10-Q

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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 March 31, 2014
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	30084-5336
(Address of principal executive offices)	(Zip Code)
Registrant's telephone number, including area code	(770) 270-7600

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

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

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

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

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

(This page has been left blank intentionally)

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

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Condensed Balance Sheets as of March 31, 2014 and December 31, 2013	1
	Unaudited Condensed Statements of Revenues and Expenses For the Three Months ended March 31, 2014 and 2013	3
	Unaudited Condensed Statements of Comprehensive Margin For the Three Months ended March 31, 2014 and 2013	4
	Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the Three Months ended March 31, 2014 and 2013	5
	Unaudited Condensed Statements of Cash Flows For the Three Months ended March 31, 2014 and 2013	6
	Notes to Unaudited Condensed Financial Statements For the Three Months ended March 31, 2014 and 2013	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 4.	Controls and Procedures	28
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	29
Item 1A.	Risk Factors	29
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29
Item 3.	Defaults Upon Senior Securities	29
Item 4.	Mine Safety Disclosures	29
Item 5.	Other Information	29
Item 6.	Exhibits	30
SIGNATURES		31

i

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, 2013. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this annual report may not occur.

Any forward-looking statement speaks only as of the date of this annual 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, 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;

•

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 our continued eligibility to receive advances from the U.S. Department of Energy;

•

actions by credit rating agencies;

•

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

ii

•

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;

•

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;

•

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 or our competitors;

•

general economic conditions;

•

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;

•

litigation or legal and administrative proceedings and settlements;

•

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

PART I—FINANCIAL INFORMATION
Item 1. Financial Statements

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
March 31, 2014 and December 31, 2013

		(dollars in thousands)
	2014			2013
Assets
Electric plant:
In service	$	8,078,128		$	8,050,103
Less: Accumulated provision for depreciation		(3,648,091	)		(3,615,375	)
		4,430,037			4,434,728
Nuclear fuel, at amortized cost		347,044			341,012
Construction work in progress		2,290,024			2,212,224
		7,067,105			6,987,964
Investments and funds:
Nuclear decommissioning trust fund		348,097			343,698
Investment in associated companies		66,393			66,437
Long-term investments		82,593			81,720
Restricted cash		10,736			34,975
Other		16,357			16,098
		524,176			542,928
Current assets:
Cash and cash equivalents		218,493			408,193
Restricted short-term investments		289,469			272,686
Receivables		130,884			128,992
Inventories, at average cost		261,341			286,168
Prepayments and other current assets		15,950			16,894
		916,137			1,112,933
Deferred charges:
Deferred debt expense, being amortized		97,831			57,175
Regulatory assets		385,769			331,108
Other		55,976			63,104
		539,576			451,387
	$	9,046,994		$	9,095,212

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

1

Oglethorpe Power Corporation
Condensed Balance Sheets (Unaudited)
March 31, 2014 and December 31, 2013

		(dollars in thousands)
	2014			2013
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	733,712		$	714,489
Accumulated other comprehensive deficit		(153	)		(549	)
		733,559			713,940
Long-term debt		6,795,655			6,817,518
Obligation under capital leases		118,871			121,731
Other		15,639			15,379
		7,663,724			7,668,568
Current liabilities:
Long-term debt and capital leases due within one year		153,772			152,153
Short-term borrowings		269,687			279,407
Accounts payable		72,865			101,529
Accrued interest		49,389			58,193
Member power bill prepayments, current		92,460			82,405
Other current liabilities		27,624			42,253
		665,797			715,940
Deferred credits and other liabilities:
Gain on sale of plant, being amortized		21,787			22,157
Asset retirement obligations		413,977			408,050
Member power bill prepayments, non-current		34,363			32,313
Power sale agreement, being amortized		22,747			26,107
Regulatory liabilities		160,437			158,789
Other		64,162			63,288
		717,473			710,704
	$	9,046,994		$	9,095,212

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

2

Oglethorpe Power Corporation
Condensed Statements of Revenues and Expenses (Unaudited)
For the Three Months Ended March 31, 2014 and 2013

		(dollars in thousands)
	Three Months
	2014			2013
Operating revenues:
Sales to Members	$	334,759		$	286,653
Sales to non-Members		32,541			19,261
Total operating revenues		367,300			305,914
Operating expenses:
Fuel		132,276			100,150
Production		108,084			94,720
Depreciation and amortization		40,714			37,083
Purchased power		20,066			12,667
Accretion		6,018			5,630
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		(9,715	)		(11,890	)
Total operating expenses		297,443			238,360
Operating margin		69,857			67,554
Other income:
Investment income		9,282			7,277
Other		2,377			2,277
Total other income		11,659			9,554
Interest charges:
Interest expense		81,917			75,777
Allowance for debt funds used during construction		(23,729	)		(24,854	)
Amortization of debt discount and expense		4,105			4,161
Net interest charges		62,293			55,084
Net margin	$	19,223		$	22,024

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

3

Oglethorpe Power Corporation
Condensed Statements of Comprehensive Margin (Unaudited)
For the Three Ended March 31, 2014 and 2013

		(dollars in thousands)
	Three Months
	2014		2013
Net margin	$	19,223	$	22,024
Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities		396		(212	)
Total comprehensive margin	$	19,619	$	21,812

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

4

Oglethorpe Power Corporation
Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Deficit) (Unaudited)
For the Three Months Ended March 31, 2014 and 2013

		(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin (Deficit)			Total
Balance at December 31, 2012	$	673,009	$	903		$	673,912
Components of comprehensive margin:
Net margin		22,024		—			22,024
Unrealized (loss) on available-for-sale securities		—		(212	)		(212	)
Balance at March 31, 2013	$	695,033	$	691		$	695,724
Balance at December 31, 2013	$	714,489	$	(549	)	$	713,940
Components of comprehensive margin:
Net margin		19,223		—			19,223
Unrealized gain on available-for-sale securities		—		396			396
Balance at March 31, 2014	$	733,712	$	(153	)	$	733,559

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

5

Oglethorpe Power Corporation
Condensed Statements of Cash Flows (Unaudited)
For the Three Months Ended March 31, 2014 and 2013

		(dollars in thousands)
	2014			2013
Cash flows from operating activities:
Net margin	$	19,223		$	22,024
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		74,880			68,384
Accretion cost		6,018			5,630
Amortization of deferred gains		(447	)		(447	)
Allowance for equity funds used during construction		(389	)		(752	)
Deferred outage costs		(25,845	)		(23,911	)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		(9,715	)		(11,890	)
Gain on sale of investments		(3,996	)		(3,529	)
Regulatory deferral of costs associated with nuclear decommissioning		(84	)		(97	)
Other		1,384			(2,119	)
Change in operating assets and liabilities:
Receivables		(1,799	)		6,124
Inventories		24,827			10,181
Prepayments and other current assets		1,892			1,794
Accounts payable		(33,330	)		(70,675	)
Accrued interest		(8,804	)		14,451
Accrued taxes		(13,144	)		4,634
Other current liabilities		(2,075	)		(2,892	)
Member power bill prepayments		12,105			84,903
Total adjustments		21,478			79,789
Net cash provided by operating activities		40,701			101,813
Cash flows from investing activities:
Property additions		(134,354	)		(180,365	)
Activity in decommissioning fund—Purchases		(101,894	)		(106,460	)
—Proceeds		100,648			105,148
Decrease (increase) in restricted cash		24,239			(4,410	)
Increase in restricted short-term investments		(16,783	)		(139,127	)
Activity in other long-term investments—Purchases		(12,220	)		(6,394	)
—Proceeds		12,413			6,633
Activity on interest rate options—Collateral returned		(46,940	)		(17,440	)
—Collateral received		22,700			21,850
Other		(401	)		2,076
Net cash used in investing activities		(152,592	)		(318,489	)
Cash flows from financing activities:
Long-term debt proceeds		734,608			20,734
Long-term debt payments		(295,740	)		(215,663	)
Decrease (Increase) in short-term borrowings, net		(474,720	)		351,944
Other		(41,957	)		610
Net cash (used in) provided by financing activities		(77,809	)		157,625
Net decrease in cash and cash equivalents		(189,700	)		(59,051	)
Cash and cash equivalents at beginning of period		408,193			298,565
Cash and cash equivalents at end of period	$	218,493		$	239,514
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	65,816		$	35,312
Supplemental disclosure of non-cash investing and financing activities:
Change in plant expenditures included in accounts payable	$	6,463		$	1,420

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

6

Oglethorpe Power Corporation
Notes to Unaudited Condensed Financial Statements
For the Three Months ended March 31, 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-month periods ended March 31, 2014 and 2013. 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, as filed with the SEC. The results of operations for the three-month period ended March 31, 2014 are not necessarily indicative of results to be expected for the full year. As noted in our 2013 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 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.

7

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

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

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

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

The tables below detail assets and liabilities measured at fair value on a recurring basis at March 31, 2014 and December 31, 2013.

			Fair Value Measurements at Reporting Date Using
		March 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	$	145,202	$	145,202	$	—	$	—
International equity trust		73,159		—		73,159		—
Corporate bonds		39,492		—		39,492		—
US Treasury and government agency securities		49,026		49,026		—		—
Agency mortgage and asset backed securities		29,654		—		29,654		—
Other		11,564		11,564		—		—
Long-term investments:
Corporate bonds		6,154		—		6,154		—
US Treasury and government agency securities		9,883		9,883		—		—
Agency mortgage and asset backed securities		3,267		—		3,267		—
International equity trust		11,259		—		11,259		—
Mutual funds		51,986		51,986		—		—
Other		44		44		—		—
Interest rate options		31,463		—		—		31,463	(1)
Natural gas swaps		1,960		—		1,960		—

8

			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 $10,730,000 and $34,970,000 of collateral received from the counterparties at March 31, 2014 and December 31, 2013, respectively.

The Level 2 investments above in international equity trust, 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 following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three months ended March 31, 2014 and 2013.

		Three Months Ended March 31, 2014
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2013	$	63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(32,008	)
Balance at March 31, 2014	$	31,463

9

		Three Months Ended March 31, 2013
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2012	$	25,783
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		756
Balance at March 31, 2013	$	26,539

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.

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

		2014				2013
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	6,933,851	$	7,534,625	$	6,954,293	$	7,317,476

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, 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 March 31, 2014 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 CoBank for valuation of the CoBank debt,

10

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.

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. We do not apply hedge accounting for these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on natural gas swaps are reflected as a regulatory asset or liability. To hedge the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, we have entered into interest rate options. Hedge accounting is not applied to our interest rate options. Consistent with our rate-making, unrealized gains or losses from the interest rate options are recorded as a regulatory asset. We do not hold or enter into derivative transactions for trading or speculative purposes.

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 March 31, 2014, 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 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

11

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

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

At March 31, 2014 and December 31, 2013, the estimated fair values of our natural gas contracts were a net asset of approximately $1,960,000 and $1,011,000, respectively.

As of March 31, 2014 and December 31, 2013, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2014 due to our credit rating being downgraded below investment grade, we would not have been required to post letters of credit with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of March 31, 2014 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2014	3.9
2015	1.1
Total	5.0

Interest rate options.     We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 to hedge the interest rates on approximately $2.2 billion of the expected debt that will be used to finance two additional nuclear units at Plant Vogtle. As of March 31, 2014, our outstanding swaptions hedged approximately $1.3 billion of the expected debt for the new Vogtle units.

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 85 basis points above the corresponding LIBOR swap rates that were in effect as of March 31, 2014 and the weighted average fixed rate is 4.12%. Swaptions having notional amounts totaling $138,317,000 expired without value during the three months ended March 31, 2014. The remaining swaptions expire quarterly through 2017.

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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 value. At March 31, 2014 and December 31, 2013, the fair value of these swaptions was approximately $31,463,000 and $63,471,000, 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 March 31, 2014 and December 31, 2013, we held $10,730,000 and $34,970,000 of funds posted as collateral 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 $20,733,000 and $28,501,000 at March 31, 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 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 March 31, 2014.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2014	$	425,107
2015		470,625
2016		310,533
2017		80,169
Total	$	1,286,434

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

	Balance Sheet Location		Fair Value
			2014		2013
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options(1)	Other deferred charges	$	31,463	$	63,471
Liabilities:
Natural gas swaps	Other current liabilities	$	1,960	$	1,011

⁽¹⁾

Excludes liability associated with cash collateral of $10,730,000 and $34,970,000 as of March 31, 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 months ended March 31, 2014 and 2013.

	Statement of Revenues and		Three months ended March 31,
	Expenses Location		2014		2013
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	279	$	117
Natural Gas Swaps	Fuel		—		(534	)
		$	279	$	(417	)

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

	Balance Sheet Location		2014			2013
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory liability	$	1,960		$	1,011
Interest rate options	Regulatory asset		(41,720	)		(15,003	)
		$	(39,760	)	$	(13,992	)

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
		(dollars in thousands)
March 31, 2014
Assets:
Natural gas swaps	$	2,054	$	(94	)	$	—		$	1,960
Interest rate options	$	31,463	$	—		$	(10,730	)	$	20,733
December 31, 2013
Assets:
Natural gas swaps	$	1,069	$	(58	)	$	—		$	1,011
Interest rate options	$	63,471	$	—		$	(34,970	)	$	28,501

(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 trust fund are directly added to or deducted from

14

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 86% of these gross unrealized losses were in effect for less than one year.

The following tables summarize the activities for available-for-sale securities as of March 31, 2014 and December 31, 2013.

	Gross Unrealized
		(dollars in thousands)
March 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	187,463	$	66,283	$	(1,190	)	$	252,556
Debt		165,776		8,509		(7,759	)		166,526
Other		11,607		2		(1	)		11,608
Total	$	364,846	$	74,794	$	(8,950	)	$	430,690

	Gross Unrealized
		(dollars in thousands)
December 31, 2013		Cost		Gains		Losses			Fair Value
Equity	$	182,755	$	68,424	$	(1,053	)	$	250,126
Debt		164,941		7,319		(9,070	)		163,190
Other		12,101		2		—			12,103
Total	$	359,797	$	75,745	$	(10,123	)	$	425,419

(E)

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 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 December 31, 2012	$	903
Unrealized (loss)		(148	)
(Gain) reclassified to net margin		(64	)
Balance at March 31, 2013	$	691
Balance at December 31, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)

(F)

Contingencies and Regulatory Matters.

