dollars in thousands)

Not designated as hedges:

Assets:

Interest rate options⁽¹⁾
Other deferred charges $ 13,110 $ 63,471 Other deferred charges $ 2,702 $ 4,371
Natural gas swaps
Other current assets $ 258 $ 1,011
Liabilities:

Natural gas swaps
Other current liabilities $ 2,022 $ — Other current liabilities $ 12,241 $ 13,418

Natural gas swaps
Other deferred credits 8,855 5,496

⁽¹⁾
Excludes liability associated with cash collateral of $0 and $34,970,000 as of September 30, 2014 and December 31, 2013, respectively, which is recorded as an offset to the fair value of the swaptions on the unaudited condensed balance sheets.

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The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015 and ~~2013.~~2014.

Statement of
Revenues and
Expenses

Three months ended
September 30,

Nine months ended
September 30,

Location 2014 2013 2014 2013

(dollars in thousands)
Not Designated as hedges:

Natural Gas Swaps

Fuel

$
638
$
122
$
1,874
$
688
Natural Gas Swaps
Fuel (889 ) (3,089 ) (890 ) (4,002 )

$ (251 ) $ (2,967 ) $ 984 $ (3,314 )
Statement of
Revenues and
Expenses

Three months ended
March 31,

Location 2015 2014

(dollars in thousands)
Not Designated as hedges:

Natural Gas Swaps
Fuel $ — $ 279
Natural Gas Swaps
Fuel (5,527 ) —

$ (5,527 ) $ 279

The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013.~~2014.

Balance Sheet
Location

2015

2014

Balance Sheet
Location

2014

2013

(dollars in thousands) (dollars in thousands)
Not designated as hedges:
Not designated as hedges:

Not designated as hedges:

Natural gas swaps

Regulatory liability

$
—
$
1,011
Regulatory asset

$
(21,096
)
$
(18,914
)
Natural gas swaps
Regulatory asset $ (1,764 ) $ —
Interest rate options
Regulatory asset (47,598 ) (15,003 ) Regulatory asset (44,845 ) (49,232 )

Total not designated as hedges
$ (65,941 ) $ (68,146 )

$ (49,362 ) $ (13,992 )

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The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral.

Gross Amounts
of Recognized
Assets
(Liabilities)

Gross
Amounts
offset on the
Balance Sheet

Cash
Collateral

Net Amounts of
Assets Presented on
the Balance Sheet

Gross Amounts
of Recognized
Assets
(Liabilities)

Gross
Amounts
offset on the
Balance Sheet

Cash
Collateral

Net Amounts of
Assets Presented on
the Balance Sheet
(dollars in thousands)

(dollars in thousands)
September 30, 2014
March 31, 2015
Assets:
Natural gas swaps
$ 261 $ (2,025 ) $ — $ (1,764 ) $ (21,096 ) $ — $ — $ (21,096 )
Interest rate options
$ 13,110 $ — $ — $ 13,110 $ 47,547 $ (44,845 ) $ — $ 2,702

December 31, 2013

December 31, 2014

Assets:
Natural gas swaps
$ 1,069 $ (58 ) $ — $ 1,011 $ (18,914 ) $ — $ — $ (18,914 )
Interest rate options
$ 63,471 $ — $ (34,970 ) $ 28,501 $ 53,603 $ (49,232 ) $ — $ 4,371

(D)
Investments in Debt and Equity Securities.    Investment securities we hold are classified as 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 other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear

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decommissioning funds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. As of ~~September 30, 2014,~~March 31, 2015, approximately ~~79%~~89% of these gross unrealized losses ~~were in effect~~had been unrealized for a duration of less than one year.
The following tables summarize the activities for available-for-sale securities as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013.~~2014.

Gross Unrealized

Gross Unrealized
(dollars in thousands)
(dollars in thousands)
September 30, 2014 Cost Gains Losses Fair
Value

March 31, 2015 Cost Gains Losses Fair
Value

Equity $ 196,523 $ 64,560 $ (2,185 ) $ 258,898 $ 206,199 $ 71,575 $ (1,926 ) $ 275,848
Debt 166,710 9,159 (8,417 ) 167,452 170,276 11,244 (8,082 ) 173,438
Other 13,173 — (2 ) 13,171 13,128 — (3 ) 13,125

Total $ 376,406 $ 73,719 $ (10,604 ) $ 439,521 $ 389,603 $ 82,819 $ (10,011 ) $ 462,411

Gross Unrealized

Gross Unrealized
(dollars in thousands)
(dollars in thousands)
December 31, 2013 Cost Gains Losses Fair
Value

December 31, 2014 Cost Gains Losses Fair
Value

Equity $ 182,755 $ 68,424 $ (1,053 ) $ 250,126 $ 200,892 $ 69,536 $ (2,163 ) $ 268,265
Debt 164,941 7,319 (9,070 ) 163,190 168,182 9,981 (8,619 ) 169,544
Other 12,101 2 — 12,103 13,927 — (4 ) 13,923

Total $ 359,797 $ 75,745 $ (10,123 ) $ 425,419 $ 383,001 $ 79,517 $ (10,786 ) $ 451,732

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(E)
Recently Issued or Adopted Accounting Pronouncements.In May 2014, the Financial Accounting Standards Board issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 ~~and early~~using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted.
On April 1, 2015, the FASB proposed deferring the effective date by one year. Under the proposal, the standard would be effective for annual reporting periods beginning after December 15, 2017. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016.
We are currently evaluating the future impact of this standard to our consolidated financial position or results of operations.
In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30); Simplifying the Presentation of Debt Issuance Costs. The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in the standard are effective for the financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We are currently evaluating the impact of adoption on our consolidated financial position or results of operations.
(F)
Accumulated Comprehensive Margin (Deficit).    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Condensed Statements of Patronage Capital and Membership Fees and 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 ~~2013~~2014 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Condensed Statement of Revenues and Expenses.

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

Accumulated Other
Comprehensive Margin
(Deficit)
Three Months Ended

(dollars in thousands)

Available-for-sale Securities

Balance at June 30, 2013
$ (399 )
Unrealized gain

181
Loss reclassified to net margin

24

Balance at September 30, 2013
$ (194 )

Balance at June 30, 2014

$
278
Unrealized (loss)

(100
)
(Gain) reclassified to net margin

(18
)

Balance at September 30, 2014
$ 160

Nine Months Ended

(dollars in thousands)

Available-for-sale
Securities

Balance at December 31, 2012
$ 903
Unrealized (loss)

(1,041
)
(Gain) reclassified to net margin

(56
)

Accumulated Other
Comprehensive Margin
(Deficit)
Three Months Ended

Balance at September 30, 2013
$ (194 )

(dollars in thousands)

Available-for-sale
Securities

Balance at December 31, 2013

$
(549
) $ (549 )
Unrealized gain

782
390
Loss reclassified to net margin

6

Balance at March 31, 2014
$ (153 )

Balance at December 31, 2014

$
468
Unrealized gain

107
(Gain) reclassified to net margin

(73
)
(154
)

Balance at March 31, 2015
$ 421

Balance at September 30, 2014
$ 160

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(G)
Contingencies and Regulatory Matters.
We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.
a.    Nuclear Construction
In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (the EPC Agreement) to design, engineer, procure, construct and ~~construct~~test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).
Under the ~~agreement,~~EPC Agreement for Vogtle Units No. 3 and No. 4, the ~~Co-Owners~~Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
~~Current litigation relates to~~In July 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the Westinghouse AP1000 Design Control 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 by the Nuclear Regulatory ~~Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs,~~Commission, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the ~~agreement.~~EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In ~~September 2013, the Contractor appealed the decision to~~March 2015, the U.S. Court of Appeals for the District of ~~Columbia.~~
Columbia affirmed this dismissal which means the case will be tried in the U.S. District Court for the Southern District of Georgia. The portion of the additional costs claimed by the Contractor ~~in its initial complaint~~ that would be attributable to us, based on our ownership interest, ~~was~~is approximately ~~$280 million~~$280,000,000 in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to ~~further schedule extensions.~~extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the ~~agreement~~EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the ~~agreement.~~EPC Agreement. The Contractor did not specify ~~in its amended counterclaim the~~ amounts relating to these new allegations ~~but~~in its amended counterclaim; however, the Contractor has subsequently asserted ~~and~~related minimum damages, based on our ownership interest, of approximately $75,000,000. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not

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agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.

