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

FORM 10-Q

Commission File No. 000-53908

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

        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 Filero o    Accelerated Filero o    Non-Accelerated Filer ý    (Do(Do not check if a smaller reporting company)    Smaller Reporting Companyo o

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

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

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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNESEPTEMBER 30, 2013

i

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CAUTIONARY STATEMENTS 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" and in other sections of our Annual Report on Form 10-K for the fiscal year ended December 31, 2012. 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 construction projects, including 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;



•

potential legislative and regulatory responses to climate change initiatives, including the regulation of carbon dioxide and other greenhouse gas emissions;



•

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 the availability of funding from the U.S. Department of Energy and other government sources;



•

actions by credit rating agencies;



•

risks and regulatory requirements related to the ownership and construction of nuclear facilities;

ii

the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning trust fund are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 72%76% of these gross unrealized losses were in effect for less than one year.




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The following tables summarize the activities for available-for-sale securities as of JuneSeptember 30, 2013 and December 31, 2012.

		Gross Unrealized													Gross Unrealized
			(dollars in thousands)													(dollars in thousands)
June 30, 2013			Cost			Gains			Losses			Fair Value
September 30, 2013																Cost			Gains			Losses			Fair Value
Equity		$	172,916		$	45,712		$	(4,608	)	$	214,020			$	178,794		$	51,750		$	(1,230	)	$	229,314
Debt			164,014			6,919			(9,164	)		161,769				162,452			7,593			(8,090	)		161,955
Other			13,439			—			(4	)		13,435				13,008			—			—			13,008
Total		$	350,369		$	52,631		$	(13,776	)	$	389,224			$	354,254		$	59,343		$	(9,320	)	$	404,277

 


		Gross Unrealized
			(dollars in thousands)
December 31, 2012			Cost			Gains			Losses			Fair Value
Equity		$	153,846		$	45,071		$	(3,675	)	$	195,242
Debt			163,127			10,286			(4,501	)		168,912
Other			13,654			—			—			13,654
Total		$	330,627		$	55,357		$	(8,176	)	$	377,808

(E)

Recently Issued or Adopted Accounting Pronouncements.    In December 2011,July 2013, the Financial Accounting Standards Board (FASB) issued "Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exist." The update provides guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The adoption of this standard is effective for us January 1, 2014 and is not expected to have a material effect on our consolidated financial statements.

In December 2011, FASB issued "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities," which modifies the disclosure requirements for offsetting financial instruments and derivative instruments. The update requires an entity to disclose information about offsetting and related arrangements and the effect of those arrangements on its financial position. The adoption of this standard was effective for us January 1, 2013 and did not have a material impact on our consolidated financial statements.


In February 2013, the FASB issued "Comprehensive Income (Topic 220): Reporting Amounts Reclassified out of Accumulated Other Comprehensive Income," which amended certain provisions of ASC 220 "Comprehensive Income." The update requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective items on the income statement for reclassified amounts that are required by U.S. GAAP to be reclassified entirely to net income. The update also requires additional footnote disclosures for reclassified amounts that are not required by U.S. GAAP to be reclassified entirely to net income. The adoption of this standard did not have a material impact on our consolidated financial statements.




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(F)

Accumulated Comprehensive Margin. 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. 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 2012 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.

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		Accumulated Other Comprehensive Margin Three Months Ended				Accumulated Other Comprehensive Margin Three Months Ended
			(dollars in thousands)				(dollars in thousands)
			Available-for-sale Securities				Available-for-sale Securities
Balance at March 31, 2012		$	1,327
Balance at June 30, 2012						$	1,446
Unrealized gain			119				165
Balance at June 30, 2012		$	1,446
Balance at March 31, 2013		$	691
Unrealized (loss)			(1,074	)
(Gain) reclassified to net margin			(16	)			(123	)
Balance at September 30, 2012						$	1,488
Balance at June 30, 2013		$	(399	)		$	(399	)
Unrealized gain							181
Loss reclassified to net margin							24
Balance at September 30, 2013						$	(194	)

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		Accumulated Other Comprehensive Margin (Deficit) Six Months Ended				Nine Months Ended
			(dollars in thousands)				(dollars in thousands)
			Available-for-sale Securities				Available-for-sale Securities
Balance at December 31, 2011		$	618			$	618
Unrealized gain			911				1,076
(Gain) reclassified to net margin			(83	)			(206	)
Balance at June 30, 2012		$	1,446
Balance at September 30, 2012						$	1,488
Balance at December 31, 2012		$	903			$	903
Unrealized (loss)			(1,222	)			(1,041	)
(Gain) reclassified to net margin			(80	)			(56	)
Balance at June 30, 2013		$	(399	)
Balance at September 30, 2013						$	(194	)

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(G)

Contingencies and Regulatory Matters.