Management does 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 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 Units 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.

Current 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

16

the Co-owners are responsible for these costs under the terms of the contract. The portion of the additional costs claimed by the Contractor that would be 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 further 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. 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. 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.

If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of March 31, 2014, 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. The lawsuit 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. The lawsuit also alleges 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 the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a regular 13-year revolving plan that retires 7.7% of total patronage capital owed to former consumer-members annually and seek relief to effect such retirements within the stated 13 year period. 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 we and Georgia Transmission should be required to implement a rate structure that would allow us and Georgia Transmission to begin retiring 7.7% of our allocated patronage capital annually. We intend to defend vigorously against all claims in this 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

17

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.

(G)

Restricted Cash.    At March 31, 2014 and December 31, 2013, we had restricted cash totaling $10,892,000 and $35,131,000, respectively, of which $10,736,000 and $34,975,000, respectively, was classified as long-term. The long-term restricted cash balance at March 31, 2014 and December 31, 2013 consisted primarily of funds posted as collateral by counterparties to our interest rate options.

(H)

Restricted Short-term Investments.    At March 31, 2014 and December 31, 2013, we had $289,469,000 and $272,686,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service guaranteed rate of 5% per annum.

(I)

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 unaudited condensed balance sheet as of March 31, 2014 and December 31, 2013.

		2014		2013
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	79,804	$	82,499
Amortization on capital leases(b)		14,756		16,124
Outage costs(c)		50,814		35,155
Interest rate swap termination fees(d)		12,338		13,336
Depreciation expense(f)		48,006		48,362
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g)		28,675		27,678
Interest rate options cost(h)		71,185		38,984
Deferral of effects on net margin—Smith Energy Facility(i)		75,168		63,491
Other regulatory assets(j)		5,023		5,479
Total Regulatory Assets	$	385,769	$	331,108
Regulatory Liabilities:
Accumulated retirement costs for other obligations(e)	$	23,195	$	24,520
Deferral of effects on net margin—Hawk Road Energy Facility(i)		25,289		23,379
Major maintenance reserve(k)		25,900		28,064
Deferred debt service adder(l)		59,617		57,223
Asset retirement obligations(e)		19,456		19,508
Other regulatory liabilities(j)		6,980		6,095
Total Regulatory Liabilities	$	160,437	$	158,789
Net Regulatory Assets	$	225,332	$	172,319

^(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 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)

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 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⁾

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 35 years and the amortization period of other regulatory liabilities range up to 18 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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(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 2014.

(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, each dated February 20, 2014, made by us to Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The Federal Financing Bank Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through 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 Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to 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 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 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 prior to February 20, 2020, up to a maximum of $335,471,604, is reflected as additional borrowings under the Facility.

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 Federal Financing Bank 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).

b)

Rural Utilities Service Guaranteed Loans:

For the three month period ended March 31, 2014, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $9,608,000 for general and environmental improvements at existing plants.

In April 2014, we received an additional $10,674,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants as well.

(L)

Subsequent Events.    On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC for additional firm natural gas transportation to our Smith facility. The agreement has a base term of 25 years, and the fixed charge for the base term is $37,700,000 per year. Our obligation to make payments begins when the pipeline expansion project goes into service, which is projected to be May 1, 2017.

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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 Months Ended March 31, 2014 and 2013

Net Margin

Our net margin for the three-month period ended March 31, 2014 was $19.2 million compared to $22.0 million for the same period of 2013. Through March 31, 2014, we collected approximately 41% of our targeted net margin of $47.1 million for the year ending December 31, 2014. 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 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 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 revenues from sales to members increased 16.8% in the three-month period ended March 31, 2014 compared to the same period of 2013. Megawatt-hour sales to members increased 18.1% for the three-month period ended March 31, 2014 compared to the same period of 2013. The average total revenue per megawatt-hour from sales to members decreased 1.1% for the three-month period ended March 31, 2014 compared to the same period of 2013. The increases in revenues from sales to members and in megawatt-hour sales to members were driven primarily by the extreme cold weather that occurred during the first quarter of 2014.

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The components of member revenues for the three-month periods ended March 31, 2014 and 2013 were as follows (amounts in thousands except for cents per kilowatt-hour):

		Three Months Ended March 31,
	2014		2013
Capacity revenues	$	191,676	$	181,114
Energy revenues		143,083		105,539
Total	$	334,759	$	286,653
Kilowatt-hours sold to members		4,905,224		4,153,662
Cents per kilowatt-hour		6.83¢		6.90¢

Capacity revenues from members increased 5.8% for the three-month period ended March 31, 2014 compared to the same period of 2013. 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 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 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.

Energy revenues were 35.6% higher for the three-month period ended March 31, 2014 compared to the same period of 2013. Our average energy revenue per megawatt-hour from sales to members increased 14.8% for the three-month period ended March 31, 2014 as compared to the same period of 2013. This increase resulted primarily from higher cost coal-fired generation and higher natural gas prices. 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 period ended March 31, 2014 were 68.9% higher as compared to the same period of 2013. This increase was primarily due to sales of natural gas of $10.8 million.

Operating Expenses

Operating expenses for the three-month period ended March 31, 2014 increased 24.8% as compared to the same period of 2013. This increase was due to higher fuel costs, production costs, depreciation and amortization expenses and purchased power costs as compared to the same period of 2013.

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

		Three Months Ended March 31,
		2014					2013
Fuel Source		Cost	Generation		Cost per MWh		Cost	Generation		Cost per MWh
		(thousands)	(MWh)				(thousands)	(MWh)
Coal	$	56,486	1,896,226	$	29.79	$	40,646	1,483,954	$	27.39
Nuclear		20,765	2,225,966		9.33		18,332	2,085,092		8.79
Gas:
Combined Cycle		51,201	1,138,084		44.99		40,138	1,276,553		31.44
Combustion Turbine		3,824	21,425		178.48		1,034	16,764		61.68
	$	132,276	5,281,701	$	25.04	$	100,150	4,862,363	$	20.60

For the three-month period ended March 31, 2014, total fuel costs increased 32.1% and megawatt-hour generation increased 8.6%, respectively, compared to the same period of 2013. The extreme cold weather in 2014 as compared to 2013 contributed to the increase in megawatt-hours of generation. Average fuel costs per megawatt-hour increased 21.6% in the three-month period ended March 31, 2014 compared to the same period of 2013. The increase in total fuel costs was partly due to higher generation from our coal-fired plants and nuclear plants and partly due to higher natural gas prices for fuel to run our natural gas-fired facilities. Plant Wansley, which is fueled by higher cost eastern coal, generated 132,000 megawatts hours in the first quarter of 2014 whereas for the same period of 2013 it was in reserve shutdown, primarily due to more economical generation from natural gas-fired facilities. Generation from Plant Scherer increased 18.5% during the three-month period ended March 31, 2014 as compared to the same period of 2013 due to increased demand from our members. Generation from the nuclear facilities increased 6.8% primarily due to normal fluctuations between fiscal periods related to the timing of scheduled outages as well as an unscheduled outage at Hatch Unit No. 1 in 2013. Generation from our gas-fired facilities decreased in the three-month period ended March 31, 2014 versus the same period of 2013 due to lower utilization of the Smith Energy Facility, although the remainder of our gas-fired facilities experienced a slight increase in generation. The decrease in generation from gas-fired facilities was more than offset by increased natural gas prices in 2014 thus fuel costs for gas-fired facilities accounted for 43.1% of the overall increase in total fuel costs.

Production costs increased 14.1% for the three-month period ended March 31, 2014 as compared to the same period of 2013. The increase resulted partly from the cost of gas sold to non-members of $6 million as discussed above and partly from higher operations and maintenance costs at our co-owned facilities (primarily Plant Vogtle) and from higher costs at the Talbot Energy Facility due to planned outage work in 2014.

Depreciation and amortization costs increased 9.8% for the three-month period ended March 31, 2014 as compared to the same period of 2013. The increase in depreciation expense in the first quarter of 2014 as compared to the first quarter of 2013 was primarily due to $291 million of environmental capital improvements at Plant Scherer that were primarily placed into service in May and August of 2013.

Interest charges

Interest expense increased 8.1% for the three-month period ended March 31, 2014 as compared to the same period of 2013 primarily due to increased debt to finance construction of Vogtle Units No. 3 and No. 4.

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Allowance for debt funds used during construction decreased 4.5% in the three-month period ended March 31, 2014 compared to the same period of 2013 primarily due to environmental capital improvements at Scherer being placed into service as discussed above. The decrease was offset somewhat by an increase in construction work in progress for Vogtle No. 3 and No. 4.

Financial Condition

Balance Sheet Analysis as of March 31, 2014

Assets

Cash used for property additions for the three-month period ended March 31, 2014 totaled $134.4 million. Of this amount, approximately $74 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $33 million for normal additions and replacements to existing generation facilities and $19 million for nuclear fuel purchases. The remaining expenditures were for environmental control systems being installed primarily at Plant Scherer.

The $289.5 million of restricted short-term investments at March 31, 2014 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.

Deferred debt expense, being amortized increased $40.7 million for the three months ending March 31, 2014 due to debt costs associated with a $3.057 billion loan with the Department of Energy, which closed in February 2014, to finance a portion of the costs associated with the Vogtle Units No. 3 and No. 4 construction project. For information regarding this loan see Note K.

Equity and Liabilities

Accounts payable decreased $28.7 million for the three-month period ended March 31, 2014. The December 31, 2013 payable balance included $38.4 million in credits due to the members for a board approved reduction to 2013 revenue requirements as a result of margins collected in excess of our 2013 target. These credits were applied to the members' bills in the first quarter of 2014. Offsetting the decrease was an $11.3 million increase in the payable to Georgia Power for operation and maintenance costs for our co-owned facilities and capital costs associated with Vogtle Units No. 3 and No. 4 construction.

Member power bill prepayments represent funds received from the members for the prepayment of their monthly power bills. At March 31, 2014, $92.5 million of member power bill prepayments was classified as a current liability and $34.4 million was classified as a long-term liability. During the three-month period ended March 31, 2014, $20.1 million of prepayments were received from the members and $7.9 million was applied to the members' monthly power bills. For information regarding the power bill prepayment program, see Note J.

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 March 31, 2014, our total investment in Vogtle Units No. 3 and No. 4 was $2.1 billion.

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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 2013 Form 10-K. Also see Note F of Notes to Unaudited Condensed Financial Statements herein.

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.

Two recent court decisions each upheld one of EPA's final rules that affect us. On April 15, 2014, the U.S. Court of Appeals for the District of Columbia Circuit upheld the EPA's final Mercury and Air Toxics Standards (MATS) rule, which establishes maximum achievable control technology limits for certain hazardous air pollutants at coal and oil-fired electric generating units. For coal units, the rule sets stringent emission limits to control various hazardous air pollutants such as mercury, non-mercury metals and acid gases and work practice standards to control organics and dioxins. Affected generating units, which include our co-owned units at Plants Wansley and Scherer, have until April 16, 2015 to comply with the rule, although controls are currently installed at both of those plants which are expected to meet the new requirements. Whether the Court's decision will be appealed is not known at this time and we cannot predict the outcome of any future litigation.

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 Circuit which had invalidated the CSAPR. The Supreme Court remanded the case back to Court of Appeals for the D.C. Circuit which could remand the case to EPA for further rulemaking to implement the CSAPR which is unlikely before mid-2015. The final rule may affect future operations of our co-owned units at Plants Scherer and Wansley; however, we do not anticipate the need to purchase allowances given the completion of additional pollution control equipment earlier this year.

Also, on April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new or modification to existing generation facilities. In addition, the proposed rule could have significant impacts on economic development projects which could impact demand. The ultimate impact of the rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined at this time.

Separately, the dates for finalizing several other rules have recently been delayed. For example, the deadline for finalization of the Coal Combustion Residuals Rule has slipped to December 19, 2014, the Effluent Limitation Guidelines rule finalization deadline has slipped to September 30, 2015 and the Cooling Water Intake or 316(b) rule finalization deadline has slipped to May 16, 2014. The impacts of these rulemakings cannot be determined at this time and will depend on the final regulations and any ensuing litigation.

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 2013 Form 10-K.

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Liquidity

At March 31, 2014, we had $1.6 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $218 million in cash and cash equivalents and $1.4 billion of unused and available committed credit arrangements.

At March 31, 2014, we had in excess of $1.9 billion of committed credit arrangements in place and $1.4 billion available under these facilities. These six separate facilities are reflected in the table below:

Committed Credit Facilities
		Authorized Amount		Available March 31, 2014		Expiration Date
		(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by Bank of America	$	1,265	$	860	(1)	June 2015
Syndicated Line of Credit led by CoBank		150		150		September 2014
CFC Line of Credit		110		110		September 2016
CFC Line of Credit(2)		210		210		December 2018
JPMorgan Chase Line of Credit		150		34	(3)	December 2018
Secured Facilities:
CFC Term Loan(2)		250		250		December 2018

⁽¹⁾

Of the portion of this facility that was unavailable at March 31, 2014, $269.7 million was dedicated to support outstanding commercial paper and $135.5 million was related to letters of credit issued to support variable rate demand bonds.

⁽²⁾

Any amounts drawn under the $210 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.

⁽³⁾

Of the portion of this facility that was unavailable at March 31, 2014, $113.7 million related to letters of credit issued to support variable rate demand bonds and $2.2 million related to letters of credit issued to post collateral to third parties.

As of March 31, 2014, we were using our commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 and for the upfront premium 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 $1.045 billion in the aggregate, of which $794 million remained available at March 31, 2014. 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.