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~~While litigation~~ Litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their ~~positions,~~positions. Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.
If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of ~~September 30, 2014,~~March 31, 2015, no material amounts have been recorded related to this claim. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.
b.    Patronage Capital Litigation
On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. ~~See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2013 Form 10-K.~~ Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.
On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two ~~alleged~~ current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level

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~~rates to a level~~ where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.
We intend to defend vigorously against all claims in the above-described litigation.
c.    Environmental Matters
As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.
In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.
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.
Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.
(H)
Restricted Cash and Investments.    ~~At September 30, 2014 and December 31, 2013, we had restricted~~Restricted cash and investments ~~totaling $344,131,000 and $307,661,000, respectively,~~primarily consist of which $96,432,000 and $34,975,000, respectively, was classified as long-term. Restricted cash balances consist primarily of funds posted as collateral by counterparties to our interest rate options. Restricted investments represent funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At March 31, 2015 and December 31, 2014, we had restricted cash and investments totaling $370,838,000 and $365,585,000, respectively, of which $118,976,000 and $118,390,000, respectively, were classified as long-term.
(I)
Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through

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December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the unaudited condensed balance sheet as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013.~~2014.

2015 2014

(dollars in thousands)

2014 2013

(dollars in thousands)

Regulatory Assets:

Premium and loss on reacquired debt^(a)
$ 74,415 $ 82,499 $ 69,277 $ 71,731
Amortization on capital leases^(b)
11,897 16,124 28,362 27,829
Outage costs^(c)
44,911 35,155 51,969 45,795
Interest rate swap termination fees^(d)
10,343 13,336 8,348 9,345
Depreciation expense^(f)(e)
47,294 48,362 46,582 46,938
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs^(g)(f)
31,126 27,678 33,643 32,501
Interest rate options cost^(h)(g)
89,781 38,984 100,470 98,671
Deferral of effects on net margin—Smith Energy Facility^(i)(h)
96,811 63,491 144,330 128,666
Other regulatory assets^(j)(m)
5,878 5,479 24,515 22,573

Total Regulatory Assets
$ 412,456 $ 331,108 $ 507,496 $ 484,049
Regulatory Liabilities:

Accumulated retirement costs for other obligations^(e)
$ 21,069 $ 24,520
Deferral of effects on net margin—Hawk Road Energy Facility⁽ⁱ⁾
28,605 23,379
Major maintenance reserve^(k)
26,762 28,064
Accumulated retirement costs for other obligations⁽ⁱ⁾
$ 15,774 $ 18,559
Deferral of effects on net margin—Hawk Road Energy Facility^(h)
31,178 29,867
Major maintenance reserve^(j)
22,952 23,427
Amortization on capital leases^(b)
23,924 21,693
Deferred debt service adder^(l)(k)
64,375 57,223 69,124 66,754
Asset retirement obligations^(e)(l)
21,508 19,508 34,394 28,870
Other regulatory liabilities^(j)(m)
4,931 6,095 4,886 4,903

Total Regulatory Liabilities
$ 167,250 $ 158,789 $ 202,232 $ 194,073

Net Regulatory Assets

$
245,206
$
172,319
$
305,264
$
289,976

^(a)
Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 30 years.

^(b)
Represents the difference between lease payments and the aggregate of the amortization on the capital lease assets and the interest on the capital lease obligations for rate-making purposes. ~~Recovered over the remaining terms of the leases through 2031.~~

^(c)
Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over an 18 to 36-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit.

^(d)
Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019.

^(e)
~~Represents 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)(f)
Deferred charges related to 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 and amortized to expense over the life of the units.

^(h)(g)
Deferral of net loss associated with the change in fair value and expired cost of ~~the~~ interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units ~~No. 3~~No.3 and ~~No. 4~~No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.

^(i)(h)
Effects on net margin for Smith and Hawk Road Energy Facilities are deferred until the end of 2015 and will be amortized over the remaining life of each respective plant.

⁽ⁱ⁾
Represents difference in timing of recognition of retirement costs associated with long-lived assets in which there are no legal obligations to retire for financial statement purposes and for ratemaking purposes.

^(j)
Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.

^(k)
Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.

^(l)
Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes.

^(m)
The amortization period for other regulatory assets range up to 35 years and the amortization period of other regulatory liabilities range up to 18 years.

^(k)
~~Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.~~

^(l)
Represents collections to fund certain debt payments through the end of 2025 in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.

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(J)
Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2018, with the majority of the balance scheduled to be credited by the end of 2015.
(K)
Debt.

a)
Department of Energy Loan Guarantee:
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 ~~(the "Loan Guarantee Agreement")~~ pursuant to which the Department of Energy agreed to guarantee our obligations ~~(the "Department of Energy Guarantee")~~ under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and ~~the Future Advance Promissory Note No. 1 and the Future Advance Promissory Note No. 2,~~two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through the Federal Financing Bank.
Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, $335,471,604 of which is designated for capitalized interest.
Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to the Federal Financing Bank under the Federal Financing Bank Notes and reimbursement obligations to the Department of Energy under the related reimbursement notes are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture by a lien on substantially all of our owned tangible and certain of our intangible assets, including property we acquire in the future.
~~Advances.~~    Advances may be requested under the Facility on a quarterly basis through December 31, 2020. ~~On February 20, 2014, we made an initial borrowing in the principal amount of $725,000,000 at a fixed~~At March 31, 2015, aggregate borrowings totaled $882,672,000, including capitalized interest rate of 3.867% through February 20, 2044. In connection with the receipt of these funds, we repaid a like amount of outstanding short-term obligations, which included a $260,000,000 term loan originally due April 1, 2014 and $465,000,000 of commercial paper. These outstanding obligations were classified as long-term at December 31, 2013.
Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs.