General

We are subject to certain claims and legal actions arising in the ordinary course of our business. The ultimate outcome of any pending or current proceedings against us cannot be predicted at this time; however, except as discussed in "—Nuclear Construction" below, management does not anticipate that the liabilities, if any, for any current proceedings against us, if adversely determined, will have a material effect on our financial condition or results of operations.




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Nuclear Construction

In April 2008, Georgia Power Company, acting for itself and as agent for Oglethorpe, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (Vogtle No. 3 and No. 4 Agreement) to design, engineer, procure, and construct 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 Vogtle No. 3 and No. 4 Agreement, 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.

The most significant litigation relates to 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, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the contract. The Contractor has claimed that its estimated adjustment attributable to us, based on our ownership interest, is approximately $280,000,000 in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to schedule extensions. 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. 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. On August 30, 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. The Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia Circuit on September 27, 2013. While litigation has commenced and Georgia Power and the Co-owners intend to vigorously defend their positions. During litigation,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 JuneSeptember 30, 2013, 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.

The ultimate outcome of these matters cannot be determined at this time.




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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




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modifications in the design or operation of existing facilities, the purchase of emission allowances, or changes or delays in the location, design, construction or operation of new facilities. 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 or 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. For example, in Januaryduring 2013, severalapproximately 150 plaintiffs have filed complaints against us and the other co-owners of Plant Scherer claiming personal injury and property damage arising from the alleged release of hazardous substances from the plant, primarily related to the coal-ash pond, into the surrounding groundwater and air.

(H)

Restricted Cash.    At JuneSeptember 30, 2013 and December 31, 2012, we had restricted cash totaling $36,230,000$31,221,000 and $9,109,000, respectively, of which $36,074,000$31,064,000 and $8,953,000, respectively, was classified as long-term. The long-term restricted cash balance at JuneSeptember 30, 2013 and December 31, 2012 consisted primarily of funds posted as collateral by counterparties to our interest rate options.



(I)

Restricted Short-term Investments.    At JuneSeptember 30, 2013 and December 31, 2012, we had $206,211,000$254,854,000 and $64,671,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.



(J)

Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.




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The following regulatory assets and liabilities are reflected on the accompanying condensed balance sheet as of JuneSeptember 30, 2013 and December 31, 2012.

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			2013			2012				2013			2012
			(dollars in thousands)							(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)		$	80,534		$	86,319			$	77,911		$	86,319
Amortization on capital leases(b)			22,364			28,670				19,154			28,670
Outage costs(c)			43,700			30,901				35,329			30,901
Interest rate swap termination fees(d)			15,331			17,326				14,333			17,326
Asset retirement obligations(e)			7,914			11,382				—			11,382
Depreciation expense(f)			49,073			49,785				48,718			49,785
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g)			25,668			23,030				26,627			23,030
Interest rate options cost(h)			58,304			75,716				58,691			75,716
Deferral of effects on net margin—Smith Energy Facility(i)			44,207			21,394				52,384			21,394
Other regulatory assets(j)			9,500			8,379				6,127			8,379
Total Regulatory Assets		$	356,595		$	352,902			$	339,274		$	352,902
Regulatory Liabilities:
Accumulated retirement costs for other obligations(e)		$	25,304		$	28,846			$	25,106		$	28,846
Deferral of effects on net margin—Hawk Road Energy Facility(i)			21,208			17,113				22,302			17,113
Major maintenance sinking fund(k)			27,680			30,948
Major maintenance reserve(k)										28,012			30,948
Deferred debt service adder(l)			52,349			47,486				54,785			47,486
Other regulatory liabilities(j)			5,278			5,592				8,982			5,592
Total Regulatory Liabilities		$	131,819		$	129,985			$	139,187		$	129,985
Net Regulatory Assets		$	224,776		$	222,917			$	200,087		$	222,917

^(a)

Represents premiums paid, together with unamortized transaction costs related to reacquired debt amortized over the period 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 and nuclear refueling outage costs. Coal-fired outages 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 swapsswap 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)

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)

Deferral of net loss associated with the change in fair value of the interest rate options to hedge interest rates on a portion of expected borrowings related to Vogtle Units No. 3 and No. 4 construction. Amortization will commence effective with the expected principal repayment of the Department of Energy (DOE)-guaranteed loan and amortized over the expected remaining life of the DOE-guaranteed loan which will finance a portion of the construction project.