Between our credit arrangements and projected cash on hand, 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 March 31, 2014, the required minimum level was $675 million and our actual patronage capital was $734 million. Additional covenants contained in several of our credit facilities limit the amount of secured indebtedness and unsecured indebtedness we can have outstanding. At

27

March 31, 2014, the most restrictive of these covenants limits our secured indebtedness to $12.0 billion and our unsecured indebtedness to $4.0 billion. At March 31, 2014, we had $7.1 billion of secured indebtedness and $269.7 million of unsecured indebtedness outstanding, which was well within the covenant thresholds.

At March 31, 2014, current assets included $289.5 million of restricted short-term investments pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account. See "—Balance Sheet Analysis as of March 31, 2014—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At March 31, 2014, we had $6.9 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 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    We currently have four approved Rural Utilities Service-guaranteed loans, totaling $871 million, which are being funded through the Federal Financing Bank and are in various stages of being drawn down, with $448 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture.

Department of Energy-Guaranteed Loan.    On February 20, 2014, we closed on a loan with the Department of Energy that will fund up to $3.057 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. The loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy. At March 31, 2014, $2.3 billion of this loan remains to be advanced. All of the debt under this loan will be secured under our first mortgage indenture.

Bond Financing.

In May 2014, we plan to issue up to $250 million of taxable first mortgage bonds to provide long-term financing for general and environmental improvements to certain of our existing facilities.

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 Form 10-K.

Newly Adopted or Issued Accounting Standards

Not Applicable.

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 Form 10-K.

Item 4.    Controls and Procedures

As of March 31, 2014, 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 March 31, 2014 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

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. The lawsuit 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. The lawsuit also alleges 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 the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a regular 13-year revolving plan that retires 7.7% of total patronage capital owed to former consumer-members annually and seek relief to effect such retirements within the stated 13 year period. 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 we and Georgia Transmission should be required to implement a rate structure that would allow us and Georgia Transmission to begin retiring 7.7% of our allocated patronage capital annually. We intend to defend vigorously against all claims in this litigation.

The ultimate outcome of this litigation cannot be predicted at this time; however, management does not anticipate that the ultimate liabilities, if any, arising from this proceeding would have a material effect on our financial condition or results of operations. See Note F of Notes to Unaudited Condensed Financial Statements for information about other loss contingencies.

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 2013 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

On May 12, 2014, our board of directors appointed Mr. Ernest Adelburt Jakins III to serve as a director for member group 5. Mr. Jakins' appointment fills the vacancy created when Mr. G. Randall Pugh retired as President and Chief Executive Officer of Jackson Electric Membership Corporation and became ineligible to serve on our board of directors in March 2014. Mr. Jakins' present term will extend until our members elect a new member director for group 5 at our annual meeting of members in March 2015.

For additional information regarding our board of directors and election procedures, see "Item 10—DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE" of our 2013 Form 10-K.

29

Item 6.    Exhibits

Number		Description
	10.1	Amendment No. 6, dated as of January 23, 2014, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone and Webster, as contractor for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)2 of Georgia Power Company's Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 8, 2014.)
	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 2011-2013).
	101	XBRL Interactive Data File.

30

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: May 12, 2014	By:	/s/ Michael L. Smith Michael L. Smith President and Chief Executive Officer
Date: May 12, 2014		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

31

EX-31.1

EXHIBIT 31.1

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

(Principal Executive Officer)

I, Michael L. Smith, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Oglethorpe Power Corporation (An Electric Membership Corporation);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 12, 2014

/s/ Michael L. Smith

Michael L. Smith

President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins

(Principal Financial Officer)

I, Elizabeth B. Higgins, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Oglethorpe Power Corporation (An Electric Membership Corporation);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 12, 2014

/s/ Elizabeth B. Higgins

Elizabeth B. Higgins

Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014 (the “Report”) of Oglethorpe Power Corporation (the “Registrant”), as filed with the Securities and Exchange Commission on the date hereof, I, Michael L. Smith, the President and Chief Executive Officer of the Registrant certify, to the best of my knowledge, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Michael L. Smith

Michael L. Smith

President and Chief Executive Officer

May 12, 2014

Date

EX-32.2

EXHIBIT 32.2

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014 (the “Report”) of Oglethorpe Power Corporation (the “Registrant”), as filed with the Securities and Exchange Commission on the date hereof, I, Elizabeth B. Higgins, the Executive Vice President and Chief Financial Officer of the Registrant certify, to the best of my knowledge, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Elizabeth B. Higgins

Elizabeth B. Higgins

Executive Vice President and
Chief Financial Officer

May 12, 2014

Date

EX-99.1

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Exhibit 99.1

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

        Our members operate their systems on a not-for-profit basis. Accumulated margins derived after payment of operating expenses and provision for depreciation constitute patronage capital of the consumers of our members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between our members and the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgage generally prohibits such distributions unless, after any such distribution, the member's total equity will equal at least 30% of its total assets, except that distributions may be made of up to 25% of the margins and patronage capital received by the member in the preceding year provided that equity is at least 20%.

        We are a membership corporation, and our members are not our subsidiaries. Except with respect to the obligations of our members under each member's wholesale power contract with us and our rights under such contracts to receive payment for power and energy supplied, we have no legal interest in, or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of our members.

        The following selected information on the individual members is intended to show, in the aggregate, the assets, liabilities, equity, revenues and margins of our members. Member assets, liabilities, equity, revenues and margins should not, however, be attributed to us. In addition, the revenues of our members are not pledged to us, but such revenues are received by the respective members and are the source from which moneys are derived by our members to pay for power and energy received from us. Revenues of our members are, however, pledged under their respective Rural Utilities Service mortgages or loan documents with other lenders.

        The information contained in these tables was taken from Rural Utilities Service Financial and Statistical Reports (RUS Form 7) or similar reports prepared for other lenders or provided directly by a member. This information has not been independently verified by the Rural Utilities Service, any lender or us. The "Total" columns were not supplied or compiled by the Rural Utilities Service, any lender or our members. The "Total" column in each table is for informational purposes only, inasmuch as each member operates independently and is not responsible for the obligations of other members, except as provided in the wholesale power contracts (see "BUSINESS—OGLETHORPE POWER CORPORATION—Wholesale Power Contracts" in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013). In addition, the Times Interest Earned, Equity to Assets and Equity to Total Capitalization ratios were calculated by us from information obtained from each member's RUS Form 7 or other financial information provided to us, but the calculations were not independently verified by our members. No adjustments were made by us in calculating these ratios for items such as debt refinancings that are not reflected separately on the financial information provided to us.

        For the calendar years 2011, 2012 and 2013, the information on the individual members is presented in the succeeding tables as follows:

Table 1—Selected Statistics,
Table 2—Average Number of Consumers Served,
Table 3—Annual Megawatt-hour Sales by Consumer Class,
Table 4—Annual Revenues by Consumer Class,
Table 5—Summary of Operating Results, and
Table 6—Condensed Balance Sheet Information.

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 1
SELECTED STATISTICS OF EACH MEMBER
(as of December 31)

	Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette		Diverse
2013
Avg. Monthly Residential Rev. ($)		138.02		130.24		142.43		139.26		109.23		159.79		121.01		130.58		130.75		155.87
Avg. Monthly Residential kWh		1,051		1,156		1,162		1,152		1,252		1,214		1,102		1,181		1,210		1,318
Avg. Residential Rev.(cents per kWh)		13.14		11.27		12.26		12.09		8.72		13.16		10.98		11.06		10.80		11.83
Times Interest Earned Ratio (1)		2.12		1.93		2.70		2.08		1.70		1.57		1.21		2.50		2.44		1.89
Equity/Assets (1)		65%		45%		44%		38%		35%		31%		43%		39%		39%		39%
Equity/Total Capitalization (1)		70%		59%		52%		45%		39%		36%		48%		48%		43%		43%
2012
Avg. Monthly Residential Rev. ($)		139.96		127.27		140.19		134.61		115.01		157.04		129.52		127.26		125.79		157.74
Avg. Monthly Residential kWh		1,046		1,115		1,160		1,124		1,253		1,205		1,141		1,184		1,224		1,297
Avg. Residential Rev.(cents per kWh)		13.39		11.41		12.08		11.98		9.18		13.03		11.35		10.75		10.28		12.16
Times Interest Earned Ratio (1)		3.18		1.84		2.62		1.78		2.04		1.41		2.32		2.61		2.32		1.72
Equity/Assets (1)		66%		44%		42%		37%		36%		30%		42%		42%		37%		47%
Equity/Total Capitalization (1)		71%		58%		49%		43%		39%		33%		48%		50%		41%		52%
2011
Avg. Monthly Residential Rev. ($)		144.84		136.94		135.31		136.78		130.03		165.87		138.43		126.31		137.10		161.14
Avg. Monthly Residential kWh		1,197		1,237		1,299		1,220		1,368		1,359		1,211		1,330		1,312		1,419
Avg. Residential Rev.(cents per kWh)		12.10		11.07		10.41		11.21		9.51		12.20		11.43		9.50		10.45		11.36
Times Interest Earned Ratio (1)		2.59		1.97		1.93		1.39		1.78		1.40		2.32		2.73		2.34		2.39
Equity/Assets (1)		64%		43%		38%		37%		34%		31%		36%		43%		35%		47%
Equity/Total Capitalization (1)		69%		60%		47%		44%		37%		34%		43%		51%		38%		54%
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2013
Avg. Monthly Residential Rev. ($)		145.83		152.93		119.44		134.78		144.22		140.85		134.25		140.87		129.20		134.53
Avg. Monthly Residential kWh		1,218		1,184		987		1,116		1,152		1,184		1,009		1,190		1,196		1,123
Avg. Residential Rev.(cents per kWh)		11.97		12.91		12.11		12.08		12.52		11.89		13.30		11.84		10.80		11.98
Times Interest Earned Ratio (1)		0.33		2.37		2.04		1.27		1.51		2.18		1.03		2.90		2.41		2.64
Equity/Assets (1)		34%		51%		45%		32%		35%		52%		25%		44%		41%		39%
Equity/Total Capitalization (1)		39%		60%		53%		40%		40%		58%		30%		54%		53%		49%
2012
Avg. Monthly Residential Rev. ($)		128.78		149.44		113.27		128.73		142.04		137.25		130.68		138.12		129.54		129.25
Avg. Monthly Residential kWh		1,209		1,108		978		1,115		1,165		1,179		994		1,185		1,241		1,114
Avg. Residential Rev.(cents per kWh)		10.65		13.49		11.58		11.55		12.20		11.64		13.15		11.66		10.43		11.60
Times Interest Earned Ratio (1)		2.20		2.37		2.12		1.44		1.73		2.52		1.14		3.19		3.08		2.19
Equity/Assets (1)		39%		52%		43%		33%		35%		52%		26%		45%		43%		39%
Equity/Total Capitalization (1)		44%		64%		52%		41%		40%		59%		30%		54%		55%		49%
2011
Avg. Monthly Residential Rev. ($)		153.08		154.45		122.33		150.15		152.15		148.62		136.07		139.45		132.98		140.34
Avg. Monthly Residential kWh		1,377		1,349		1,103		1,228		1,245		1,342		1,096		1,331		1,326		1,243
Avg. Residential Rev.(cents per kWh)		11.12		11.45		11.09		12.22		12.22		11.07		12.41		10.48		10.03		11.29
Times Interest Earned Ratio (1)		2.68		2.17		2.10		1.57		1.63		2.82		1.39		3.06		2.01		2.29
Equity/Assets (1)		40%		53%		43%		32%		33%		51%		28%		42%		38%		38%
Equity/Total Capitalization (1)		44%		65%		51%		39%		38%		58%		33%		51%		47%		48%

Footnotes:

(1)

Times Interest Earned and Equity ratios were calculated from information contained on each Member's RUS Form 7, or similar form provided to another lender, and were not independently verified by each respective Member.

(2)

Weighted Average.

Table 1 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2013
Avg. Monthly Residential Rev. ($)		118.11		143.04		136.66		120.91		127.71		131.38		153.03		121.54		140.50	130.37
Avg. Monthly Residential kWh		1,235		1,267		1,092		1,168		1,019		1,083		1,152		1,234		1,113	991
Avg. Residential Rev.(cents per kWh)		9.56		11.29		12.52		10.35		12.54		12.13		13.29		9.85		12.63	13.16
Times Interest Earned Ratio (1)		2.24		1.37		2.82		2.19		1.71		2.11		0.45		1.94		2.56	1.72
Equity/Assets (1)		58%		33%		45%		42%		32%		42%		30%		40%		42%	33%
Equity/Total Capitalization (1)		66%		40%		57%		47%		38%		51%		32%		46%		51%	40%
2012
Avg. Monthly Residential Rev. ($)		117.33		130.70		131.50		117.94		120.42		126.30		137.42		120.52		139.06	127.10
Avg. Monthly Residential kWh		1,231		1,271		1,081		1,158		987		1,057		1,062		1,225		1,121	987
Avg. Residential Rev.(cents per kWh)		9.53		10.29		12.16		10.18		12.20		11.95		12.93		9.84		12.41	12.88
Times Interest Earned Ratio (1)		2.14		1.61		2.30		1.72		1.41		1.91		1.37		1.97		2.18	1.52
Equity/Assets (1)		59%		35%		45%		42%		31%		43%		33%		40%		40%	32%
Equity/Total Capitalization (1)		66%		41%		55%		47%		36%		52%		36%		46%		49%	37%
2011
Avg. Monthly Residential Rev. ($)		125.18		142.23		137.93		126.01		130.07		136.82		163.30		123.24		144.36	135.87
Avg. Monthly Residential kWh		1,376		1,423		1,230		1,262		1,089		1,166		1,307		1,345		1,252	1,094
Avg. Residential Rev.(cents per kWh)		9.09		9.99		11.21		9.99		11.95		11.73		12.49		9.16		11.53	12.42
Times Interest Earned Ratio (1)		2.18		2.06		2.16		1.67		1.64		2.31		1.49		2.27		1.82	1.83
Equity/Assets (1)		58%		37%		46%		40%		33%		42%		34%		38%		42%	33%
Equity/Total Capitalization (1)		64%		44%		56%		45%		39%		51%		36%		44%		52%	38%
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2013
Avg. Monthly Residential Rev. ($)		121.08		153.37		160.29		115.67		139.00		118.63		126.45		119.22			129.49
Avg. Monthly Residential kWh		1,252		1,252		1,317		887		1,142		1,063		1,238		1,036			1,179
Avg. Residential Rev.(cents per kWh)		9.67		12.3		12.18		13.0		12.17		11.16		10.21		11.50			10.99
Times Interest Earned Ratio (1)		1.52		2.00		1.85		1.64		1.56		2.45		3.48		2.17			1.92 (2)
Equity/Assets (1)		41%		33%		47%		38%		34%		51%		44%		52%			41% (2)
Equity/Total Capitalization (1)		54%		40%		52%		43%		37%		59%		58%		57%			48% (3)
2012
Avg. Monthly Residential Rev. ($)		119.67		146.76		157.56		108.47		133.89		117.62		126.55		119.42			128.13
Avg. Monthly Residential kWh		1,268		1,225		1,315		887		1,132		1,061		1,256		1,031			1,182
Avg. Residential Rev.(cents per kWh)		9.44		11.99		11.98		12.24		11.83		11.09		10.08		11.58			10.84
Times Interest Earned Ratio (1)		1.42		2.38		2.16		1.91		1.65		2.47		3.06		2.20			2.12 (2)
Equity/Assets (1)		43%		36%		48%		40%		35%		51%		40%		51%			41% (2)
Equity/Total Capitalization (1)		55%		43%		53%		44%		37%		59%		53%		56%			48% (2)
2011
Avg. Monthly Residential Rev. ($)		126.33		155.46		168.74		117.95		148.20		122.24		127.35		129.28			134.70
Avg. Monthly Residential kWh		1,391		1,352		1,470		1,008		1,263		1,138		1,369		1,131			1,296
Avg. Residential Rev.(cents per kWh)		9.08		11.50		11.48		11.70		11.73		10.75		9.30		11.43			10.39
Times Interest Earned Ratio (1)		1.55		2.12		2.42		1.90		1.84		1.91		2.99		2.02			2.11 (2)
Equity/Assets (1)		42%		36%		46%		42%		33%		50%		41%		51%			39% (2)
Equity/Total Capitalization (1)		54%		42%		51%		48%		35%		57%		51%		56%			46% (2)