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~~Maturity, Interest Rate and Amortization.~~    ~~The final maturity date for each advance~~advanced under the Facility is February 20, 2044. Interest is payable quarterly in arrears on February 20, May 20, August 20 and November 20 of each year. Principal and interest payments will begin on February 20, 2020. Interest accrued and payable through November 20, 2019, up to a maximum of $335,471,604, is reflected as additional borrowings under the Facility. As of September 30, 2014, $17,179,000 of interest is reflected as long-term debt on our condensed balance sheet.
Under Future Advance Promissory Note No. 1, we may select an interest rate period applicable to each advance, with such interest rate periods ranging from three months to the final maturity date. All advances under Future Advance Promissory Note No. 2 will bear a fixed rate of interest through the final maturity date. Under both Federal Financing Bank Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.
In connection with our entry into the Loan Guarantee Agreement and the FFB Credit Facility Documents, we incurred issuance costs of approximately $51,000,000, which will be amortized over the life of the borrowings under the Facility. Issuance costs include fees paid to the Department of Energy, legal and consulting expenses and costs for compliance with certain federal requirements (including compliance with the Davis-Bacon Act).loan.
b)
Rural Utilities Service Guaranteed Loans:
For the ~~nine~~three month period ended ~~September 30, 2014,~~March 31, 2015, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling ~~$35,900,000~~$113,718,000 for general and environmental improvements at existing plants.
c)
~~Bond Issuance:~~Credit Facilities:
On ~~June 12, 2014,~~March 23, 2015, we ~~issued $250,000,000~~entered into a $1,210,000,000 credit agreement with a syndicate of ~~4.55% first mortgage bonds, Series 2014A primarily for~~thirteen lenders, led by the purpose of repaying outstanding commercial paper issued for the interim financing of general and environmental capital expenditures at our existing generation facilities and for general corporate purposes. The bonds are secured under our first mortgage indenture.National Rural Utilities Cooperative Finance Corporation as administrative agent.
(L)
~~Purchase Agreements.~~Nuclear Fuel Disposal Cost Litigation.    ~~On April 11, 2014, we signed a precedent agreement~~Contracts with ~~Transcontinental Gas Pipeline Company, LLC (Transco) for additional firm natural gas transportation~~the U.S. Department of Energy have been executed to our Smith facility. The additional firm transportation is contingent upon the construction of a new natural gas pipeline by Transco. The agreement has a base term of 25 years, with a fixed charge of $37,700,000 per yearprovide for the ~~base term.~~permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract.
On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of January 1, 2005 through December 31, 2010. Our ~~obligation~~ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded in our March 31, 2015 financial statements and resulted in a $7,320,000 reduction in total operating expenses, including reductions to ~~make payments begins when the pipeline expansion project is placed into service, which is projected~~fuel expense and production costs, as well as a $3,629,000 reduction to ~~be May 1, 2017.~~plant in service.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations
General
We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 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~~which we provide primarily from our generation assets and, to a lesser extent, from power purchased from ~~power marketers and~~ other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.
Results of Operations
For the Three Months Ended March 31, 2015 and ~~Nine Months Ended September 30,~~ 2014 ~~and 2013~~
Net Margin
Our net margin for the three-month ~~and nine-month periods~~period ended ~~September 30, 2014~~March 31, 2015 was ~~$14.5~~$15.4 million ~~and $50.9 million, respectively,~~ compared to ~~$20.1 million and $66.6~~$19.2 million for the same ~~periods~~period of ~~2013.~~2014. Through ~~September 30, 2014,~~March 31, 2015, we collected approximately ~~109%~~32% of our targeted net margin of ~~$46.6~~$48.6 million for the year ending December 31, ~~2014.~~2015. This is typical as our capacity revenues are recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board of directors will approve a budget adjustment by the end of the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio. For additional information regarding our net ~~margins~~margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" of our ~~2013~~2014 Form 10-K.
Operating Revenues
Our operating revenues fluctuate from period to period based on several factors, including fuel costs, 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, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.
Sales to Members.    ~~Total~~We generate revenues principally from ~~sales~~the sale of electric capacity and energy to members increased 7.3% and 11.4% in the three-month and nine-month periods ended September 30, 2014 compared to the same periods of 2013. Megawatt-hour sales to members increased 2.9% and 9.5% for the three-month and nine-month periods ended September 30, 2014 compared to the same periods of 2013. The average total revenue per megawatt-hour from sales to members increased 4.3% and 1.7% for the three-month and nine-month periods ended September 30, 2014 compared to the same periods of 2013. The increase in revenues from sales to members and in megawatt-hour sales to members in the nine-months ended September 30, 2014 versus the same period of 2013 was driven partly by increased generation at Plant Scherer due to increased member demand and partly due to increased generation at Plant Wansley Unit due to extensive testing of Mercury Air Toxic Standards environmental controls that were installed in early 2014. Increased member demand due to extreme cold weather during the winter of 2014 also contributed to the increase in sales to members for the nine-month period ended September 30, 2014.

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~~The components of member revenues for the three-month and nine-month periods ended September 30, 2014 and 2013 were as follows (amounts in thousands except for cents per kilowatt-hour):~~

Three Months Ended
September 30, Nine Months Ended
September 30,

2014 2013 2014 2013
Capacity revenues
$ 188,750 $ 182,107 $ 570,502 $ 547,482
Energy revenues
149,990 133,539 441,113 361,008

Total
$ 338,740 $ 315,646 $ 1,011,615 $ 908,490

Kilowatt-hours sold to members

5,360,623
5,210,893
15,440,120
14,097,380
Cents per kilowatt-hour
6.32¢ 6.06¢ 6.55¢ 6.44¢

~~Capacity revenues from members increased 3.6% and 4.2% for the three-month and nine-month periods ended September 30, 2014 compared to the same periods of 2013.~~our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, and are designed to ~~cover~~recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Each member is required to pay us for capacity furnished under its wholesale power contract according to the individual fixed percentage capacity cost responsibility for each resource in which it participates. Our capacityEnergy revenues are ~~based on the costs we expect~~earned by selling electricity to ~~incur on an annual basis and are subject to adjustment by~~ our ~~board such that~~members, which involves generating or purchasing electricity for our ~~net margins will achieve, but not exceed, the targeted margins for interest ratio.~~
members. Energy revenues ~~were 12.3% and 22.2% higher for~~recover the three-month and nine-month periods ended September 30, 2014 compared to the same periods of 2013. Our average energy revenue per megawatt-hour from sales to members increased 9.2% and 11.6% for the three-month and nine-month periods ended September 30, 2014 as compared to the same periods of 2013. The increase in energy revenues for the three-month period ended September 30, 2014 as compared to the same period of 2013 was primarily due to an increase in higher cost natural gas generation, primarily from our combustion turbine facilities. The increase in energy revenues for the comparable nine-month period ended September 30, 2014 as compared to the same period of 2013 was partly due to an increase in higher cost coal-fired generation and to a change in the mixvariable costs of our natural gas generation with an increase in generation from our higher cost combustion turbine facilities. Increased generation during the winter of 2014 as a result of extreme cold weather also contributed to this increase. For a discussion of totalbusiness, including fuel, ~~costs~~purchased energy and ~~total generation, see "—~~~~Operating Expenses.~~"
~~Sales to Non-Members.~~    ~~Sales to non-members for the three-month~~variable operations and nine-month periods ended September 30, 2014 decreased 10.0% and increased 13.4% as compared to the same periods of 2013. The decrease in the third quarter of 2014 compared to the same period of 2013 was primarily due to lower energy sales from the Smith Energy Facility. The increase for non-member sales year-to-date in 2014 was primarily due to sales of natural gas of $10.8 million during the first quarter of 2014.maintenance expense.
~~Operating Expenses~~
Operating expenses for the three-month and nine-month periods ended September 30, 2014 increased 6.9% and 14.3% as compared to the same periods of 2013. These increases were due to higher fuel costs, production costs and depreciation and amortization expenses as compared to the same periods of 2013.