⁽ⁱ⁾

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.



^(j)

The amortization period for other regulatory assets range up to 36 years and the amortization period of other regulatory liabilities range up to 13 years.



^(k)

Represents collections for future major maintenance costs; revenues to be recognized as major maintenance costs are incurred.



^(l)

Collections to fund debt payments in excess of depreciation expense through the end of 2025; deferred revenues will be amortized over the remaining useful life of the plants.




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(K)

Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. At JuneSeptember 30, 2013, member power bill prepayments as reflected on the unaudited condensed balance sheets are $156,792,000,$108,023,000, of which $124,090,000$75,410,000 is classified as current liabilities and $32,702,000$32,613,000 as deferred credits and other liabilities. The prepayments are being appliedcredited against members' power bills through January 2018, with the majority of the remaining balance scheduled to be appliedcredited by the end of 2013.



(L)

Debt.    On March 1, 2013, instead of remarketing the $212,760,000 of pollution control revenue bonds that were originally issued on our behalf by the Development Authorities of Appling, Burke and Monroe Counties, and were subject to mandatory tender, we elected to redeem the bonds with commercial paper. On April 23, 2013, the Development Authority of Appling County (Georgia), the Development Authority of Burke County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $212,760,000 in aggregate principal amount of tax-exempt pollution control revenue bonds for the purpose of refinancing costs associated with certain of our air or water pollution control and sewage or solid waste disposal facilities. The proceeds were used to repay the outstanding commercial paper utilized to redeem the pollution control revenue bonds that were redeemed on March 1, 2013. Each series of bonds bear interest at 2.40% per annum until April 1, 2020, the initial mandatory tender date. The pollution control revenue bonds are scheduled to mature starting in 2038 through 2040. Our payment obligations related to these bonds are secured under our first mortgage indenture.



For the sixnine month period ended JuneSeptember 30, 2013, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $70,408,000$662,880,000 for general and environmental improvements at existing plants.


In July 2013, we received an additional $589,605,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for the long-term financing of the Smith Energy Facility and general and environmental improvements at existing plants. A portion of these


On October 31, 2013, we received $13,217,000 in advances was utilized to repay $232,610,000 of outstanding commercial paper classified as long-term debtfrom RUS for general and environmental improvements at June 30, 2013.existing plants.




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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 our generation assets and, to a lesser extent, power purchased from power marketers and other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Results of Operations

For the Three and SixNine Months Ended JuneSeptember 30, 2013 and 2012

Net Margin

Throughout the year, we monitor our operating results and, with board approval, make budget adjustments when and as necessary to ensure our targeted margins for interest ratio is achieved. Under our first mortgage indenture, we are required to establish and collect rates that are reasonably expected, together with our other revenues, to yield at least a 1.10 margins for interest ratio in each fiscal year. However, to enhance margin coverage during a period of increased capital requirements, our board of directors approved budgets for 2012, 2013 and 20132014 to achieve a 1.14 margins for interest ratio. As our capital requirements continue to evolve, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.

Our net margin for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 was $24.5$20.1 million and $46.5$66.6 million compared to $10.9$23.7 million and $24.4$48.1 million for the same periods of 2012. Through JuneSeptember 30, 2013, we collected approximately 112%160% of our targeted net margin of $41.5 million for the year ending December 31, 2013. Actual net margins exceeding targeted margins during the fiscal year is typical as our capacity revenues are recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board 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.

Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, 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 revenues from sales to members decreased 1.4%6.8% and 2.1%3.8% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012. Megawatt-hour sales to members decreased 14.9%15.4% and 13.4%14.2% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012. The average total revenue per megawatt-hour from sales to members increased 15.9%10.1% and 13.1%12.1% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periodperiods of 2012.