Footnotes:

(1)

Times Interest Earned and Equity ratios were calculated from information contained on each Member's RUS Form 7, or similar form provided to another lender, and were not independently verified by each respective Member.

(2)

Weighted Average.

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 2
AVERAGE NUMBER OF CONSUMERS SERVED BY EACH MEMBER

	Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette		Diverse
2013
Residential Service		17,996		41,847		19,847		46,533		47,704		14,912		178,149		57,724		69,043		24,995
Commercial & Industrial		1,791		4,277		337		2,460		4,314		2,016		16,209		3,439		5,872		3,683
Other		186		9		392		368		289		146		7,322		2,592		739		167
Total Consumers Served		19,973		46,133		20,576		49,361		52,307		17,074		201,680		63,755		75,654		28,845
2012
Residential Service		17,954		41,576		19,850		46,315		46,978		14,917		176,576		57,406		68,378		24,857
Commercial & Industrial		1,791		4,196		329		2,460		4,217		1,944		15,668		3,408		5,802		3,614
Other		165		9		369		372		284		144		5,503		2,424		733		157
Total Consumers Served		19,910		45,781		20,548		49,147		51,479		17,005		197,747		63,238		74,913		28,628
2011
Residential Service		17,930		41,500		19,690		46,172		46,692		14,745		175,159		57,146		68,038		24,752
Commercial & Industrial		1,785		4,225		324		2,477		4,198		1,842		15,540		3,606		5,737		3,589
Other		137		9		329		375		271		131		5,455		1,966		725		162
Total Consumers Served		19,852		45,734		20,343		49,024		51,161		16,718		196,154		62,718		74,500		28,503
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2013
Residential Service		5,122		21,168		10,770		10,692		32,083		15,046		15,736		49,023		140,420		7,820
Commercial & Industrial		1,704		1,174		660		1,766		2,342		571		2,509		2,533		15,395		377
Other		989		2,654		511		164		432		850		—		2,155		1,396		246
Total Consumers Served		7,815		24,996		11,941		12,622		34,857		16,467		18,245		53,711		157,211		8,443
2012
Residential Service		5,111		21,269		10,807		10,809		31,999		15,022		15,773		48,699		137,045		7,756
Commercial & Industrial		1,702		1,149		650		1,656		2,329		579		2,463		2,550		15,138		359
Other		902		2,510		502		156		420		789		—		2,044		1,405		240
Total Consumers Served		7,715		24,928		11,959		12,621		34,748		16,390		18,236		53,293		153,588		8,355
2011
Residential Service		5,084		21,259		10,788		10,921		31,967		14,984		15,881		48,535		135,051		7,697
Commercial & Industrial		1,702		1,167		647		1,530		2,356		584		2,440		2,511		14,967		350
Other		844		2,310		464		144		412		712		—		1,929		1,388		231
Total Consumers Served		7,630		24,736		11,899		12,595		34,735		16,280		18,321		52,975		151,406		8,278

Table 2 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2013
Residential Service		20,286		70,990		18,343		111,966		31,426		28,198		9,849		189,650		31,023		10,555
Commercial & Industrial		1,345		9,629		477		8,534		2,394		7,169		125		16,085		1,702		133
Other		339		948		615		246		7		9		1,126		4,570		369		385
Total Consumers Served		21,970		81,567		19,435		120,746		33,827		35,376		11,100		210,305		33,094		11,073
2012
Residential Service		20,134		70,687		18,276		110,948		31,340		28,293		10,599		186,860		31,004		10,542
Commercial & Industrial		1,324		9,394		460		8,388		2,360		7,086		133		15,848		1,623		131
Other		309		913		585		301		7		9		1,122		4,511		324		358
Total Consumers Served		21,767		80,994		19,321		119,637		33,707		35,388		11,854		207,219		32,951		11,031
2011
Residential Service		20,030		69,981		18,183		109,897		31,314		28,350		9,743		185,662		30,913		10,499
Commercial & Industrial		1,326		9,125		453		9,965		2,335		6,972		122		15,704		1,584		130
Other		280		865		553		1,795		6		7		938		4,459		285		345
Total Consumers Served		21,636		79,971		19,189		121,657		33,655		35,329		10,803		205,825		32,782		10,974
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2013
Residential Service		87,686		17,495		14,665		13,867		19,087		8,305		110,466		14,641				1,635,128
Commercial & Industrial		4,060		1,081		4,792		1,383		1,898		702		7,707		618				143,263
Other		1,040		16		573		3		—		116		1,698		88				33,755
Total Consumers Served		92,786		18,592		20,030		15,253		20,985		9,123		119,871		15,347				1,812,146
2012
Residential Service		86,874		17,502		14,678		13,878		19,097		8,352		109,229		14,619				1,622,009
Commercial & Industrial		4,189		1,071		4,752		523		1,896		722		7,647		621				140,172
Other		1,024		17		503		777		—		116		1,671		66				31,741
Total Consumers Served		92,087		18,590		19,933		15,178		20,993		9,190		118,547		15,306				1,793,922
2011
Residential Service		86,519		17,486		14,654		13,817		19,085		8,386		108,732		14,599				1,611,841
Commercial & Industrial		4,311		1,039		4,707		537		1,891		738		7,604		619				140,739
Other		1,020		18		439		687		—		116		1,659		50				31,516
Total Consumers Served		91,850		18,543		19,800		15,041		20,976		9,240		117,995		15,268				1,784,096

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 3
ANNUAL MWh SALES BY CONSUMER CLASS OF EACH MEMBER

	Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette		Diverse
2013
Residential Service		226,875		580,517		276,675		643,101		716,638		217,327		2,356,264		817,927		1,002,732		395,320
Commercial & Industrial		142,649		103,946		114,650		361,089		366,766		218,963		1,192,155		248,212		418,518		141,670
Other		5,595		183		4,352		6,297		3,800		2,421		231,140		80,339		8,579		13,189
Total MWh Sales		375,119		684,647		395,677		1,010,487		1,087,204		438,711		3,779,559		1,146,478		1,429,829		550,179
2012
Residential Service		225,255		556,345		276,349		624,448		706,270		215,713		2,417,032		815,760		1,003,980		386,931
Commercial & Industrial		137,111		103,980		107,704		376,060		345,873		208,017		1,181,952		254,549		426,156		143,420
Other		6,118		183		6,274		6,475		3,816		2,397		235,797		88,884		8,337		9,657
Total MWh Sales		368,484		660,508		390,327		1,006,982		1,055,959		426,127		3,834,781		1,159,194		1,438,472		540,008
2011
Residential Service		257,567		615,854		306,985		676,228		766,318		240,498		2,545,519		911,721		1,071,569		421,342
Commercial & Industrial		134,150		108,170		104,015		368,161		346,938		204,698		1,198,600		251,498		427,774		139,527
Other		7,138		176		8,105		6,939		3,651		2,378		242,659		103,089		8,048		10,886
Total MWh Sales		398,855		724,199		419,105		1,051,328		1,116,907		447,574		3,986,778		1,266,308		1,507,391		571,756
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2013
Residential Service		74,877		300,854		127,498		143,178		443,426		213,857		190,608		699,882		2,015,890		105,387
Commercial & Industrial		38,043		66,339		44,271		181,530		65,291		24,952		55,239		321,234		1,040,536		59,640
Other		10,588		53,386		5,024		3,050		17,415		14,198		—		30,979		29,695		4,086
Total MWh Sales		123,508		420,579		176,793		327,758		526,132		253,007		245,847		1,052,095		3,086,121		169,112
2012
Residential Service		74,133		282,713		126,823		144,587		447,203		212,605		188,110		692,485		2,041,618		103,698
Commercial & Industrial		39,918		62,555		44,255		166,124		54,542		24,288		53,945		304,978		1,048,714		52,494
Other		25,164		69,456		10,084		5,114		18,944		19,489		—		32,959		29,878		7,032
Total MWh Sales		139,215		414,725		181,162		315,825		520,689		256,382		242,055		1,030,422		3,120,211		163,224
2011
Residential Service		84,011		344,051		142,793		160,973		477,729		241,311		208,904		775,031		2,149,470		114,783
Commercial & Industrial		40,161		69,819		44,654		159,367		55,637		22,160		55,936		297,682		1,048,860		53,376
Other		29,995		90,410		11,206		5,065		19,163		22,845		—		39,775		29,909		7,861
Total MWh Sales		154,166		504,280		198,652		325,405		552,528		286,315		264,839		1,112,488		3,228,239		176,019

Table 3 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2013
Residential Service		300,698		1,079,290		240,270		1,569,336		384,189		366,492		136,116		2,809,034		414,191		125,496
Commercial & Industrial		67,924		522,242		39,087		1,053,568		95,030		178,374		27,306		1,831,132		107,039		48,234
Other		3,568		38,519		14,632		16,813		142		447		12,848		284,046		12,516		4,830
Total MWh Sales		372,190		1,640,050		293,990		2,639,717		479,361		545,313		176,270		4,924,212		533,746		178,560
2012
Residential Service		297,528		1,077,807		237,108		1,542,369		371,336		358,844		135,124		2,747,209		416,900		124,859
Commercial & Industrial		69,159		543,911		42,826		1,041,476		94,655		176,174		27,843		1,800,213		117,404		48,177
Other		5,400		52,153		14,975		15,121		142		596		22,702		277,871		16,719		6,138
Total MWh Sales		372,087		1,673,871		294,908		2,598,967		466,132		535,614		185,669		4,825,293		551,022		179,175
2011
Residential Service		330,838		1,195,307		268,406		1,664,012		409,187		396,698		152,803		2,997,455		464,256		137,831
Commercial & Industrial		69,462		546,742		42,421		1,042,621		98,168		176,360		28,253		1,784,748		119,926		49,694
Other		7,237		53,177		19,606		15,238		118		594		26,497		289,326		18,066		7,592
Total MWh Sales		407,538		1,795,227		330,433		2,721,871		507,473		573,653		207,553		5,071,530		602,247		195,116
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2013
Residential Service		1,317,677		262,783		231,679		147,675		261,648		105,934		1,641,384		182,061				23,124,789
Commercial & Industrial		442,219		49,161		89,981		28,540		87,308		14,297		649,173		165,521				10,701,826
Other		16,404		4,900		22,075		31,358		—		2,753		71,847		2,554				1,064,569
Total MWh Sales		1,776,300		316,844		343,735		207,573		348,955		122,985		2,362,404		350,136				34,891,184
2012
Residential Service		1,322,091		257,179		231,649		147,637		259,364		106,298		1,646,202		180,833				23,002,397
Commercial & Industrial		447,561		49,542		94,258		28,308		87,066		14,849		642,975		167,031				10,630,062
Other		16,147		5,107		34,627		35,324		—		2,242		73,303		4,338				1,168,965
Total MWh Sales		1,785,799		311,828		360,535		211,270		346,430		123,390		2,362,480		352,201				34,801,424
2011
Residential Service		1,444,098		283,700		258,497		167,206		289,348		114,469		1,786,857		198,164				25,071,789
Commercial & Industrial		454,203		50,135		97,614		27,622		89,297		15,291		641,026		173,743				10,638,509
Other		16,035		5,450		37,219		44,620		—		2,324		76,330		2,996				1,271,720
Total MWh Sales		1,914,336		339,284		393,330		239,448		378,645		132,084		2,504,213		374,904				36,982,019