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

Three Months Ended
September 30,

2014 2013

Fuel Source
Cost Generation Cost per
MWh Cost Generation Cost per
MWh

(thousands) (MWh) (thousands) (MWh)
Coal
$ 54,863 1,800,149 $ 30.48 $ 53,934 1,818,076 $ 29.67
Nuclear
20,824 2,694,182 7.73 23,238 2,636,084 8.82
Gas:

Combined Cycle
57,756 1,690,619 34.16 55,665 1,700,112 32.74
Combustion Turbine
13,871 234,819 59.07 5,415 72,358 74.84

$ 147,314 6,419,769 $ 22.95 $ 138,252 6,226,630 $ 22.20

Nine Months Ended
September 30,

2014 2013

Fuel Source
Cost Generation Cost per
MWh Cost Generation Cost per
MWh

(thousands) (Mwh) (thousands) (Mwh)
Coal
$ 175,011 5,713,709 $ 30.63 $ 139,746 4,792,309 $ 29.16
Nuclear
63,591 7,497,391 8.48 64,168 7,295,446 8.80
Gas:

Combined Cycle
150,337 3,855,072 39.00 137,335 4,119,313 33.34
Combustion Turbine
24,627 353,585 69.65 10,218 136,690 74.75

$ 413,566 17,419,757 $ 23.74 $ 351,467 16,343,758 $ 21.50

~~For~~components of member revenues for the three-month period ended March 31, 2015 and ~~nine-month periods~~2014 were as follows:

Three Months Ended
March 31, 2015 vs. 2014
% Change

2015 2014

Capacity revenues
$ 195,328 $ 191,676 1.9%
Energy revenues
113,448 143,083 (20.7%)

Total
$ 308,776 $ 334,759 (7.8%)

kWh Sales to members

4,567,689
4,905,224
(6.9%)

Cents/kWh
6.76 6.82 (0.9%)

The decrease in energy revenues to members for the three-months ended ~~September 30, 2014, total fuel costs increased 6.6% and 17.7% and megawatt-hour generation increased 3.1% and 6.6%, respectively,~~March 31, 2015 compared to the same ~~periods of 2013. Average fuel costs per megawatt-hour increased 3.3% and 10.4%~~period in ~~the three-month and nine-month periods ended September 30,~~ 2014 ~~compared to the same periods of 2013. The increase in total fuel costs~~ was primarily due to ~~higher~~a decrease in fuel costs, a decrease in generation for member sales and, to lesser extent, a decrease in purchase power energy. Lower member demand as a result of milder weather experienced during the first quarter of 2015 contributed to these decreases. Primarily as a result of the decrease in fuel costs, average energy revenue per kilowatt-hour from ~~our coal-fired plants. As discussed above, extensive testing of environmental equipment at Plant Wansley increased generation in 2014 by 351,000 megawatt-hours~~sales to members decreased 14.9% for the ~~nine-month~~three-month period ended ~~September 30, 2014~~March 31, 2015 as compared to the same period of ~~2013 when it was in reserve shutdown~~2014. For a discussion of fuel costs and purchased power costs, see "—Operating Expenses."
Sales to Non-members.    Our sales to non-members primarily consist of capacity and energy sales at the Smith Energy Facility.
Operating Expenses.    Operating expenses decreased 8.7% for ~~most of~~ the ~~nine month period primarily due to more economical generation from natural gas-fired facilities. Generation from Plant Scherer also increased 12.6% during the nine-month~~three-month period ended ~~September 30, 2014 as~~March 31, 2015 compared to the same period of ~~2013 due~~2014 which was driven by lower fuel and purchased power costs.
The following table summarizes our fuel costs and kilowatt-hour generation by generating source.

Cost Generation Cents per kWh

(dollars in thousands) (kWh in thousands) (kWh in thousands)

Three Months Ended
March 31,
2015 vs.
Three Months Ended
March 31,
2015 vs.
Three Months Ended
March 31,
2015 vs.
Fuel Source
2015 2014 2014
% Change 2015 2014 2014
% Change 2015 2014 2014
% Change

Coal
$ 42,485 $ 56,486 (24.8% ) 1,405,651 1,896,226 (25.9% ) 3.02 2.98 1.5%
Nuclear⁽¹⁾
13,007 20,765 (37.4% ) 2,377,764 2,225,966 6.8% 0.55 0.93 (41.4% )
Gas:

Combined Cycle
47,315 51,201 (7.6% ) 1,582,967 1,138,084 39.1% 2.99 4.50 (33.6% )
Combustion Turbine
5,602 3,824 46.5% 46,157 21,425 115.4% 12.14 17.85 (32.0% )

$ 108,409 $ 132,276 (18.0% ) 5,412,539 5,281,701 2.5% 2.00 2.50 (20.0% )

⁽¹⁾
The 2015 nuclear fuel cost amount includes a $7.1 million credit for nuclear fuel storage costs recovered as a result of litigation related to ~~increased demand~~responsibility for nuclear fuel disposal costs. The exclusion of the credit would have resulted in total nuclear fuel costs of $20.1 million, a 3.3% decline and nuclear cost per kWh of 0.84 cents per kWh, a 9.5% decline from ~~our members. The extreme cold weather in the first quarter of 2014 also contributed to the increase in megawatt-hours of generation for the nine month period ended September 30, 2014.~~
~~Production costs increased 7.8% and 11.0% for the three-month and nine-month periods ended September 30, 2014 as compared to the same periods of 2013. The increase in the third quarter of 2014 versus~~ the same period of ~~2013 resulted primarily from higher operations and maintenance expenses at our co-owned facilities. Increased environmental expenses at our coal-fired plants also contributed to the increase.~~ 2014. For information regarding this litigation, see Note L.
The ~~increase~~decrease in total fuel costs for the ~~nine-month~~three-month period ended ~~September 30, 2014 as~~March 31, 2015 compared to the same period of ~~2013 resulted~~2014 was primarily ~~from (i) the cost of~~due to lower natural gas ~~sold to non-members~~costs and the recognition of $6a $7.1 million ~~(ii) higher operations and maintenance~~reduction in fuel expense associated with the recovery of spent nuclear fuel storage costs ~~at our co-owned facilities and (iii) environmental expenses at our~~from the U.S. Department of Energy. For additional information regarding nuclear fuel disposal cost recovery, see Note L. Generation from coal-fired ~~plants.~~plants decreased for the three-month period ended March 31, 2015

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~~Depreciation and amortization costs increased 2.5% and 6.4% for the three-month and nine-month periods ended September 30, 2014~~ as compared to the same ~~periods~~period of ~~2013. The increase in depreciation expense in~~ 2014 ~~was~~ primarily due to ~~$291 million~~a decrease in member demand as a result of ~~environmental capital improvements~~more moderate weather as compared to the extreme cold weather experienced during the first quarter of 2014. Generation from natural-gas fired plants increased during the first quarter of 2015 primarily as a result of lower natural gas prices and an increase in non-member megawatt-hour sales.
Production costs increased 6.2% for the three-month period ended March 31, 2015 as compared to the same period of 2014. The increase resulted primarily from planned major maintenance outage work at ~~Plant Scherer that were~~Smith in 2015.
Purchase power costs decreased 32.1% for the three-month period ended March 31, 2015 as compared to the same period of 2014 primarily ~~placed into service~~due to a decrease in ~~May and August~~energy purchases. This decrease was largely due to a decrease in demand as a result of ~~2013.~~more moderate weather during the first quarter of 2015.
Interest charges
Interest expense increased ~~9.7% and 10.2%~~7.1% for the three-month ~~and nine-month periods~~period ended ~~September 30, 2014~~March 31, 2015 as compared to the same ~~periods~~period of ~~2013~~2014 primarily due to increased debt to finance construction of Vogtle Units No. 3 and No. 4.
Financial Condition
~~Balance Sheet Analysis as of September 30, 2014~~
Balance Sheet Analysis as of March 31, 2015
Assets
Cash used for property additions for the ~~nine-month~~three-month period ended ~~September 30, 2014~~March 31, 2015 totaled ~~$428.6~~$165.4 million. Of this amount, approximately ~~$250~~$80.1 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, ~~$25 million for environmental control systems being installed primarily at Plant Scherer and $47~~$14.4 million for nuclear fuel ~~purchases. The~~purchases and the remaining expenditures were for normal additions and replacements to existing generation facilities.
~~Long-term restricted~~Prepayments and other current assets increased $30.2 million for the three-month period ended March 31, 2015 primarily as a result of the prepayment of major maintenance costs for an outage at our Smith facility.
Restricted cash and investments at ~~September 30, 2014~~March 31, 2015 consist primarily of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. 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. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs. ~~At December 31, 2013, the balance represented restricted cash posted as collateral by counterparties to our interest rate options.~~
Deferred debt expense, being amortized increased $41.5 million for the nine months ended September 30, 2014 due to debt related costs associated with a $3.057 billion loan with the Department of Energy, which closed in February 2014. For additional information regarding this loan, see Note K.
Regulatory assets increased $81.3 million for the nine months ended September 30, 2014. The increase was primarily due to a $50.8 million increase in the deferral of unrealized losses on, and expirations of, our interest rate options. For information regarding our interest rate options, see Note C. In addition, there was a $33.3 million increase in deferred losses related to Smith Energy Facility. The effects on net margin for Smith are being deferred until the end of 2015 at which time the amounts will be amortized over the remaining life of the facility. For additional information regarding all regulatory assets, see Note I.
Equity and Liabilities
Short-term borrowings increased $109.4 million for the three-month period ended March 31, 2015. These borrowings provided interim financing for capital expenditures related to the Vogtle Units No. 3 and No. 4 construction project.
Accounts payable decreased ~~$33.7~~$59.3 million for the ~~nine-month~~three-month period ended ~~September 30, 2014~~March 31, 2015 primarily as a result of ~~$38.4~~a $31.7 million decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4. Also contributing to the decrease was $17.7 million in credits, applied to ~~the~~our members' bills in the first quarter of ~~2014~~2015, for a board approved reduction ~~to 2013~~in 2014 revenue requirements as a result of ~~margins collected~~margin collections in excess of our ~~2013~~2014 target. ~~Offsetting the decrease was a $7.2~~
Other current liabilities decreased $32.2 million ~~increase in natural gas purchases.~~
~~Member power bill prepayments represent funds received from the members~~ for the prepayment of their monthly power bills. At September 30, 2014, $100.4 million of member power bill prepayments was classified as a current liability and $71.8 million was classified as a long-term liability. During the nine-monththree-month period ended ~~September 30, 2014, $97.7 million of prepayments were received from the members and $40.2 million was applied~~March 31, 2015 primarily due to the ~~members' monthly power bills. For information regarding the power bill prepayment program, see Note J.~~payment of operation and maintenance expenses and property taxes accrued at December 31, 2014.