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The components of member revenues for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 and 2012 were as follows (amounts in thousands except for cents per kilowatt-hour):

			Three Months Ended June 30,						Six Months Ended June 30,							Three Months Ended September 30,						Nine Months Ended September 30,
		2013			2012			2013			2012				2013			2012			2013			2012
Capacity revenues		$	184,261		$	173,446		$	365,375		$	347,633			$	182,107		$	171,267		$	547,482		$	518,900
Energy revenues			121,930			137,037			227,469			258,080				133,539			167,501			361,008			425,581
Total		$	306,191		$	310,483		$	592,844		$	605,713			$	315,646		$	338,768		$	908,490		$	944,481
Kilowatt-hours sold to members			4,732,825			5,563,074			8,886,487			10,265,873				5,210,893			6,156,398			14,097,380			16,422,271
Cents per kilowatt-hour			6.47¢			5.58¢			6.67¢			5.90¢				6.06¢			5.50¢			6.44¢			5.75¢

Capacity revenues from members increased 6.2%6.3% and 5.1%5.5% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012. Capacity revenues relate primarily to the assignment to each of our members the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges. Each member is required to pay us for capacity furnished under its wholesale power contract in accordance with rates we establish. Our capacity revenues are based on the costs we expect to incur on an annual basis and are subject to adjustment by our board such that our net margins will achieve, but not exceed, the targeted margins for interest ratio. See "—Net Margin" for discussion regarding margins for interest ratio.

Energy revenues were 11.0%20.3% and 11.9%15.2% lower for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012. Our average energy revenue per megawatt-hour from sales to members increased 4.6%decreased 5.8% and 1.8%1.2% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012. The decrease in energy revenues for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012 resulted primarily from lower coal-fired and natural gas generation partially offset by higher fuel costs per megawatt-hour due to higher natural gas prices.generation. For a discussion of total fuel costs and total generation, see "—Operating Expenses."

Sales to Non-Members.    Sales to non-members for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 were 51.2%11.8% and 38.9%28.4% lower as compared to the same periods of 2012. Sales to non-members in 2012 consisted of capacity and energy sales made under an agreement to sell the entire output of Unit No. 1 of the Thomas A. Smith Energy Facility to Georgia Power Company through May 31, 2012, as well as energy sales to other non-members from Smith Units No. 1 and No. 2. The decrease for the three-month and six-month periodsnine-month period ended JuneSeptember 30, 2013 as compared to the same periodsperiod of 2012 was primarily due to the expiration of this agreement with Georgia Power. This decrease was partially offset by increased energy sales to other non-members.

Operating Expenses

Operating expenses for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 decreased 10.3%11.7% and 8.9%9.9% as compared to the same periods of 2012. ThisThe decrease for the three-month and nine-month periods ended September 30, 2013 as compared to the same periods of 2012 was primarily due to lower fuel costs andcosts. For the nine-month period ended September 30, 2013 as compared to the same period of 2012, lower depreciation and amortization expenses, which were partially offset somewhat by higher purchased power costs and accretion expense.expense, also contributed to the decrease in operating expenses.




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

			Three Months Ended June 30,																			Three Months Ended September 30,
			2013									2012										2013									2012
Fuel Source			Cost			Generation			Cost per MWh			Cost			Generation			Cost per MWh				Cost			Generation			Cost per MWh			Cost			Generation			Cost per MWh
			(thousands)			(MWh)						(thousands)			(MWh)							(thousands)			(MWh)						(thousands)			(MWh)
Coal		$	45,167			1,490,279		$	30.31		$	65,319			2,069,400		$	31.56			$	53,934			1,818,076		$	29.67		$	69,000			2,292,572		$	30.10
Nuclear			22,598			2,574,270			8.78			17,702			2,612,822			6.78				23,238			2,636,084			8.82			22,092			2,556,238			8.64
Gas:
Combined Cycle			41,532			1,142,648			36.35			45,299			1,991,583			22.75				55,665			1,700,112			32.74			59,537			2,298,222			25.91
Combustion Turbine			3,768			47,568			79.21			10,868			275,745			39.41				5,415			72,358			74.84			20,549			456,603			45.00
		$	113,065			5,254,765		$	21.52		$	139,188			6,949,550		$	20.03			$	138,252			6,226,630		$	22.20		$	171,178			7,603,635		$	22.51

 