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 4
ANNUAL REVENUES BY CONSUMER CLASS OF EACH MEMBER

	Altamaha		Amicalola		Canoochee		Carroll			Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette			Diverse
2013
Residential Service	$	29,804,753	$	65,400,855	$	33,921,125	$	77,760,361		$	62,525,782	$	28,594,318	$	258,698,730	$	90,450,818	$	108,330,474		$	46,750,957
Commercial & Industrial		13,603,007		12,648,695		11,186,117		28,862,345			27,299,708		19,016,566		110,227,924		23,792,320		38,182,150			14,363,987
Other		638,547		35,784		685,823		850,465			620,534		377,739		25,535,827		8,835,705		1,770,901			1,333,699
Total Electric Sales	$	44,046,307	$	78,085,334	$	45,793,065	$	107,473,171		$	90,446,024	$	47,988,623	$	394,462,480	$	123,078,843	$	148,283,525		$	62,448,643
Other Operating Revenue		712,275		5,305,586		6,390,494		2,944,969			3,626,070		1,033,191		9,330,881		3,250,466		3,661,349			2,851,674
Total Operating Revenue	$	44,758,582	$	83,390,920	$	52,183,559	$	110,418,140		$	94,072,094	$	49,021,814	$	403,793,361	$	126,329,309	$	151,944,874		$	65,300,317
2012
Residential Service	$	30,153,536	$	63,497,469	$	33,392,964	$	74,814,023		$	64,833,102	$	28,110,543	$	274,437,494	$	87,667,013	$	103,218,835		$	47,051,750
Commercial & Industrial		13,449,332		12,441,706		10,519,567		28,621,529			26,872,431		17,855,229		112,764,721		23,688,205		36,444,880			14,682,334
Other		703,411		35,401		898,662		859,485			601,014		353,776		25,769,058		9,400,925		1,728,856			1,061,999
Total Electric Sales	$	44,306,279	$	75,974,576	$	44,811,193	$	104,295,037		$	92,306,547	$	46,319,548	$	412,971,273	$	120,756,143	$	141,392,571		$	62,796,083
Other Operating Revenue		1,009,744		3,336,709		5,825,063		(941,796	)		3,591,954		916,199		8,702,759		3,016,239		3,571,371			2,721,375
Total Operating Revenue	$	45,316,023	$	79,311,285	$	50,636,256	$	103,353,241		$	95,898,501	$	47,235,747	$	421,674,032	$	123,772,382	$	144,963,942		$	65,517,458
2011
Residential Service	$	31,164,824	$	68,195,346	$	31,972,126	$	75,787,510		$	72,853,778	$	29,348,893	$	290,974,700	$	86,616,944	$	111,934,901		$	47,863,584
Commercial & Industrial		12,283,039		12,529,666		9,494,138		28,184,851			28,788,895		16,504,322		115,068,083		21,365,886		37,589,977			13,988,783
Other		710,393		31,692		923,190		880,357			583,143		327,286		26,620,558		9,599,884		1,629,906			1,111,869
Total Electric Sales	$	44,158,256	$	80,756,704	$	42,389,454	$	104,852,718		$	102,225,816	$	46,180,501	$	432,663,341	$	117,582,714	$	151,154,784		$	62,964,236
Other Operating Revenue		2,671,211		1,540,454		7,073,693		4,436,940			3,694,144		975,940		8,975,818		8,181,172		3,880,144			2,477,859
Total Operating Revenue	$	46,829,467	$	82,297,158	$	49,463,147	$	109,289,658		$	105,919,960	$	47,156,441	$	441,639,159	$	125,763,886	$	155,034,928		$	65,442,095
	Middle Georgia		Mitchell		Ocmulgee		Oconee			Okefenoke		Planters		Rayle		Satilla		Sawnee			Slash Pine
2013
Residential Service	$	8,963,100	$	38,846,309	$	15,436,967	$	17,293,201		$	55,524,398	$	25,431,313	$	25,350,547	$	82,869,264	$	217,702,065		$	12,623,845
Commercial & Industrial		4,852,184		7,915,949		4,067,452		12,797,829			7,380,880	$	2,488,235		7,322,253		23,959,203		98,235,793			5,797,217
Other		1,815,905		7,001,559		830,461		376,731			1,919,937	$	2,014,716		—		4,153,859		5,095,807			510,970
Total Electric Sales	$	15,631,189	$	53,763,817	$	20,334,880	$	30,467,761		$	64,825,215	$	29,934,264	$	32,672,800	$	110,982,326	$	321,033,665		$	18,932,032
Other Operating Revenue		415,231		1,793,194		772,766		1,091,131			1,009,724	$	923,630		412,879		3,505,380		(4,889,653	)		893,582
Total Operating Revenue	$	16,046,420	$	55,557,011	$	21,107,646	$	31,558,892		$	65,834,939	$	30,857,894	$	33,085,679	$	114,487,706	$	316,144,012		$	19,825,614
2012
Residential Service	$	7,898,309	$	38,141,954	$	14,689,188	$	16,697,109		$	54,540,937	$	24,741,918	$	24,734,514	$	80,718,030	$	213,030,648		$	12,029,405
Commercial & Industrial		4,473,464		7,037,201		3,878,063		11,485,803			6,682,144		2,383,549		7,071,581		22,586,449		96,344,168			4,930,066
Other		3,210,884		8,151,582		1,322,009		512,862			2,029,442		2,455,956		—		4,215,050		4,975,832			773,942
Total Electric Sales	$	15,582,657	$	53,330,737	$	19,889,260	$	28,695,774		$	63,252,523	$	29,581,423	$	31,806,095	$	107,519,529	$	314,350,648		$	17,733,413
Other Operating Revenue		509,287		3,191,057		770,075		1,041,999			1,052,209		1,715,206		603,073		3,695,106		(7,497,733	)		1,321,673
Total Operating Revenue	$	16,091,944	$	56,521,794	$	20,659,335	$	29,737,773		$	64,304,732	$	31,296,629	$	32,409,168	$	111,214,635	$	306,852,915		$	19,055,086
2011
Residential Service	$	9,339,366	$	39,400,802	$	15,836,607	$	19,677,765		$	58,365,510	$	26,722,670	$	25,931,588	$	81,216,104	$	215,513,353		$	12,962,627
Commercial & Industrial		4,760,536		7,398,762		3,982,414		10,877,820			6,770,845		2,228,043		6,923,471		20,807,482		92,790,653			4,854,658
Other		3,859,287		10,098,061		1,408,210		545,245			2,062,825		2,684,162		—		4,494,674		4,931,294			859,438
Total Electric Sales	$	17,959,189	$	56,897,625	$	21,227,231	$	31,100,830		$	67,199,180	$	31,634,875	$	32,855,059	$	106,518,260	$	313,235,300		$	18,676,723
Other Operating Revenue		408,478		1,880,685		819,358		652,538			1,212,514		993,109		939,466		3,903,555		(89,952	)		800,662
Total Operating Revenue	$	18,367,667	$	58,778,310	$	22,046,589	$	31,753,368		$	68,411,694	$	32,627,984	$	33,794,525	$	110,421,815	$	313,145,348		$	19,477,385

Table 4 (continued)

	Excelsior			Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2013
Residential Service	$	28,750,569		$	121,853,462	$	30,080,001	$	162,458,971	$	48,162,693	$	44,456,594	$	18,085,978	$	276,609,062	$	52,304,820	$	16,512,952
Commercial & Industrial		6,525,654			50,021,692		3,936,392		94,395,898		10,574,549		20,402,399		2,884,699		159,868,292		10,830,768		4,275,105
Other		525,664			4,024,889		1,994,794		2,621,534		9,623		49,072		2,434,462		28,727,876		1,862,627		754,268
Total Electric Sales	$	35,801,887		$	175,900,043	$	36,011,187	$	259,476,403	$	58,746,865	$	64,908,065	$	23,405,139	$	465,205,230	$	64,998,215	$	21,542,325
Other Operating Revenue		2,364			4,451,630		1,642,702		8,162,620		3,085,674		3,988,569		357,008		2,490,757		3,149,837		920,511
Total Operating Revenue	$	35,804,251		$	180,351,673	$	37,653,889	$	267,639,023	$	61,832,539	$	68,896,634	$	23,762,147	$	467,695,987	$	68,148,052	$	22,462,836
2012
Residential Service	$	28,347,010		$	110,868,845	$	28,838,721	$	157,027,908	$	45,289,086	$	42,882,085	$	17,477,842	$	270,235,918	$	51,735,192	$	16,079,041
Commercial & Industrial		6,545,978			46,262,728		4,163,913		91,320,834		10,123,899		19,773,898		2,893,972		154,253,572		11,100,916		4,202,962
Other		630,530			4,678,165		1,936,732		2,593,122		9,520		59,563		3,038,862		28,403,405		2,061,494		857,235
Total Electric Sales	$	35,523,518		$	161,809,738	$	34,939,366	$	250,941,864	$	55,422,505	$	62,715,546	$	23,410,676	$	452,892,895	$	64,897,602	$	21,139,238
Other Operating Revenue		(267,151	)		11,402,163		1,512,138		8,307,468		2,687,429		3,745,395		544,893		16,626,505		4,045,083		487,687
Total Operating Revenue	$	35,256,367		$	173,211,901	$	36,451,504	$	259,249,332	$	58,109,934	$	66,460,941	$	23,955,569	$	469,519,400	$	68,942,685	$	21,626,925
2011
Residential Service	$	30,087,339		$	119,437,408	$	30,095,872	$	166,174,042	$	48,877,563	$	46,547,276	$	19,092,228	$	274,564,999	$	53,551,404	$	17,118,116
Commercial & Industrial		6,368,633			46,456,456		4,062,008		89,964,267		10,356,985		19,821,082		2,841,863		145,357,484		10,500,374		4,184,167
Other		736,168			4,723,950		2,216,521		2,569,375		8,645		56,959		3,494,775		28,065,896		1,950,094		1,004,237
Total Electric Sales	$	37,192,140		$	170,617,814	$	36,374,401	$	258,707,684	$	59,243,193	$	66,425,317	$	25,428,866	$	447,988,379	$	66,001,872	$	22,306,520
Other Operating Revenue		525,473			10,139,019		1,630,059		8,021,488		2,085,405		2,385,243		590,764		24,319,866		2,512,371		593,853
Total Operating Revenue	$	37,717,613		$	180,756,833	$	38,004,460	$	266,729,172	$	61,328,598	$	68,810,560	$	26,019,630	$	472,308,245	$	68,514,243	$	22,900,373
	Snapping Shoals			Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2013
Residential Service	$	127,407,451		$	32,197,847	$	28,208,639	$	19,248,045	$	31,836,851	$	11,822,703	$	167,619,042	$	20,945,664			$	2,540,840,526
Commercial & Industrial		34,989,781			4,885,468		11,189,614		3,726,638		8,461,557		1,643,866		59,922,574		12,460,082				974,994,842
Other		2,771,867			394,869		3,226,980		5,673,681		—		339,836		8,771,509		342,880				128,931,400
Total Electric Sales	$	165,169,099		$	37,478,184	$	42,625,233	$	28,648,364	$	40,298,408	$	13,806,405	$	236,313,125	$	33,748,626			$	3,644,766,767
Other Operating Revenue		(3,107,382	)		1,265,243		1,325,605		782,110		1,208,225		459,730		8,489,327		954,639				84,663,988
Total Operating Revenue	$	162,061,717		$	38,743,427	$	43,950,838	$	29,430,474	$	41,506,633	$	14,266,135	$	244,802,452	$	34,703,265			$	3,729,430,755
2012
Residential Service	$	124,750,117		$	30,823,330	$	27,751,707	$	18,064,891	$	30,682,539	$	11,788,486	$	165,872,706	$	20,948,772			$	2,493,862,937
Commercial & Industrial		35,502,311			4,829,285		11,362,016		3,374,815		8,291,731		1,678,168		58,791,639		12,554,563				951,239,622
Other		2,663,551			455,030		4,291,882		5,462,718		—		282,195		8,833,653		450,865				135,768,668
Total Electric Sales	$	162,915,979		$	36,107,645	$	43,405,605	$	26,902,424	$	38,974,270	$	13,748,849	$	233,497,998	$	33,954,200			$	3,580,871,227
Other Operating Revenue		7,082,554			1,165,239		883,902		784,087		1,201,986		464,243		4,436,461		907,344				104,168,995
Total Operating Revenue	$	169,998,533		$	37,272,884	$	44,289,507	$	27,686,511	$	40,176,256	$	14,213,092	$	237,934,459	$	34,861,544			$	3,685,040,222
2011
Residential Service	$	131,164,383		$	32,620,025	$	29,672,851	$	19,557,315	$	33,940,772	$	12,300,920	$	166,160,326	$	22,648,607			$	2,605,290,444
Commercial & Industrial		35,721,766			4,735,594		11,044,820		2,970,195		8,727,056		1,727,023		55,005,959		13,111,372				930,149,428
Other		2,620,688			467,519		4,170,235		5,331,786		—		286,204		8,754,798		295,852				140,115,176
Total Electric Sales	$	169,506,837		$	37,823,138	$	44,887,906	$	27,859,296	$	42,667,828	$	14,314,147	$	229,921,083	$	36,055,831			$	3,675,555,048
Other Operating Revenue		6,945,158			1,204,760		1,304,205		842,603		1,288,394		468,746		7,856,770		899,331				129,041,296
Total Operating Revenue	$	176,451,995		$	39,027,898	$	46,192,111	$	28,701,899	$	43,956,222	$	14,782,893	$	237,777,853	$	36,955,162			$	3,804,596,344