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Capital Requirements and Liquidity and Sources of Capital
Vogtle Units No. 3 and No. 4.
We, are participating in 30% of the cost of constructing two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. As of September 30, 2014, our total investment in the additional Vogtle units was $2.3 billion.
~~In April 2008,~~along with Georgia Power, ~~for itself and as agent for us,~~ the Municipal Electric Authority of Georgia and the City of Dalton are participating in the "Co-owners," signed an Engineering, Procurement and Construction Contract with Westinghouse Electric Company, LLC and Stone & Webster, Inc., together, the "Contractor." Pursuant to the contract, the Contractor will supply and constructconstruction of two ~~1,100 megawatt nuclear units using the~~ Westinghouse AP1000 ~~technology,~~nuclear generating units at Plant Vogtle, each with ~~the exception~~a nominally rated generating capacity of ~~certain owner supplied items. Under the contract, the Co-owners will pay a purchase price that~~approximately 1,100 megawatts. Our ownership interest is subject to certain price escalation and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. Each Co-owner is severally, not jointly, liable to the Contractor based on its ownership share. The contract includes certain liquidated damages upon the Contractor's failure to comply with schedule and performance guarantees. The Contractor's liability for those liquidated damages and for warranty claims is subject to a cap.
~~The obligations~~30%, representing 660 megawatts of ~~Westinghouse and Stone & Webster are guaranteed by their parent companies Toshiba Corporation and The Shaw Group, Inc., a subsidiary~~total capacity. As of Chicago Bridge & Iron Co. N.V., respectively. In the event of certain credit rating downgrades of any Co-owner, that Co-owner would be required to provide a letter of credit or other credit enhancement to the Contractor. In addition, the Co-owners may terminate the contract at any time for their convenience, provided that the Co-owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Contractor. The Contractor may terminate the contract under certain circumstances, including certain Co-owner suspension or delays of work, action by a governmental authority to stop work permanently, certain breaches of the contract by the Co-owners, Co-owner insolvency and certain other events. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.
The Nuclear Regulatory Commission certified the Westinghouse AP1000 Design Control Document (DCD) effective December 30, 2011. On February 10, 2012, the Nuclear Regulatory Commission issued combined licenses forMarch 31, 2015, our total investment in Vogtle Units No. 3 and No. 4 ~~which allowed full~~was $2.5 billion.
For additional information about the Vogtle construction ~~to begin. There have been technical and procedural challenges to the construction and licensing of~~project, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4 ~~at the federal and state level, and additional challenges are expected as construction proceeds.~~
The Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.
Current litigation relates to costs associated with design changes to the 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 by the Nuclear Regulatory Commission. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the contract. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not

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responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia.
The portion of the additional costs claimed by the Contractor that would be attributable to us, based on our ownership interest, is approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to further schedule extensions. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the agreement. The Contractor did not specify in its amended counterclaim the amounts relating to these new allegations, but the Contractor subsequently asserted and may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues.
While litigation has commenced and Georgia Power and the Co-owners intend to vigorously defend their positions, Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.
Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the combined licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission.
Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners, the Contractor, or both.
The issues mentioned above, in addition to other factors that have materialized during the development and construction process, have caused revisions to the estimated project schedule and cost. The current estimated commercial operation dates for Units No. 3 and No. 4 are the fourth quarter of 2017 and 2018, respectively. Our current estimated project cost, including allowance for funds used during construction and a contingency amount, is approximately $4.5 billion. Commercial responsibility for the revised commercial operation dates and additional costs remain in dispute.
As construction continues, the risk remains that ongoing challenges with contractor performance including additional challenges in the fabrication, assembly, delivery and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Vogtle Units No. 3 and No. 4, or other issues could arise and may further impact project schedule and cost. Contractor performance and progress in recent months has resulted in additional schedule pressure. The Co-owners expect the Contractor to employ mitigation efforts to maintain the current project schedule and believe the terms of the contract provide that the Contractor is responsible for any related costs.