			Six Months Ended June 30,																			Nine Months Ended September 30,
			2013									2012										2013									2012
Fuel Source			Cost			Generation			Cost per MWh			Cost			Generation			Cost per MWh				Cost			Generation			Cost per MWh			Cost			Generation			Cost per MWh
			(thousands)			(MWh)						(thousands)			(MWh)							(thousands)			(Mwh)						(thousands)			(Mwh)
Coal		$	85,812			2,974,233		$	28.85		$	118,905			3,748,595		$	31.72			$	139,746			4,792,309		$	29.16		$	187,905			6,041,167		$	31.10
Nuclear			40,930			4,659,362			8.78			38,033			5,046,539			7.54				64,168			7,295,446			8.80			60,125			7,602,777			7.91
Gas:
Combined Cycle			81,670			2,419,201			33.76			80,170			3,381,051			23.71				137,335			4,119,313			33.34			139,707			5,679,273			24.60
Combustion Turbine			4,803			64,332			74.66			11,308			282,489			40.03				10,218			136,690			74.75			31,857			739,092			43.10
		$	213,215			10,117,128		$	21.07		$	248,416			12,458,674		$	19.94			$	351,467			16,343,758		$	21.50		$	419,594			20,062,309		$	20.91

For the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013, total fuel costs decreased 18.8%19.2% and 14.2%16.2% and megawatt-hour generation from these fuel sources decreased 24.4%18.1% and 18.8%18.5%, respectively, compared to the same periods of 2012. Milder temperatures in 2013 as compared to 2012 contributed to the decrease in megawatt-hour generation. Average fuel costs per megawatt-hour decreased 1.4% and increased 7.4% and 5.7%2.8% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012. The decrease in total fuel costs was primarily due to lower generation at Plant Wansley and our natural gas-fired facilities. Plant Wansley, which is fueled by higher cost eastern coal, was in reserve shutdown for most of the six-monthnine-month period ended JuneSeptember 30, 2013 primarily due to more economical generation from our natural gas-fired facilities. Generation from our gas-fired facilities also decreased in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 versus the same periods of 2012 primarily due to lower utilization of the Smith Energy Facility, although all of our gas-fired facilities experienced decreased generation in the first halfthree-month and nine-month periods of 2013 compared to the same periodperiods of 2012. The decrease in total fuel costs was partially offset by increased natural gas prices in 2013. As was the case in 2012, generation from Smith continues to be sold to non-members.

Total production costs decreased 2.3% for the six-month period ended June 30, 2013 as compared to the same period of 2012. This decrease resulted primarily from lower production costs for Hawk Road Energy Facility in 2013 as production costs in 2012 included planned outage work.

Depreciation and amortization costs increased 7.9% and decreased 4.9% and 11.1%5.2% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012. ThisThe increase in depreciation expense in the third quarter of 2013 as compared to the same quarter of 2012 was primarily due to $249.7 million of environmental capital improvements at Plant Scherer that were placed into service in May and August of 2013. The decrease for the nine-month period ended September 30, 2013 as compared to the same period of 2012 was primarily due to the May 2012 completion of amortization




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of the intangible asset associated with a purchase and sale agreement with Georgia Power which was acquired as part of the Smith acquisition. In addition,




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amortization expense of leasehold improvements for Scherer Unit No. 2 capital leases decreased because we extended the lease terms in June 2012.

Purchased power costs increased 24.5%14.0% and 14.4%14.3% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012. The increase in purchased power costs resulted primarily from increased cost per kilowatt-houran increase in kilowatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with power purchased on the spot market at a lower price. In addition, increased transmission expenses contributed to the higher purchased power costs.

Accretion expense increased 16.8%17.8% and 16.4%16.9% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012. The increase in accretion expense resulted primarily from an increase in the asset retirement obligation for the decommissioning of our ash ponds based on December 2012 studies.

The effect on net margin of the Smith and Hawk Road Energy Facilities is being deferred until 2016, at which time the amounts will be amortized over the remaining life of the plants. In implementing the deferral plans, we assumed that our members would generally not require energy from the plants until 2016. The change in the deferral resulted primarilypartly from the expiration of the power purchase and sale agreement with Georgia Power that ended in May 2012.2012, partly from an increase in interest expense for the long-term financing of Smith, which was obtained in July 2013, and partly from reduced margins associated with non-member energy sales from Smith.