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 5
SUMMARY OF OPERATING RESULTS OF EACH MEMBER

	Altamaha			Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette		Diverse
2013
Operating Revenue & Patronage Capital	$	44,758,583		$	83,390,920	$	52,183,559	$	110,418,140	$	94,072,094	$	49,021,814	$	403,793,361	$	126,115,512	$	151,944,875	$	65,300,317
Depreciation and Amortization		3,019,923			5,985,879		3,801,659		8,216,766		5,711,738		2,732,936		28,195,430		7,264,761		8,924,175		5,516,958
Other Operating Expenses		40,304,162			73,838,406		42,239,092		94,184,308		82,195,869		43,356,588		349,218,454		110,229,326		131,289,421		55,414,618
Electric Operating Margin	$	1,434,498		$	3,566,635	$	6,142,808	$	8,017,066	$	6,164,487	$	2,932,290	$	26,379,476	$	8,835,996	$	11,731,279	$	4,368,741
Other Income		1,248,983			2,675,103		1,244,895		998,096		2,819,345		744,204		3,700,691		1,732,983		6,021,647		1,524,737
Gross Operating Margin	$	2,683,481		$	6,241,738	$	7,387,703	$	9,015,162	$	8,983,832	$	3,676,494	$	30,080,167	$	10,568,979	$	17,752,926	$	5,893,478
Interest on Long-term Debt		1,253,635			3,241,282		2,731,394		4,340,384		5,290,531		2,309,010		24,183,237		4,230,012		7,227,498		3,097,667
Other Deductions		20,533			—		5,774		—		—		49,519		802,598		701		107,723		46,901
Net Margins	$	1,409,313		$	3,000,456	$	4,650,535	$	4,674,778	$	3,693,301	$	1,317,965	$	5,094,332	$	6,124,396	$	10,417,705	$	2,748,910
2012
Operating Revenue & Patronage Capital	$	45,316,023		$	79,311,285	$	50,636,256	$	103,353,241	$	95,898,500	$	47,235,747	$	421,674,032	$	123,772,382	$	144,963,943	$	65,517,459
Depreciation and Amortization		2,944,854			5,860,969		3,756,937		8,055,198		5,490,253		2,676,057		25,312,768		6,925,600		8,727,750		6,368,683
Other Operating Expenses		39,843,498			70,704,411		40,777,627		87,728,705		82,224,069		41,850,235		350,056,520		107,668,045		123,720,991		54,570,503
Electric Operating Margin	$	2,527,671		$	2,745,905	$	6,101,692	$	7,569,338	$	8,184,178	$	2,709,455	$	46,304,744	$	9,178,737	$	12,515,202	$	4,578,273
Other Income		1,289,936			3,585,831		1,436,129		803,885		2,579,256		670,150		16,079,153		1,705,570		4,068,183		746,732
Gross Operating Margin	$	3,817,607		$	6,331,736	$	7,537,821	$	8,373,223	$	10,763,434	$	3,379,605	$	62,383,897	$	10,884,307	$	16,583,385	$	5,325,005
Interest on Long-term Debt		1,200,425			3,431,071		2,873,815		4,700,501		5,281,247		2,396,367		25,936,464		4,171,376		7,105,602		3,085,911
Other Deductions		5,407			1,703		12,146		—		—		3,039		2,106,096		701		119,038		26,914
Net Margins	$	2,611,775		$	2,898,962	$	4,651,860	$	3,672,722	$	5,482,187	$	980,199	$	34,341,337	$	6,712,230	$	9,358,745	$	2,212,180
2011
Operating Revenue & Patronage Capital	$	46,829,467		$	82,297,158	$	49,463,147	$	109,289,658	$	105,919,961	$	47,156,442	$	441,639,158	$	125,763,886	$	155,034,928	$	65,442,095
Depreciation and Amortization		2,768,858			5,749,081		3,570,620		8,026,458		5,366,594		2,580,106		24,135,949		6,565,372		8,564,757		6,330,152
Other Operating Expenses		42,091,186			72,497,339		41,263,877		95,200,554		93,092,496		42,003,405		383,067,325		109,746,125		133,536,300		54,507,288
Electric Operating Margin	$	1,969,423		$	4,050,738	$	4,628,650	$	6,062,646	$	7,460,871	$	2,572,931	$	34,435,884	$	9,452,389	$	12,933,871	$	4,604,655
Other Income		1,070,207			2,570,054		1,057,217		916,959		2,385,994		676,651		27,034,488		1,707,930		5,463,039		2,944,601
Gross Operating Margin	$	3,039,630		$	6,620,792	$	5,685,867	$	6,979,605	$	9,846,865	$	3,249,582	$	61,470,372	$	11,160,319	$	18,396,910	$	7,549,256
Interest on Long-term Debt		1,172,736			3,353,460		2,940,297		5,032,593		5,518,307		2,322,163		25,590,277		4,094,605		7,805,495		3,159,799
Other Deductions		6,349			7,017		623		—		—		3,039		2,218,252		—		128,079		—
Net Margins	$	1,860,545		$	3,260,315	$	2,744,947	$	1,947,012	$	4,328,558	$	924,380	$	33,661,843	$	7,065,714	$	10,463,336	$	4,389,457
	Middle Georgia			Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2013
Operating Revenue & Patronage Capital	$	16,046,420		$	55,557,012	$	21,107,646	$	31,558,892	$	65,834,939	$	30,857,893	$	33,085,679	$	114,487,707	$	316,144,012	$	19,825,614
Depreciation and Amortization		1,313,539			4,020,288		1,366,238		1,924,174		4,624,646		1,888,490		2,766,909		5,749,882		15,433,948		870,775
Other Operating Expenses		14,707,434			47,722,252		17,847,622		27,940,299		57,085,674		27,100,096		29,015,036		99,458,322		282,944,133		17,386,028
Electric Operating Margin	$	25,447		$	3,814,472	$	1,893,786	$	1,694,419	$	4,124,619	$	1,869,307	$	1,303,734	$	9,279,503	$	17,765,931	$	1,568,811
Other Income		391,540			1,192,873		324,706		734,334		1,367,349		1,310,879		1,114,984		2,489,679		6,739,744		347,831
Gross Operating Margin	$	416,987		$	5,007,345	$	2,218,492	$	2,428,753	$	5,491,968	$	3,180,186	$	2,418,718	$	11,769,182	$	24,505,675	$	1,916,642
Interest on Long-term Debt		962,750			2,037,707		1,083,351		1,814,671		3,532,976		1,456,345		2,326,363		3,802,798		10,139,456		725,067
Other Deductions		94,919			175,628		11,966		128,248		158,523		9,020		22,493		70,650		33,401		—
Net Margins	($	640,682	)	$	2,794,010	$	1,123,175	$	485,834	$	1,800,469	$	1,714,821	$	69,862	$	7,895,734	$	14,332,818	$	1,191,575
2012
Operating Revenue & Patronage Capital	$	16,091,943		$	56,521,794	$	20,659,335	$	29,737,773	$	64,304,734	$	31,296,629	$	32,409,168	$	111,214,635	$	306,852,915	$	19,055,086
Depreciation and Amortization		1,223,973			3,668,796		1,330,104		1,890,890		4,535,660		1,865,133		2,656,742		5,514,107		17,315,741		832,325
Other Operating Expenses		13,187,909			49,315,042		17,477,568		25,721,969		53,994,427		26,992,907		28,001,522		96,519,081		263,656,354		17,014,676
Electric Operating Margin	$	1,680,061		$	3,537,956	$	1,851,663	$	2,124,914	$	5,774,647	$	2,438,589	$	1,750,904	$	9,181,447	$	25,880,820	$	1,208,085
Other Income		453,222			1,284,713		517,356		674,552		835,661		1,251,581		832,103		2,365,971		5,794,176		343,883
Gross Operating Margin	$	2,133,283		$	4,822,669	$	2,369,019	$	2,799,466	$	6,610,308	$	3,690,170	$	2,583,007	$	11,547,418	$	31,674,996	$	1,551,968
Interest on Long-term Debt		942,917			1,944,417		1,110,578		1,858,067		3,661,808		1,462,251		2,248,664		3,591,011		10,202,461		709,792
Other Deductions		56,208			213,640		11,708		130,376		262,935		—		23,688		81,344		237,841		—
Net Margins	$	1,134,158		$	2,664,612	$	1,246,733	$	811,023	$	2,685,565	$	2,227,919	$	310,655	$	7,875,063	$	21,234,694	$	842,176
2011
Operating Revenue & Patronage Capital	$	18,367,667		$	58,805,311	$	22,046,589	$	31,753,368	$	68,411,694	$	32,627,984	$	33,794,525	$	110,421,815	$	313,145,348	$	19,477,385
Depreciation and Amortization		1,084,790			3,512,444		1,274,379		1,846,698		4,388,377		1,848,024		2,478,913		5,437,801		14,497,803		790,170
Other Operating Expenses		15,223,909			52,115,295		18,881,982		27,507,703		59,141,657		28,068,338		28,943,298		95,765,618		274,158,052		17,336,784
Electric Operating Margin	$	2,058,968		$	3,177,572	$	1,890,228	$	2,398,967	$	4,881,660	$	2,711,622	$	2,372,314	$	9,218,396	$	24,489,493	$	1,350,431
Other Income		418,397			1,125,871		354,180		698,333		1,337,069		1,084,908		562,368		1,619,096		200,507		381,019
Gross Operating Margin	$	2,477,365		$	4,303,443	$	2,244,408	$	3,097,300	$	6,218,729	$	3,796,530	$	2,934,682	$	10,837,492	$	24,690,000	$	1,731,450
Interest on Long-term Debt		912,762			1,943,142		1,062,379		1,909,095		3,808,371		1,343,322		2,084,048		3,348,393		12,272,546		756,219
Other Deductions		32,449			93,599		12,134		101,768		14,615		1,887.00		41,811		600,526		61,698		—
Net Margins	$	1,532,154		$	2,266,702	$	1,169,895	$	1,086,437	$	2,395,743	$	2,451,321	$	808,823	$	6,888,573	$	12,355,756	$	975,231

Table 5 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin			Jackson		Jefferson		Little Ocmulgee
2013
Operating Revenue & Patronage Capital	$	35,804,251	$	180,351,673	$	37,653,889	$	267,639,023	$	61,832,539	$	68,896,635	$	23,762,147		$	467,695,987	$	68,148,052	$	22,462,836
Depreciation and Amortization		2,264,564		11,678,679		2,715,473		14,675,182		4,707,020		4,656,108		2,769,821			29,009,972		4,437,749		1,498,069
Other Operating Expenses		31,723,307		155,219,390		33,409,487		232,366,615		53,693,477		59,792,924		20,701,719			411,657,706		57,778,042		19,208,528
Electric Operating Margin	$	1,816,380	$	13,453,604	$	1,528,929	$	20,597,226	$	3,432,042	$	4,447,603	$	290,607		$	27,028,309	$	5,932,261	$	1,756,239
Other Income		1,149,397		2,347,421		1,502,545		3,562,221		1,879,294		2,930,089		700,903			15,042,230		2,452,976		526,511
Gross Operating Margin	$	2,965,777	$	15,801,025	$	3,031,474	$	24,159,447	$	5,311,336	$	7,377,692	$	991,510		$	42,070,539	$	8,385,237	$	2,282,750
Interest on Long-term Debt		1,324,303		7,984,598		983,679		11,048,399		3,096,900		3,497,870		2,054,722			21,629,714		3,268,901		1,328,263
Other Deductions		—		4,894,690		257,056		—		25,452		8,691		68,371			2,011		13,620		—
Net Margins	$	1,641,474	$	2,921,737	$	1,790,739	$	13,111,048	$	2,188,984	$	3,871,131	($	1,131,583	)	$	20,438,814	$	5,102,716	$	954,487
2012
Operating Revenue & Patronage Capital	$	35,256,367	$	173,211,901	$	36,451,504	$	259,249,332	$	58,109,934	$	66,460,940	$	23,955,569		$	469,519,399	$	68,942,685	$	21,626,924
Depreciation and Amortization		2,186,036		10,968,219		2,626,483		14,211,927		4,678,626		4,599,687		2,612,374			28,497,927		4,223,210		1,433,605
Other Operating Expenses		31,323,110		150,629,589		32,341,052		229,188,680		50,137,872		57,916,403		19,366,927			411,818,548		59,856,746		18,781,623
Electric Operating Margin	$	1,747,221	$	11,614,093	$	1,483,969	$	15,848,725	$	3,293,436	$	3,944,850	$	1,976,268		$	29,202,924	$	4,862,729	$	1,411,696
Other Income		1,113,930		2,339,241		1,180,740		3,506,401		1,250,805		2,585,881		784,647			12,964,983		2,028,119		327,989
Gross Operating Margin	$	2,861,151	$	13,953,334	$	2,664,709	$	19,355,126	$	4,544,241	$	6,530,731	$	2,760,915		$	42,167,907	$	6,890,848	$	1,739,685
Interest on Long-term Debt		1,336,675		8,551,147		1,064,474		11,242,942		3,204,987		3,420,246		1,973,119			21,437,251		3,152,778		1,146,077
Other Deductions		—		175,524		218,900		—		22,496		11,327		55,956			2,662		15,126		—
Net Margins	$	1,524,476	$	5,226,663	$	1,381,335	$	8,112,184	$	1,316,758	$	3,099,158	$	731,840		$	20,727,994	$	3,722,944	$	593,608
2011
Operating Revenue & Patronage Capital	$	37,717,613	$	180,756,833	$	38,004,459	$	266,729,172	$	61,328,598	$	68,810,562	$	26,019,629		$	472,308,245	$	68,514,243	$	22,900,372
Depreciation and Amortization		2,092,519		10,820,814		2,531,331		13,476,564		4,723,185		4,549,294		2,445,219			27,342,181		4,214,496		1,335,306
Other Operating Expenses		33,845,382		155,206,169		33,902,192		238,237,481		52,780,192		59,212,210		21,114,374			408,962,875		60,630,119		19,700,932
Electric Operating Margin	$	1,779,712	$	14,729,850	$	1,570,936	$	15,015,127	$	3,825,221	$	5,049,058	$	2,460,036		$	36,003,189	$	3,669,628	$	1,864,134
Other Income		1,235,543		1,338,958		1,115,633		2,497,362		1,491,455		2,167,943		374,732			12,697,289		2,038,833		380,309
Gross Operating Margin	$	3,015,255	$	16,068,808	$	2,686,569	$	17,512,489	$	5,316,676	$	7,217,001	$	2,834,768		$	48,700,478	$	5,708,461	$	2,244,443
Interest on Long-term Debt		1,383,090		7,671,431		1,134,782		10,517,196		3,241,895		3,117,229		1,854,058			21,434,136		3,121,494		1,224,905
Other Deductions		—		250,841		240,841		—		2,466		5,346		65,264			3,497		23,080		—
Net Margins	$	1,632,165	$	8,146,536	$	1,310,946	$	6,995,293	$	2,072,315	$	4,094,426	$	915,446		$	27,262,845	$	2,563,887	$	1,019,538
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton			Washington				MEMBER TOTAL
2013
Operating Revenue & Patronage Capital	$	162,061,717	$	38,743,427	$	43,950,838	$	29,430,474	$	41,506,633	$	14,266,135	$	244,802,452		$	34,703,265			$	3,728,753,823
Depreciation and Amortization		8,865,479		2,227,756		2,825,880		1,854,022		3,394,035		819,119		12,983,657			2,109,710				232,821,409
Other Operating Expenses		147,867,698		34,016,810		37,881,548		26,082,037		34,382,097		12,412,946		221,271,148			30,278,424				3,263,220,269
Electric Operating Margin	$	5,328,540	$	2,498,861	$	3,243,410	$	1,494,415	$	3,730,501	$	1,034,070	$	10,547,647		$	2,315,131			$	232,712,144
Other Income		2,331,010		886,961		1,430,344		794,089		1,239,068		594,059		8,373,787			858,611				87,326,119
Gross Operating Margin	$	7,659,550	$	3,385,822	$	4,673,754	$	2,288,504	$	4,969,569	$	1,628,129	$	18,921,434		$	3,173,742			$	320,038,263
Interest on Long-term Debt		4,849,766		1,691,350		2,512,028		1,363,409		3,152,075		658,051		5,377,256			1,459,032				163,066,450
Other Deductions		305,733		—		27,769		58,219		47,829		15,353		211,990			953.00				7,676,334
Net Margins	$	2,504,051	$	1,694,472	$	2,133,957	$	866,876	$	1,769,665	$	954,725	$	13,332,188		$	1,713,757			$	149,295,479
2012
Operating Revenue & Patronage Capital	$	169,998,533	$	37,272,885	$	44,289,508	$	27,686,510	$	40,176,256	$	14,213,092	$	237,934,459		$	34,861,544			$	3,685,040,222
Depreciation and Amortization		9,201,706		2,112,881		2,727,109		1,708,586		3,287,495		800,689		12,694,994			2,114,891				227,638,985
Other Operating Expenses		155,396,358		31,582,149		37,583,128		24,690,029		32,663,389		12,210,457		215,719,982			30,140,051				3,192,372,151
Electric Operating Margin	$	5,400,469	$	3,577,855	$	3,979,271	$	1,287,895	$	4,225,372	$	1,201,946	$	9,519,483		$	2,606,602			$	265,029,085
Other Income		1,827,414		398,832		1,373,049		1,362,315		1,036,962		584,534		8,974,512			747,450				91,705,847
Gross Operating Margin	$	7,227,883	$	3,976,687	$	5,352,320	$	2,650,210	$	5,262,334	$	1,786,480	$	18,493,995		$	3,354,052			$	356,734,932
Interest on Long-term Debt		4,969,390		1,669,566		2,473,869		1,331,322		3,195,860		716,423		5,974,121			1,522,116				166,297,108
Other Deductions		172,406		—		9,303		103,337		100		15,414		222,387			3,156.00				4,320,878
Net Margins	$	2,086,087	$	2,307,121	$	2,869,148	$	1,215,551	$	2,066,374	$	1,054,643	$	12,297,487		$	1,828,780			$	186,116,946
2011
Operating Revenue & Patronage Capital	$	176,451,995	$	39,027,898	$	46,192,111	$	28,701,899	$	43,956,222	$	14,782,893	$	237,777,853		$	36,955,162			$	3,804,623,345
Depreciation and Amortization		9,216,535		2,053,391		2,607,220		1,592,907		3,217,198		781,386		12,535,109			2,133,121				218,485,122
Other Operating Expenses		161,074,451		33,890,932		38,841,164		25,466,495		35,798,148		13,271,540		213,788,107			32,504,113				3,322,375,407
Electric Operating Margin	$	6,161,009	$	3,083,575	$	4,743,727	$	1,642,497	$	4,940,876	$	729,967	$	11,454,637		$	2,317,928			$	263,762,816
Other Income		1,967,971		565,899		1,262,695		840,027		931,889		585,304		8,954,243			837,322				94,892,295
Gross Operating Margin	$	8,128,980	$	3,649,474	$	6,006,422	$	2,482,524	$	5,872,765	$	1,315,271	$	20,408,880		$	3,155,250			$	358,655,111
Interest on Long-term Debt		5,191,480		1,719,920		2,476,700		1,232,172		3,180,932		681,413		6,707,810			1,558,975				167,879,627
Other Deductions		102,483		—		21,855		138,405		7,841		16,018		322,340			—				4,524,123
Net Margins	$	2,835,017	$	1,929,554	$	3,507,867	$	1,111,947	$	2,683,992	$	617,840	$	13,378,730		$	1,596,275			$	186,251,361