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Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the contract, but also may be resolved through litigation.
The ultimate outcome of these matters cannot be determined at this time. See "RISK FACTORS" for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units. For additional information regarding Vogtle Units No. 3 and No. 4, see "—~~Financing Activities—Department of Energy-Guaranteed Loan~~" and ~~Notes~~"Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2014 Form 10-K. Also see Note G and Note K.
Environmental Regulations
The U.S. Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water and waste management at power plants. Following are some of the recent developments that may affect future operations at our facilities.
On ~~June 18, 2014,~~April 17, 2015 EPA ~~proposed a~~published its final coal combustion residuals (CCR) rule, in which it decided to regulate CCRs as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act. The final rule contains requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new ~~source performance standards at certain~~and existing ~~power plants called~~CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. The rule takes effect on October 14, 2015. We are still reviewing the ~~"Clean Power Plan." As~~effects of the CCR, but they could include actions to address some or all of the requirements listed above. Significant operational changes for existing CCR storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities and additional material management and financial assurance requirements may be needed. Preliminary estimates suggest that our capital costs for compliance with the CCR (in combination with EPA's proposed ~~the~~effluent limitations guidelines rule ~~would cut carbon dioxide emissions from existing fossil fuel-fired power plants nationwide~~which is to be finalized by an average of 30% from 2005 levels by 2030, with an additional interim goal for the years 2020 through 2029. For Georgia, however, the proposal would require a 44% reduction in emission rates from 2012 levels through a combination of plant efficiency improvements, shifting generation from coal-fired plants to natural gas-fired plants, addition of renewable and other non-carbon emitting generation (e.g. nuclear), and implementing various demand reducing energy efficiency measures. That same day, EPA also proposed new source performance standards for certain modified or reconstructed fossil fuel-fired power plants which, if finalized,September 2015) could ~~apply to our coal-fired and natural gas-fired facilities. EPA is scheduled to finalize the Clean Power Plan~~be approximately $200 million. More definitive cost estimates will be developed as ~~well as the standards for modified or reconstructed sources by June 1, 2015.~~
On October 28, 2014, EPA issued a Notice of Data Availability (NODA) related to the Clean Power Plan, which was not intended to revise EPA's proposal but to provide an opportunity for the public to comment on some additional technical details. We commented on the proposed standards for modified and reconstructed sources and are in the process of ~~developing comments on the Clean Power Plan~~rule evaluation, compliance approach design and construction implementation proceeds, and the ~~NODA, which will include preliminary analysis of cost to us and our members, and intend to provide them to~~ultimate impacts associated with the publically available comment docket before the December 1, 2014 deadline. If finalized as proposed, the Clean Power Plan could result in operational restrictions and compliance costs which could be significant. We believe that some of the policy approaches being proposed could have significant negative consequences for both the economy and electric systems of Georgia and nationwide. However, the outcome of the Clean Power Plan and the standards for modified or reconstructed sources rulemakings, including any subsequent challenges,CCR rule cannot be determined with certainty at this time and will depend on numerous factors such as: how the State of Georgia chooses to implement the final requirements; the schedules for implementation and compliance; how new and existing nuclear generation is treated in the final rule; the impacts of future decisions regarding unit retirement and replacement (including the type and amount of any replacement capacity); the availability and cost of additional natural gas supplies, the changes that may be needed in the transmission system to accommodate new, potentially intermittent generation sources; and the availability and cost of technologies to improve the efficiency of the existing coal-fired units.
On February 12, 2013, EPA proposed a rule that would require many states, including Georgia, to revise those portions of their State Implementation Plans (SIPs) that relate to the regulation of excess emissions at industrial facilities, including fossil fuel-fired electric generating units, during periods of startup, shut-down or malfunction (SSM). EPA's proposed determination, if finalized, would require revisions to all affected SIPs within 18 months. Since that time, in litigation over this rulemaking, EPA has delayed final action on the proposal until May 22, 2015, which would delay the SIP submission deadline for each of the states subject to the rule until November 2016. On September 17, 2014 EPA

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proposed supplemental changes to its February 2013 proposal, proposing that affected states like Georgia must remove all affirmative defense provisions in their SIPs as a condition of complying with the proposed SSM SIP call. If finalized as proposed, these new rules could result in additional compliance and operational costs at our power plants. We cannot predict the ultimate outcome of this rulemaking and any ensuing litigation regarding it that may occur.
Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts on fish and other aquatic life. EPA's final section 316(b) requirements for existing power plants and manufacturing facilities were published in the August 15, 2014~~Federal Register~~, making them effective October 14, 2014. The final rule applies to all existing facilities that withdraw at least two million gallons of water per day and that use at least 25% of such water exclusively for cooling purposes. We are in the process now of conferring with the Georgia Environmental Protection Division to determine what modifications, if any, need to be made to our four co-owned power plants that trigger the cooling water use threshold (Plants Scherer, Wansley, Vogtle and Hatch) to meet the new finalized standards. Capital requirements for any additional controls that might be needed for compliance at any of these plants cannot be determined at this time, but are not expected to be significant, and the result of any litigation which has been brought challenging the final rules cannot be predicted.
On April 29, 2014, the U. S. Supreme Court upheld the Cross State Air Pollution Rule (CSAPR), reversing a 2012 decision of the U.S. Court of Appeals for the District of Columbia (D.C.) Circuit which had invalidated the CSAPR. The Supreme Court remanded the case back to the D.C. Circuit for further proceedings consistent with the decision. On October 23, 2014, the D.C. Circuit issued an order lifting its previously-issued stay of CSAPR, which may lead to the implementation of the rule, delayed by three years due to the litigation. Therefore, CSAPR's Phase 1 emission budgets may begin on January 1, 2015, for the annual programs and May 1, 2015, for the ozone-season NO_x program, while CSAPR's Phase 2 emission budgets would apply beginning in 2017. Briefing on the remaining issues in the litigation is underway, and we cannot predict the outcome of that litigation or the effect, if any, it may have on CSAPR or the future operations of our co-owned units at Plants Scherer and Wansley. Given the recent installation of additional pollution control equipment at Plant Scherer, we do not anticipate the need to purchase allowances for the operation of our units at either facility to comply with CSAPR.time.
For further discussion regarding potential effects on our business from environmental regulations, 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 and Sources of Capital—~~~~Environmental Regulations~~~~" in our quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014, as well as~~ "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our ~~2013~~2014 Form 10-K.
Liquidity
At ~~September 30, 2014,~~March 31, 2015, we had ~~$1.6~~$1.3 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$312~~$272 million in cash and cash equivalents and ~~$1.3~~$1.0 billion of unused and available committed credit arrangements.

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At ~~September 30, 2014,~~March 31, 2015, we had in excess of ~~$1.8~~$1.61 billion of committed credit arrangements in place and ~~$1.3~~$1.0 billion available under these facilities. These ~~five~~four separate facilities are reflected in the table below:

Committed Credit Facilities
Committed Credit Facilities

Authorized
Amount

Available
March 31,
2015

Expiration Date
Committed Credit Facilities

Authorized
Amount

Available
September 30,
2014

Expiration Date

(dollars in millions) (dollars in millions)
Unsecured Facilities:

Syndicated Line of Credit led by Bank of America⁽¹⁾
$ 1,265 $ 865 ⁽²⁾ June 2015
CFC Line of Credit(3)
110 110 September 2016
Syndicated Line of Credit led by CFC
$ 1,210 ⁽¹⁾ $ 730 ⁽²⁾ March 2020
CFC Line of Credit⁽³⁾
210 210 December 2018 110 110 December 2018
JPMorgan Chase Line of Credit
150 34 ⁽⁴⁾ December 2018 150 34 ⁽⁴⁾ November 2016
Secured Facilities:

CFC Term Loan⁽³⁾
250 250 December 2018 250 250 December 2018

⁽¹⁾
~~We plan to renew~~The amount of this facility ~~in the first quarter of 2015.~~that can be used to support outstanding commercial paper is limited to $1.0 billion.

⁽²⁾
Of the portion of this facility that was unavailable at ~~September 30, 2014, $264.6~~March 31, 2015, $344 million was dedicated to support outstanding commercial paper and ~~$135.5~~$136 million was related to letters of credit issued to support variable rate demand bonds.

⁽³⁾
Any amounts drawn under the ~~$210~~$110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.

⁽⁴⁾
Of the portion of this facility that was unavailable at ~~September 30, 2014, $113.7~~March 31, 2015, $114 million related to letters of credit issued to support variable rate demand bonds and ~~$2.2~~$2 million related to letters of credit issued to post collateral to third parties.
As of ~~September 30, 2014,~~March 31, 2015, we were using our commercial paper program to provide interim funding for 1) ~~the monthly~~ payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanent funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and 2) the premium payments made in connection with our interest rate hedging program. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide for the interim financings described above.
Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding.
Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling ~~$970~~$760 million in the aggregate, of which ~~$719~~$508 million remained available at ~~September 30, 2014.~~March 31, 2015. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.
~~Several~~Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At ~~September 30, 2014,~~March 31, 2015, the required minimum level was $675 million and our actual patronage capital was ~~$765~~$776 million. ~~Additional covenants contained in several of our credit facilities limit~~These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At ~~September 30, 2014,~~March 31, 2015, we had ~~$7.3~~$7.4 billion of secured indebtedness and ~~$265~~$344 million of unsecured indebtedness ~~outstanding, which was well within the covenant thresholds.~~

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At ~~September 30, 2014,~~March 31, 2015, we had ~~$344~~$371 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of ~~September 30, 2014—~~March 31, 2015—Assets" for more information regarding this account.