Other Income

Investment income increased 5.0%29.8% and decreased 3.7%5.9% for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to the same periods of 2012. An increase in funds deposited in the Rural Utilities Service Cushion of Credit Account as well as increased investment income from nuclear decommissioning trust funds contributed to the higher investment income in the second quarterthree-month and nine-month periods of 2013. The termination2013 as compared to same periods of 90% of2012. Partially offsetting the increase during the nine-month period ended September 30, 2013, was a reduction in investment income associated with the Rocky Mountain lease transactions duringtransactions. During the second half of 2012, contributed tofive of the decrease in investment income during the six-month period ended June 30, 2013.six lease transactions were terminated.

Other income decreased 29.0% and 34.5%The gain on termination of Rocky Mountain transactions for the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 as compared to2012 represented the same periodsnet gain resulting from the July 2012 termination of 2012. This decrease was primarily due to lower amortization of gain on Rocky Mountain lease transactions due to the 2012 terminations discussed above. In addition, the amortizationthree of the gain associated with the Scherer Unit No. 2 capital leases was lower due to extension of the terms of the leases in 2012.six leases.

Interest charges

Allowance for debt funds used during construction increased 22.7%11.6% and 22.2%18.5% in the three-month and six-monthnine-month periods ended JuneSeptember 30, 2013 compared to the same periods of 2012 primarily due to construction expenditures for Vogtle Units No. 3 and No. 4.




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Financial Condition

Balance Sheet Analysis as of JuneSeptember 30, 2013

Assets

Cash used for property additions for the six-monthnine-month period ended JuneSeptember 30, 2013 totaled $321.2$414 million. Of this amount, approximately $182$251 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, approximately $46$67 million for environmental control systems being installed primarily at Plant Scherer and approximately $28$39 million for nuclear fuel purchases. The remaining expenditures were for normal additions and replacements to existing generation facilities.

The $206.2$254.9 million of restricted short-term investments at JuneSeptember 30, 2013 represent funds deposited into a Rural Utilities Service Cushion of Credit Account with the U.S. Treasury and earns interest at a guaranteed rate of 5% per annum. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.

Equity and Liabilities

Long-term debt and capital leases due within one year increased $292.2$279.0 million during the six-monthnine-month period ended JuneSeptember 30, 2013 primarily due to the reclassification of a $260.0 million term loan due in April 2014.

Accounts payable decreased $66.9$62.7 million infor the six-monthnine-month period ended JuneSeptember 30, 2013. The December 31, 2012 payablespayable balance included $25.2 million in credits due to the members for a board approved reduction to 2012 revenue requirements as a result of margins collected in excess of our 2012 target. These credits were applied to the members' bills in the first quarter of 2013. The decrease was also the result of a $32.3$24.6 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 construction. In addition, there was $15.4a $15.6 million decrease in accounts payable trade accounts primarily related to property tax payments.

Member power bill prepayments represent funds received from the members for the prepayment of their monthly power bills. At JuneSeptember 30, 2013, $124.1$75.4 million of member power bill prepayments was classified as a current liability and $32.7$32.6 million was classified as a long-term liability. During the six-monthnine-month period ended JuneSeptember 30, 2013, $96.7$102.1 million of prepayments were received from the members and $46.0$100.0 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note K of Notes to Unaudited Condensed Financial Statements and "—Capital Requirements and Liquidity and Sources of Capital—Liquidity."

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4.

We, along with Georgia Power, the Municipal Electric Authority of Georgia and the City of Dalton are participating in the construction of two Westinghouse AP1000 nuclear generating units at Plant Vogtle, each with a nominally rated generating capacity of approximately 1,100 megawatts. Our ownership interest is 30%, representing 660 megawatts of total capacity. As of JuneSeptember 30, 2013, our total capitalized costs to date for Vogtle Units No. 3 and No. 4 were $1.9 billion.

As previously disclosed, separate groups of petitioners had filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking judicial review of the Nuclear Regulatory Commission's certification of the design control document and the issuance of the combined construction permits and operating licenses. On May 14, 2013, the Court ruled in favor of the Nuclear Regulatory Commission




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and upheld the certification of the design control document and the issuance of the combined construction permits and operating licenses. On July 23, 2013, the Court rejected the petitioner's request for rehearing. The deadline for any further appeals expired without the petitioners seeking review.