FINANCIAL AND STATISTICAL INFORMATION FOR THE
38 MEMBERS OF OGLETHORPE POWER CORPORATION

Table 6
CONDENSED BALANCE SHEET INFORMATION OF EACH MEMBER
(as of December 31)

	Altamaha		Amicalola		Canoochee			Carroll		Central Georgia		Coastal		Cobb		Colquitt		Coweta- Fayette		Diverse
2013
ASSETS
Total Utility Plant (1)	$	98,931,967	$	188,143,252	$	127,661,371		$	233,381,027	$	200,478,589	$	87,457,551	$	814,308,356	$	236,738,439	$	304,122,401	$	184,889,850
Depreciation		29,978,721		63,203,982		358,798,871			66,590,386		48,886,572		17,641,042		227,698,981		66,629,919		91,990,201		62,929,271
Net Plant		68,953,246		124,939,270		(231,137,500	)		166,790,641		151,592,017		69,816,509		586,609,376		170,108,520		212,132,200		121,960,579
Other Assets		32,647,077		25,456,061		347,011,358			54,379,719		53,833,690		19,955,924		330,395,656		58,398,480		84,087,973		24,097,469
Total Assets	$	101,600,323	$	150,395,331	$	115,873,858		$	221,170,360	$	205,425,707	$	89,772,433	$	917,005,031	$	228,507,000	$	296,220,173	$	146,058,048
EQUITY & LIABILITIES
Equity	$	65,693,794	$	68,421,455	$	51,444,387		$	84,669,415	$	72,585,475	$	27,941,519	$	390,588,067	$	88,739,880	$	115,537,268	$	56,691,824
Long-term Debt		28,615,928		47,114,563		48,120,618			104,179,818		114,050,466		50,602,949		431,490,477		95,353,093		152,835,087		74,393,814
Other Liabilities		7,290,601		34,859,313		16,308,853			32,321,127		18,789,766		11,227,965		94,926,487		44,413,953		27,847,818		14,972,410
Total Equity and Liabilities	$	101,600,323	$	150,395,331	$	115,873,858		$	221,170,360	$	205,425,707	$	89,772,433	$	917,005,031	$	228,507,000	$	296,220,173	$	146,058,048
2012
ASSETS
Total Utility Plant (1)	$	95,419,373	$	184,288,223	$	123,968,375		$	227,559,342	$	194,482,301	$	83,132,960	$	808,583,433	$	227,579,712	$	295,934,368	$	145,652,180
Depreciation		29,561,613		58,152,027		33,529,536			60,559,056		44,666,100		16,064,513		217,611,446		63,712,883		85,582,382		56,930,043
Net Plant		65,857,760		126,136,196		90,438,839			167,000,286		149,816,201		67,068,447		590,971,987		163,866,829		210,351,986		88,722,137
Other Assets		32,165,728		25,368,516		21,518,866			55,335,786		47,441,170		20,250,071		327,421,581		56,286,138		77,977,314		23,401,196
Total Assets	$	98,023,488	$	151,504,712	$	111,957,705		$	222,336,072	$	197,257,371	$	87,318,518	$	918,393,568	$	220,152,967	$	288,329,300	$	112,123,333
EQUITY & LIABILITIES
Equity	$	64,228,071	$	67,251,940	$	46,854,205		$	81,867,328	$	71,062,071	$	26,622,384	$	384,577,503	$	92,219,988	$	107,626,137	$	52,398,137
Long-term Debt		26,870,299		48,897,713		49,042,048			109,964,660		109,291,102		54,857,210		418,439,859		93,961,653		155,173,199		47,895,878
Other Liabilities		6,925,118		35,355,059		16,061,452			30,504,084		16,904,198		5,838,924		115,376,206		33,971,326		25,529,964		11,829,318
Total Equity and Liabilities	$	98,023,488	$	151,504,712	$	111,957,705		$	222,336,072	$	197,257,371	$	87,318,518	$	918,393,568	$	220,152,967	$	288,329,300	$	112,123,333
2011
ASSETS
Total Utility Plant (1)	$	91,387,483	$	180,847,499	$	120,627,584		$	222,082,323	$	189,166,354	$	80,134,611	$	788,296,273	$	216,798,235	$	289,430,169	$	140,723,161
Depreciation		28,101,840		53,644,934		32,146,365			54,757,533		41,218,061		14,963,886		200,864,674		58,753,019		80,208,519		52,883,843
Net Plant		63,285,643		127,202,565		88,481,219			167,324,790		147,948,293		65,170,725		587,431,599		158,045,216		209,221,650		87,839,318
Other Assets		33,591,028		25,552,557		22,565,967			46,523,644		51,870,601		16,915,049		342,873,023		45,183,747		75,562,550		18,591,165
Total Assets	$	96,876,671	$	152,755,122	$	111,047,186		$	213,848,434	$	199,818,894	$	82,085,774	$	930,304,622	$	203,228,963	$	284,784,200	$	106,430,483
EQUITY & LIABILITIES
Equity	$	61,961,130	$	65,919,950	$	42,627,993		$	80,128,265	$	67,617,928	$	25,602,718	$	331,496,680	$	88,030,453	$	99,940,942	$	50,309,151
Long-term Debt		27,588,837		44,015,241		48,636,094			100,961,627		113,321,681		48,923,065		441,111,419		84,003,131		160,604,461		42,948,084
Other Liabilities		7,326,704		42,819,931		19,783,099			32,758,542		18,879,285		7,559,991		157,696,523		31,195,379		24,238,797		13,173,248
Total Equity and Liabilities	$	96,876,671	$	152,755,122	$	111,047,186		$	213,848,434	$	199,818,894	$	82,085,774	$	930,304,622	$	203,228,963	$	284,784,200	$	106,430,483
	Middle Georgia		Mitchell		Ocmulgee			Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2013
ASSETS
Total Utility Plant (1)	$	44,269,456	$	144,453,845	$	53,477,901		$	69,558,114	$	162,993,478	$	65,844,536	$	93,179,626	$	183,098,754	$	509,526,066	$	33,203,084
Depreciation		7,602,252		31,701,289		15,379,184			16,615,787		48,627,060		20,094,940		31,949,246		37,637,720		112,444,652		8,683,636
Net Plant		36,667,204		112,752,556		38,098,717			52,942,327		114,366,418		45,749,596		61,230,380		145,461,034		397,081,414		24,519,448
Other Assets		10,171,710		29,988,668		10,818,154			18,503,378		29,722,858		17,727,530		16,804,909		48,868,341		128,792,277		12,268,557
Total Assets	$	46,838,914	$	142,741,224	$	48,916,871		$	71,445,705	$	144,089,276	$	63,477,126	$	78,035,289	$	194,329,375	$	525,873,691	$	36,788,005
EQUITY & LIABILITIES
Equity	$	16,136,683	$	73,089,515	$	22,012,266		$	23,004,912	$	50,919,037	$	32,742,305	$	19,660,302	$	85,323,819	$	214,186,818	$	14,472,611
Long-term Debt		24,856,225		48,193,737		19,161,354			34,866,991		76,499,241		23,466,351		45,816,173		73,047,036		187,459,880		15,126,416
Other Liabilities		5,846,006		21,457,972		7,743,251			13,573,802		16,670,998		7,268,470		12,558,814		35,958,520		124,226,993		7,188,978
Total Equity and Liabilities	$	46,838,914	$	142,741,224	$	48,916,871		$	71,445,705	$	144,089,276	$	63,477,126	$	78,035,289	$	194,329,375	$	525,873,691	$	36,788,005
2012
ASSETS
Total Utility Plant (1)	$	41,905,537	$	138,851,820	$	52,197,340		$	68,129,472	$	160,532,416	$	63,115,323	$	89,409,000	$	176,719,681	$	488,644,582	$	32,400,881
Depreciation		7,341,798		29,661,219		14,351,941			15,668,402		45,348,802		20,123,434		29,978,817		34,480,020		105,969,720		8,173,319
Net Plant		34,563,739		109,190,601		37,845,399			52,461,070		115,183,614		42,991,889		59,430,183		142,239,661		382,674,862		24,227,562
Other Assets		8,108,082		26,850,426		9,620,562			16,399,557		26,112,592		17,370,034		16,866,510		44,010,240		98,960,537		9,526,307
Total Assets	$	42,671,821	$	136,041,027	$	47,465,961		$	68,860,627	$	141,296,206	$	60,361,923	$	76,296,693	$	186,249,901	$	481,635,399	$	33,753,869
EQUITY & LIABILITIES
Equity	$	16,788,737	$	70,792,374	$	20,624,452		$	22,714,858	$	49,993,855	$	31,603,620	$	19,728,207	$	83,307,487	$	205,630,729	$	13,285,068
Long-term Debt		20,939,908		40,657,259		19,074,731			33,220,056		74,735,642		21,593,635		46,687,808		71,518,701		170,092,205		13,622,772
Other Liabilities		4,943,176		24,591,394		7,766,778			12,925,713		16,566,709		7,164,668		9,880,678		31,423,713		105,912,465		6,846,029
Total Equity and Liabilities	$	42,671,821	$	136,041,027	$	47,465,961		$	68,860,627	$	141,296,206	$	60,361,923	$	76,296,693	$	186,249,901	$	481,635,399	$	33,753,869
2011
ASSETS
Total Utility Plant (1)	$	38,861,502	$	131,996,701	$	50,213,915		$	66,870,602	$	156,324,972	$	60,753,289	$	86,779,399	$	170,645,869	$	472,125,157	$	31,814,770
Depreciation		7,171,774		27,369,319		13,372,795			14,203,564		42,291,342		19,009,960		28,554,336		31,109,980		95,318,995		8,105,074
Net Plant		31,689,728		104,627,382		36,841,120			52,667,038		114,033,630		41,743,329		58,225,063		139,535,889		376,806,162		23,709,696
Other Assets		7,782,956		23,536,279		9,796,515			15,273,351		30,043,691		17,079,968		13,309,332		44,843,334		115,632,154		10,554,260
Total Assets	$	39,472,684	$	128,163,661	$	46,637,635		$	67,940,389	$	144,077,321	$	58,823,297	$	71,534,395	$	184,379,223	$	492,438,316	$	34,263,956
EQUITY & LIABILITIES
Equity	$	15,668,801	$	68,291,476	$	20,013,487		$	21,783,357	$	48,135,475	$	29,958,473	$	19,973,852	$	77,717,353	$	189,376,420	$	13,182,245
Long-term Debt		20,348,748		36,148,210		19,421,082			33,613,605		80,065,035		21,377,459		40,400,610		75,536,910		213,393,807		14,024,003
Other Liabilities		3,455,135		23,723,975		7,203,066			12,543,427		15,876,811		7,487,365		11,159,933		31,124,960		89,668,089		7,057,708
Total Equity and Liabilities	$	39,472,684	$	128,163,661	$	46,637,635		$	67,940,389	$	144,077,321	$	58,823,297	$	71,534,395	$	184,379,223	$	492,438,316	$	34,263,956

Footnotes:

(1)

Including construction work in progress.