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Financing Activities
First Mortgage Indenture.    At ~~September 30, 2014,~~March 31, 2015, we had ~~$7.2~~$7.3 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our ~~2013~~2014 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans.    We currently have three approved Rural Utilities Service-guaranteed loans ~~totaling $561 million, which are~~ being funded through the Federal Financing Bank ~~and~~that are in various stages of being drawn ~~down,~~down. These three loans total $561 million with ~~$339~~$212 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of March 31, 2015, we had $2.7 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.
Department of Energy-Guaranteed Loan.    In February 2014, we closed on a loan with the Department of Energy that will fund up to the lesser of $3.057 billion or 70% of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.
As of ~~September 30, 2014,~~March 31, 2015, our total investment in Vogtle Units No. 3 and No. 4 was ~~$2.3~~$2.5 billion and we have incurred ~~$2.1~~$2.3 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds we previously issued and ~~$742~~$883 million, including capitalized interest, under the Department of Energy loan facility. The facility may be used until no later than December 2020 to provide long-term funding for up to 70% of eligible project costs after they are incurred. As of ~~September 30, 2014,~~March 31, 2015, we have the capacity to fund an additional ~~$775~~$746 million under the facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced, the debt will be secured under our first mortgage indenture. For additional information regarding this loan, see Note K.
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 ~~2013~~2014 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
There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our ~~2013~~2014 Form 10-K.
Item 4.    Controls and Procedures
As of ~~September 30, 2014,~~March 31, 2015, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.
There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended ~~September 30, 2014~~March 31, 2015 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

Table of Contents

PART II—OTHER INFORMATION
Item 1.    Legal Proceedings
~~The ultimate outcome of pending or potential litigation against us cannot be predicted at this time; however, we do~~There have not ~~anticipate that the ultimate liabilities, if~~been any ~~arising~~material changes to legal proceedings from ~~such proceedings would have a material effect on our financial condition or results of operations.~~
~~Patronage Capital Litigation~~
~~On March 13, 2014, a lawsuit was filed~~those reported in ~~the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three~~"Item 3—LEGAL PROCEEDINGS" of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 20132014 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.
On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two alleged current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and rate increases required to meet the plaintiffs' demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

~~Table of Contents~~
~~We intend to defend vigorously against all claims in the above-described litigation.~~
~~Vogtle Units No. 3 and No. 4~~
For a discussion of litigation related to the development and construction of Vogtle Units No. 3 and No. 4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—~~Vogtle Units No. 3 and No. 4~~."
Item 1A.    Risk Factors
There have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our ~~2013~~2014 Form ~~10-K and "Item 1A—Risk Factors" of our quarterly report for the quarterly period ended June 30, 2014.~~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.    Mine Safety Disclosures
Not Applicable.
Item 5.    Other Information
Not Applicable.
Item 6.    Exhibits
Number
Description
~~4.1~~31.1 ~~Ninth Amended and Restated Loan Contract, dated as of September 2, 2014, between Oglethorpe (An Electric Membership Corporation) and the United States of America.~~

~~4.2~~

Sixty-Ninth Supplemental Indenture, dated as of September 2, 2014, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2014 (FFB AB-8) Note and Series 2014 (RUS AB-8) Reimbursement Note.

~~31.1~~

Rule 13a-14(a)/15d-14(a) Certification, by Michael L. 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 Michael L. 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 2012-2014).

101

XBRL Interactive Data File.

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 7, 2014~~May 13, 2015

By:

/s/ Michael L. Smith
Michael L. Smith
President and Chief Executive Officer

Date: ~~November 7, 2014~~May 13, 2015

/s/ Elizabeth B. Higgins
Elizabeth B. Higgins
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)



												Fair Value Measurements at Reporting Date Using
													March 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	Fair Value Measurements at Reporting Date Using
		September 30, 2014			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)
Nuclear decommissioning trust funds:
Domestic equity	$	151,485		$	151,485	$	—		$	—		$	163,991	$	163,991	$	—	$	—
International equity trust		72,518			—		72,518			—			74,705		—		74,705		—
Corporate bonds		39,713			—		39,713			—			18,298		—		18,298		—
US Treasury and government agency securities		62,440			62,440		—			—			70,197		70,197		—		—
Agency mortgage and asset backed securities		16,736			—		16,736			—			14,957		—		14,957		—
Municipal bonds													19,565		—		19,565		—
Other		12,940			12,940		—			—			12,862		12,862		—		—
Long-term investments:
International equity trust		11,166			—		11,166			—			11,508		—		11,508		—
Corporate bonds		6,558			—		6,558			—			6,135		—		6,135		—
US Treasury and government agency securities		13,933			13,933		—			—			17,129		17,129		—		—
Agency mortgage and asset backed securities		570			—		570			—			870		—		870		—
Mutual funds		51,045			51,045		—			—			51,932		51,932		—		—
Other		417			417		—			—			262		262		—		—
Interest rate options		13,110			—		—			13,110	⁽¹⁾		2,702		—		—		2,702
Natural gas swaps		(1,764	)		—		(1,764	)		—			21,096		—		21,096		—



	Fair Value Measurements at Reporting Date Using
		December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	143,929	$	143,929	$	—	$	—
International equity trust		72,466		—		72,466		—
Corporate bonds		39,863		—		39,863		—
US Treasury and government agency securities		44,846		44,846		—		—
Agency mortgage and asset backed securities		30,133		—		30,133		—
Municipal Bonds		641		—		641		—
Other		11,820		11,820		—		—
Long-term investments:
Corporate bonds		6,487		—		6,487		—
US Treasury and government agency securities		8,563		8,563		—		—
Agency mortgage and asset backed securities		3,679		—		3,679		—
International equity trust		11,148		—		11,148		—
Mutual funds		51,559		51,559		—		—
Other		284		284		—		—
Interest rate options		63,471		—		—		63,471	⁽¹⁾
Natural gas swaps		1,011		—		1,011		—



	Fair Value Measurements at Reporting Date Using
		December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	159,536	$	159,536	$	—	$	—
International equity trust		72,474		—		72,474		—
Corporate bonds		34,446		—		34,446		—
US Treasury and government agency securities		68,854		68,854		—		—
Agency mortgage and asset backed securities		16,148		—		16,148		—
Municipal Bonds		743		—		743		—
Other		13,803		13,803		—		—
Long-term investments:
Corporate bonds		5,445		—		5,445		—
US Treasury and government agency securities		16,619		16,619		—		—
Agency mortgage and asset backed securities		643		—		643		—
International equity trust		11,162		—		11,162		—
Mutual funds		51,741		51,741		—		—
Other		118		118		—		—
Interest rate options		4,371		—		—		4,371
Natural gas swaps		18,914		—		18,914		—



					Three Months Ended March 31, 2015

		Three Months Ended September 30, 2014			Interest rate options

		Interest rate options


		(dollars in thousands)			(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2014	$	18,535
Balance at December 31, 2014				$	4,371
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(5,425	)		(1,669	)


Balance at September 30, 2014	$	13,110

Balance at March 31, 2015				$	2,702



		Three Months Ended September 30, 2013

		Interest rate options

		(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2013	$	43,680
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(149	)


Balance at September 30, 2013	$	43,531



		Nine Months Ended September 30, 2014

		Interest rate options

		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2013	$	63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(50,361	)


Balance at September 30, 2014	$	13,110



				Three Months Ended March 31, 2014

		Nine Months Ended September 30, 2013		Interest rate options

		Interest rate options


		(dollars in thousands)		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2012	$	25,783
Balance at December 31, 2013			$	63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		17,748		(32,008	)