For additional information about the Vogtle construction project, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2012 Form 10-K. Also see "Note G—




TableContingencies and Regulatory Matters—Nuclear Construction" of ContentsNotes to Unaudited Condensed Financial Statements herein.

Environmental Regulations

The Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water intake and waste management at power plants.

In June,On September 20, 2013, EPA signed rules reproposing (and rescinding) the President announced his Climate Action Plan to reduce domestic emissions of greenhouse gases by 17% below 2005 levels by 2020. Underpinning the plan is a focus on carbon emissions from power plants. On June 25, 2013, a Presidential Memorandum directed the Administrator of the EPA to perform two tasks: (1) to re-proposeApril 2012 New Source Performance Standards (NSPS) for certain new fossil fuel-fired electric generating units. In this new action, EPA proposed standards of performance for fossil fuel-fired electric utility steam generating units that burn coal and other fossil fuels based on partial implementation of carbon capture and storage (CCS). It also proposed separate standards for natural gas-fired stationary combustion turbines that do not involve CCS. Simple cycle "peaking" turbines, certain biomass and oil-fired units and modified, reconstructed and existing sources were exempted or not addressed by the proposal. Once EPA promulgates a NSPS for a category of new, modified or reconstructed emissions sources, it is required to establish guidelines requiring states to develop emission standards for the same category of existing sources. Thus, greenhouse gas NSPS for existing sources may be issued at some point in the future. These proposed rules will likely be challenged when finalized. We cannot predict at this time how further developments may affect the regulation of greenhouse gas emissions from newour power plants, by September 20, 2013 which would replace or modify the NSPS proposed on April 13, 2012, and to finalize the September proposal in a timely fashion; and (2) to propose NSPS for modified, reconstructed and existing power plants by June 1, 2014, finalize those NSPS by June 1, 2015 and require states to submit plans for implementing those finalized NSPS by June 30, 2016. The effects of these actions on our facilities cannot be determined at this time and will depend on further rulemaking and any litigation brought to challenge any final federal or state rules.including capital requirements.

For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "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 2012 Form 10-K.

Liquidity

At JuneSeptember 30, 2013, we had $1.123$1.5 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $221$437 million in cash and cash equivalents and $902 million$1.1 billion of unused and available committed credit arrangements.




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At JuneSeptember 30, 2013, we had in excess of $1.9 billion of committed credit arrangements in place, comprised of the five separate facilities reflected in the table below.

Committed Credit Facilities	Committed Credit Facilities								Committed Credit Facilities
			Authorized Amount			Available 6/30/2013		Expiration Date			Authorized Amount			Available 9/30/2013		Expiration Date
			(dollars in millions)								(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by Bank of America		$	1,265		$	358	(1)	June 2015		$	1,265		$	526	(1)	June 2015
Syndicated Line of Credit led by CoBank			150			150		September 2014			150			150		September 2014
CFC Line of Credit			110			110		September 2016			110			110		September 2016
JPMorgan Chase Line of Credit			150			34	(2)	December 2013			150			34	(2)	December 2013
Secured facilities:
CFC Line of Credit(3)			250			250		December 2013			250			250		December 2013
Total		$	1,925		$	902				$	1,925		$	1,070

⁽¹⁾

Of the portion of this facility that is unavailable, $771.1$603.8 million is dedicated to support commercial paper we have issued and $135.5 million relates to letters of credit issued under this facility to support variable rate demand bonds.



⁽²⁾

Of the portion of this facility that is unavailable, $113.7 million relates to letters of credit issued under this facility to support variable rate demand bonds and $2.3$2.2 million relates to letters of credit issued to post collateral to third parties.



⁽³⁾

This facility has a term loan option that can extend the maturity to December 31, 2043.




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As of JuneSeptember 30, 2013, we were using our commercial paper program to provide interim funding for (i) payments related to the construction of Vogtle Units No. 3 and No. 4, (ii) a portion of the cost to acquire Smith, and (iii)(ii) the upfront payments made in connection with our interest rate hedging program.

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 $835 million in the aggregate, of which $584 million remained available at JuneSeptember 30, 2013. 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.

We are currently negotiating a new 3-year, $150 million unsecured credit facility with JPMorgan Chase Bank, N.A. to replace an existing credit facility we have with them and expect to close on the new facility in November 2013. We are also negotiating a restructuring of our existing $250 million secured credit facility with CFC into a new 5-year, $250 million unsecured credit facility and expect to close on this new facility in December 2013.