Balance at September 30, 2013	$	43,531

Balance at March 31, 2014			$	31,463



		2014				2013

		Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,157,870	$	7,983,009	$	6,954,293	$	7,317,476




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

2014	0.4

2015	7.9	19.0
2016	5.4	11.0

2017		2.8

Total	14.3	32.8




Year		LIBOR Swaption Notional Dollar Amount (in thousands)		LIBOR Swaption Notional Dollar Amount (in thousands)

2014	$	143,629

2015		470,624	$	355,424
2016		310,533		310,533
2017		80,169		80,169


Total	$	1,004,955	$	746,126



						Balance Sheet Location		Fair Value
	Balance Sheet Location		Fair Value


			2014		2013			2015		2014
			(dollars in thousands)					(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options⁽¹⁾	Other deferred charges	$	13,110	$	63,471	Other deferred charges	$	2,702	$	4,371
Natural gas swaps	Other current assets	$	258	$	1,011
Liabilities:
Natural gas swaps	Other current liabilities	$	2,022	$	—	Other current liabilities	$	12,241	$	13,418

Natural gas swaps						Other deferred credits		8,855		5,496



	Statement of Revenues and Expenses		Three months ended September 30,						Nine months ended September 30,
	Location		2014			2013			2014			2013

			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	638		$	122		$	1,874		$	688
Natural Gas Swaps	Fuel		(889	)		(3,089	)		(890	)		(4,002	)


		$	(251	)	$	(2,967	)	$	984		$	(3,314	)	Statement of Revenues and Expenses		Three months ended March 31,
														Location		2015			2014

																(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps														Fuel	$	—		$	279
Natural Gas Swaps														Fuel		(5,527	)		—

															$	(5,527	)	$	279



													Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Cash Collateral		Net Amounts of Assets Presented on the Balance Sheet

		Gross Amounts of Recognized Assets (Liabilities)		Gross Amounts offset on the Balance Sheet			Cash Collateral			Net Amounts of Assets Presented on the Balance Sheet			(dollars in thousands)

		(dollars in thousands)
September 30, 2014
March 31, 2015
Assets:
Natural gas swaps	$	261	$	(2,025	)	$	—		$	(1,764	)	$	(21,096	)	$	—		$	—	$	(21,096	)
Interest rate options	$	13,110	$	—		$	—		$	13,110		$	47,547		$	(44,845	)	$	—	$	2,702
December 31, 2013
December 31, 2014
Assets:
Natural gas swaps	$	1,069	$	(58	)	$	—		$	1,011		$	(18,914	)	$	—		$	—	$	(18,914	)
Interest rate options	$	63,471	$	—		$	(34,970	)	$	28,501		$	53,603		$	(49,232	)	$	—	$	4,371



											Gross Unrealized

	Gross Unrealized										(dollars in thousands)
		(dollars in thousands)
September 30, 2014		Cost		Gains		Losses			Fair Value

March 31, 2015											Cost		Gains		Losses			Fair Value

Equity	$	196,523	$	64,560	$	(2,185	)	$	258,898	$	206,199	$	71,575	$	(1,926	)	$	275,848
Debt		166,710		9,159		(8,417	)		167,452		170,276		11,244		(8,082	)		173,438
Other		13,173		—		(2	)		13,171		13,128		—		(3	)		13,125


Total	$	376,406	$	73,719	$	(10,604	)	$	439,521	$	389,603	$	82,819	$	(10,011	)	$	462,411

	Accumulated Other Comprehensive Margin (Deficit) Three Months Ended


		(dollars in thousands)
		Available-for-sale Securities


Balance at June 30, 2013	$	(399	)
Unrealized gain		181
Loss reclassified to net margin		24


Balance at September 30, 2013	$	(194	)


Balance at June 30, 2014	$	278
Unrealized (loss)		(100	)
(Gain) reclassified to net margin		(18	)


Balance at September 30, 2014	$	160



	Nine Months Ended
		(dollars in thousands)
		Available-for-sale Securities


Balance at December 31, 2012	$	903
Unrealized (loss)		(1,041	)
(Gain) reclassified to net margin		(56	)
				Accumulated Other Comprehensive Margin (Deficit) Three Months Ended

Balance at September 30, 2013	$	(194	)
					(dollars in thousands)
					Available-for-sale Securities

Balance at December 31, 2013	$	(549	)	$	(549	)
Unrealized gain		782			390
Loss reclassified to net margin					6

Balance at March 31, 2014				$	(153	)

Balance at December 31, 2014				$	468
Unrealized gain					107
(Gain) reclassified to net margin		(73	)		(154	)

Balance at March 31, 2015				$	421



Balance at September 30, 2014	$	160



		Three Months Ended March 31,			2015 vs. 2014 % Change

		2015		2014

Capacity revenues	$	195,328	$	191,676	1.9%
Energy revenues		113,448		143,083	(20.7%)

Total	$	308,776	$	334,759	(7.8%)



kWh Sales to members		4,567,689		4,905,224	(6.9%)
Cents/kWh		6.76		6.82	(0.9%)



		Cost						Generation					Cents per kWh

		(dollars in thousands)						(kWh in thousands)					(kWh in thousands)
	Three Months Ended March 31,				2015 vs.		Three Months Ended March 31,			2015 vs.		Three Months Ended March 31,			2015 vs.
Fuel Source		2015		2014	2014 % Change			2015	2014	2014 % Change			2015	2014	2014 % Change

Coal	$	42,485	$	56,486	(24.8%	)		1,405,651	1,896,226	(25.9%	)		3.02	2.98	1.5%
Nuclear⁽¹⁾		13,007		20,765	(37.4%	)		2,377,764	2,225,966	6.8%			0.55	0.93	(41.4%	)
Gas:
Combined Cycle		47,315		51,201	(7.6%	)		1,582,967	1,138,084	39.1%			2.99	4.50	(33.6%	)
Combustion Turbine		5,602		3,824	46.5%			46,157	21,425	115.4%			12.14	17.85	(32.0%	)

	$	108,409	$	132,276	(18.0%	)		5,412,539	5,281,701	2.5%			2.00	2.50	(20.0%	)



Committed Credit Facilities							Committed Credit Facilities

									Authorized Amount			Available March 31, 2015		Expiration Date
Committed Credit Facilities

		Authorized Amount		Available September 30, 2014		Expiration Date


		(dollars in millions)							(dollars in millions)
*Unsecured Facilities:*
Syndicated Line of Credit led by Bank of America⁽¹⁾	$	1,265	$	865	⁽²⁾	June 2015
CFC Line of Credit(3)		110		110		September 2016
Syndicated Line of Credit led by CFC								$	1,210	⁽¹⁾	$	730	⁽²⁾	March 2020
CFC Line of Credit⁽³⁾		210		210		December 2018			110			110		December 2018
JPMorgan Chase Line of Credit		150		34	⁽⁴⁾	December 2018			150			34	⁽⁴⁾	November 2016
*Secured Facilities:*
CFC Term Loan⁽³⁾		250		250		December 2018			250			250		December 2018

Number			Description

	~~4.1~~31.1		~~Ninth Amended and Restated Loan Contract, dated as of September 2, 2014, between Oglethorpe (An Electric Membership Corporation) and the United States of America.~~
	~~4.2~~		Sixty-Ninth Supplemental Indenture, dated as of September 2, 2014, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2014 (FFB AB-8) Note and Series 2014 (RUS AB-8) Reimbursement Note.
	~~31.1~~		Rule 13a-14(a)/15d-14(a) Certification, by Michael L. 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 Michael L. 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 2012-2014).
	101		XBRL Interactive Data File.


		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: ~~November 7, 2014~~May 13, 2015	By:	/s/ Michael L. Smith Michael L. Smith President and Chief Executive Officer
Date: ~~November 7, 2014~~May 13, 2015		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)