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

Several of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At JuneSeptember 30, 2013, the required minimum level was $575 million and our actual patronage capital was $720$740 million. Additional covenants contained in several of our credit facilities limit the amount of secured indebtedness and unsecured indebtedness we can have outstanding. At JuneSeptember 30, 2013, the most restrictive of these covenants limits our secured




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indebtedness to $9.5 billion and our unsecured indebtedness to $4.0 billion. At JuneSeptember 30, 2013, we had $5.9$6.4 billion of secured indebtedness and $1.2 billion$972 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.

At JuneSeptember 30, 2013, current assets included $206.2$255 million of restricted short-term investments pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account. See "Balance"—Balance Sheet Analysis" hereinAnalysis as of September 30, 2013—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At JuneSeptember 30, 2013, we had $5.7$6.2 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our tangible and some of our intangible assets, including those we acquire in the future. See "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities—First Mortgage Indenture" in our 2012 Form 10-K for a further discussion of our first mortgage indenture.

Bond Financing.    On April 23, 2013, we issued $212.8 million of pollution control revenue bonds through the Development Authorities of Appling, Burke and Monroe Counties and used the proceeds to repay a like amount of commercial paper that we issued on March 1, 2013. The proceeds from the commercial paper issuance were used to redeem $212.8 million of pollution control revenue bonds previously issued by the development authorities on our behalf that we elected to redeem on March 1, 2013.

Rural Utilities Service-Guaranteed Loans.    We currently have four approved Rural Utilities Service-guaranteed loans, totaling $1.1 billion, which are being funded through the Federal Financing Bank and are in various stages of being drawn down, with $298.3 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. OnIn July 9, 2013, we received a




Table $492.6 million advance for the full amount of Contents

$492.6 advance under the loan covering the majority of the acquisition cost of Smith, a portion of which was utilized to repay $232.6 million of outstanding commercial paper.paper prior to the end of the third quarter. We currently have four other approved Rural Utilities Service-guaranteed loans, totaling $871 million, which are being funded through the Federal Financing Bank with $469 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture.

Department of Energy-Guaranteed Loan.    In May 2010, we signed a conditional term sheet with the Department of Energy that sets forth the general terms of a loan and related loan guarantee that would fund up to $3.057 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. We continue to work with the Department of Energy on this proposed financing; however, final approval and issuance of a loan guarantee is subject to negotiation of definitive agreements, completion of due diligence and satisfaction of other conditions. Therefore, there can be no assurance that the Department of Energy will ultimately issue the loan guarantee to us. We expect that we will fund any remaining Vogtle costs not funded under the Department of Energy loan guarantee program through capital market financings. The conditional commitment has been extended by the Department of Energy to September 30,December 31, 2013.

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 2012 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


Not Applicable.




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Item 4.    Controls and Procedures


As of JuneSeptember 30, 2013, 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 JuneSeptember 30, 2013 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.




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PART II—OTHER INFORMATION


Item 1.    Legal Proceedings


There have not been any material changes to legal proceedings from those reported in "Item 3—LEGAL PROCEEDINGS" of our 2012 Form 10-K.

Item 1A.    Risk Factors


There have not been any material changes in our risk factors from those reported in "Item 1A—RISK FACTORS" of our 2012 Form 10-K.

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


Not Applicable.

Item 3.    Defaults upon Senior Securities


Not Applicable.

Item 4.    Mine Safety Disclosures


Not Applicable.

Item 5.    Other Information


Not Applicable.On November 6, 2013, Michael L. Smith began serving as our new President and Chief Executive Officer. Prior to joining Oglethorpe, Mr. Smith served as the President and Chief Executive Officer of Georgia Transmission Corporation since 2005 and has over thirty years of experience in the energy industry in the areas of finance, planning, risk control and operations. For additional information regarding Mr. Smith, see our Current Report on Form 8-K, dated as of October 15, 2013.

Item 6.    Exhibits


Number			Description
	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 Executive Officer and 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 Executive Officer and Principal Financial Officer).
	101		XBRL Interactive Data File.




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SIGNATURES


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

				Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: August 12,November 13, 2013		By:		/s/ Michael L. Smith Michael L. Smith President and Chief Executive Officer
Date: November 13, 2013				/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)