Table 6 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Ocmulgee
2013
ASSETS
Total Utility Plant (1)	$	75,334,003	$	365,022,728	$	94,021,794	$	444,050,297	$	142,262,634	$	160,747,740	$	81,971,677	$	879,191,715	$	149,245,937	$	56,313,397
Depreciation		19,480,087		105,922,473		21,371,807		100,606,905		57,048,759		49,079,986		24,754,555		253,561,461		39,432,689		12,338,632
Net Plant		55,853,916		259,100,255		72,649,987		343,443,392		85,213,875		111,667,754		57,217,122		625,630,254		109,813,248		43,974,765
Other Assets		22,416,731		89,432,408		23,465,704		138,307,780		40,223,345		48,307,934		12,796,886		246,883,921		46,193,011		9,069,493
Total Assets	$	78,270,647	$	348,532,663	$	96,115,691	$	481,751,172	$	125,437,220	$	159,975,688	$	70,014,008	$	872,514,175	$	156,006,259	$	53,044,258
EQUITY & LIABILITIES
Equity	$	45,787,203	$	115,787,053	$	43,472,741	$	201,296,708	$	40,017,856	$	67,971,665	$	20,970,941	$	345,426,456	$	65,643,304	$	17,541,985
Long-term Debt		23,763,045		173,013,397		32,281,855		227,022,869		64,796,917		66,023,607		44,302,545		410,337,289		62,877,309		26,830,227
Other Liabilities		8,720,399		59,732,213		20,361,095		53,431,595		20,622,447		25,980,416		4,740,522		116,750,430		27,485,646		8,672,046
Total Equity and Liabilities	$	78,270,647	$	348,532,663	$	96,115,691	$	481,751,172	$	125,437,220	$	159,975,688	$	70,014,008	$	872,514,175	$	156,006,259	$	53,044,258
2012
ASSETS
Total Utility Plant (1)	$	72,872,216	$	349,173,168	$	89,870,541	$	429,328,185	$	138,177,522	$	157,243,830	$	79,182,415	$	845,749,495	$	142,927,700	$	54,714,531
Depreciation		54,680,569		98,915,404		19,538,412		90,867,677		52,603,579		45,744,298		23,472,637		236,657,700		37,031,193		12,677,406
Net Plant		18,191,647		250,257,764		70,332,129		338,460,508		85,573,943		111,499,532		55,709,778		609,091,795		105,896,507		42,037,125
Other Assets		56,694,148		81,649,268		21,923,384		118,098,474		38,192,166		43,967,329		11,661,636		221,108,564		49,216,616		11,391,907
Total Assets	$	74,885,795	$	331,907,032	$	92,255,513	$	456,558,982	$	123,766,109	$	155,466,861	$	67,371,414	$	830,200,359	$	155,113,123	$	53,429,032
EQUITY & LIABILITIES
Equity	$	44,145,811	$	114,890,140	$	41,832,834	$	192,048,825	$	38,670,250	$	66,776,323	$	22,409,843	$	330,465,791	$	62,208,390	$	17,045,668
Long-term Debt		22,520,191		164,162,298		33,709,793		215,711,180		67,391,603		61,616,308		40,458,367		394,804,270		63,920,706		29,262,225
Other Liabilities		8,219,793		52,854,594		16,712,886		48,798,977		17,704,256		27,074,230		4,503,204		104,930,298		28,984,027		7,121,139
Total Equity and Liabilities	$	74,885,795	$	331,907,032	$	92,255,513	$	456,558,982	$	123,766,109	$	155,466,861	$	67,371,414	$	830,200,359	$	155,113,123	$	53,429,032
2011
ASSETS
Total Utility Plant (1)	$	70,171,870	$	330,871,523	$	86,416,730	$	424,695,461	$	135,493,590	$	153,009,071	$	75,542,662	$	817,055,628	$	136,886,943	$	52,280,541
Depreciation		17,168,438		94,967,751		18,511,263		86,931,131		48,353,932		42,736,396		22,459,431		219,586,599		34,169,174		11,806,685
Net Plant		53,003,432		235,903,772		67,905,467		337,764,330		87,139,658		110,272,675		53,083,231		597,469,029		102,717,769		40,473,856
Other Assets		19,962,852		67,504,096		20,087,742		126,599,489		27,285,845		42,922,067		11,535,143		235,337,608		39,388,431		10,438,478
Total Assets	$	72,966,284	$	303,407,868	$	87,993,209	$	464,363,819	$	114,425,503	$	153,194,742	$	64,618,374	$	832,806,637	$	142,106,200	$	50,912,334
EQUITY & LIABILITIES
Equity	$	42,619,299	$	111,757,803	$	40,663,505	$	186,817,327	$	38,160,794	$	63,791,862	$	21,699,448	$	314,661,196	$	59,391,939	$	16,559,069
Long-term Debt		23,457,577		139,519,824		31,852,397		224,007,827		58,980,230		61,246,530		38,819,017		406,735,186		54,980,414		27,469,135
Other Liabilities		6,889,408		52,130,241		15,477,307		53,538,665		17,284,479		28,156,350		4,099,909		111,410,255		27,733,847		6,884,130
Total Equity and Liabilities	$	72,966,284	$	303,407,868	$	87,993,209	$	464,363,819	$	114,425,503	$	153,194,742	$	64,618,374	$	832,806,637	$	142,106,200	$	50,912,334
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2013
ASSETS
Total Utility Plant (1)	$	257,769,338	$	73,035,490	$	105,903,137	$	64,902,416	$	109,520,507	$	26,994,902	$	394,986,696	$	77,521,392			$	7,394,513,463
Depreciation		87,233,634		20,748,888		24,578,452		19,327,653		21,418,721		9,130,511		135,936,567		26,264,110				2,393,319,602
Net Plant		170,535,704		52,286,602		81,324,685		45,574,763		88,101,786		17,864,391		259,050,129		51,257,282				5,001,193,862
Other Assets		53,505,705		18,111,364		27,925,740		20,832,944		19,687,322		14,093,681		187,080,191		22,553,825				2,394,354,634
Total Assets	$	224,041,409	$	70,397,966	$	109,250,425	$	66,407,707	$	107,789,108	$	31,958,072	$	446,130,320	$	73,811,107			$	7,395,548,495
EQUITY & LIABILITIES
Equity	$	91,606,042	$	23,526,900	$	51,121,270	$	25,537,458	$	37,052,456	$	16,263,622	$	196,475,904	$	38,340,990			$	3,017,238,840
Long-term Debt		78,430,927		34,981,923		47,510,527		34,109,010		63,822,510		11,170,501		142,467,865		28,660,891				3,267,653,431
Other Liabilities		54,004,440		11,889,143		10,618,628		6,761,239		6,914,142		4,523,949		107,186,551		6,809,226				1,110,656,224
Total Equity and Liabilities	$	224,041,409	$	70,397,966	$	109,250,425	$	66,407,707	$	107,789,108	$	31,958,072	$	446,130,320	$	73,811,107			$	7,395,548,495
2012
ASSETS
Total Utility Plant (1)	$	252,954,380	$	70,680,733	$	101,825,434	$	60,915,043	$	104,674,372	$	26,647,872	$	387,796,776	$	75,056,886			$	7,138,297,418
Depreciation		81,697,961		19,894,340		23,247,624		18,244,083		20,139,717		8,384,178		126,798,767		25,536,758				1,973,599,374
Net Plant		171,256,419		50,786,393		78,577,810		42,670,960		84,534,655		18,263,694		260,998,009		49,520,128				5,164,698,044
Other Assets		42,677,700		17,000,322		25,410,732		19,785,283		18,876,457		13,062,947		184,531,282		23,376,367				1,959,615,795
Total Assets	$	213,934,119	$	67,786,715	$	103,988,542	$	62,456,243	$	103,411,112	$	31,326,641	$	445,529,291	$	72,896,495			$	7,124,313,839
EQUITY & LIABILITIES
Equity	$	92,100,673	$	24,660,270	$	49,546,686	$	24,949,091	$	35,755,619	$	16,007,343	$	180,323,103	$	37,379,638			$	2,920,393,449
Long-term Debt		76,301,014		32,303,427		44,025,445		31,584,591		60,703,346		11,298,286		160,660,850		29,510,547				3,166,480,785
Other Liabilities		45,532,432		10,823,018		10,416,411		5,922,561		6,952,147		4,021,012		104,545,338		6,006,310				1,037,439,605
Total Equity and Liabilities	$	213,934,119	$	67,786,715	$	103,988,542	$	62,456,243	$	103,411,112	$	31,326,641	$	445,529,291	$	72,896,495			$	7,124,313,839
2011
ASSETS
Total Utility Plant (1)	$	246,382,727	$	66,715,815	$	97,989,465	$	57,000,073	$	101,608,154	$	25,649,011	$	378,344,733	$	72,370,842			$	6,914,364,707
Depreciation		75,319,690		18,611,145		21,422,714		17,524,118		18,621,016		7,915,323		117,225,918		24,297,642				1,801,678,179
Net Plant		171,063,037		48,104,670		76,566,751		39,475,955		82,987,138		17,733,688		261,118,815		48,073,200				5,112,686,528
Other Assets		51,429,374		18,466,339		25,191,604		17,310,567		21,280,374		12,848,499		184,725,306		22,566,095				1,921,961,080
Total Assets	$	222,492,411	$	66,571,009	$	101,758,355	$	56,786,522	$	104,267,512	$	30,582,187	$	445,844,121	$	70,639,295			$	7,034,647,608
EQUITY & LIABILITIES
Equity	$	92,762,740	$	24,198,448	$	46,858,638	$	24,030,831	$	34,141,918	$	15,250,454	$	182,583,110	$	36,304,900			$	2,769,989,430
Long-term Debt		80,135,741		33,667,627		44,728,666		26,085,656		62,935,164		11,649,417		178,084,282		28,167,184				3,198,964,983
Other Liabilities		49,593,930		8,704,934		10,171,051		6,670,035		7,190,430		3,682,316		85,176,729		6,167,211				1,065,693,195
Total Equity and Liabilities	$	222,492,411	$	66,571,009	$	101,758,355	$	56,786,522	$	104,267,512	$	30,582,187	$	445,844,121	$	70,639,295			$	7,034,647,608

Footnotes:

(1)

Including construction work in progress.

QuickLinks

Exhibit 99.1

FINANCIAL AND STATISTICAL INFORMATION FOR 38 MEMBERS OF OGLETHORPE POWER CORPORATION

XML

Debt (Details) (USD $)	0 Months Ended
	Feb. 20, 2014	Apr. 30, 2014	Mar. 31, 2014
Facility
Debt
Capitalized interest	$ 335,471,604
Principal amount	725,000,000	10,674,000	9,608,000
Fixed interest rate (as a percent)	3.867%
Basis spread (as a percent)	0.375%
Issuance costs	51,000,000
Facility | Minimum
Debt
Term of each advance	3 months
Facility | Maximum
Debt
Aggregate borrowings expressed as a percentage of Eligible Project Costs	70.00%
Aggregate borrowings	3,057,069,461
Interest accrued and payable prior to February 20, 2020, is reflected as additional borrowings under the Facility			335,471,604
Term loan
Debt
Repayment of outstanding debt	260,000,000
Commercial paper
Debt
Repayment of outstanding debt	$ 465,000,000

XML

Investments in Debt and Equity Securities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Investments in Debt and Equity Securities
Available-for-sale securities, gross unrealized losses that were in effect for less than one year (as a percent)	86.00%
Available-for-sale securities
Cost	$ 364,846	$ 359,797
Gross Unrealized Gains	74,794	75,745
Gross Unrealized Losses	(8,950)	(10,123)
Fair Value	430,690	425,419
Equity
Available-for-sale securities
Cost	187,463	182,755
Gross Unrealized Gains	66,283	68,424
Gross Unrealized Losses	(1,190)	(1,053)
Fair Value	252,556	250,126
Debt
Available-for-sale securities
Cost	165,776	164,941
Gross Unrealized Gains	8,509	7,319
Gross Unrealized Losses	(7,759)	(9,070)
Fair Value	166,526	163,190
Other
Available-for-sale securities
Cost	11,607	12,101
Gross Unrealized Gains	2	2
Gross Unrealized Losses	(1)
Fair Value	$ 11,608	$ 12,103

XML

Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair value measurement
Long-term investments	$ 82,593	$ 81,720
Interest rate options
Fair value measurement
Derivative assets	31,463	63,471
Collateral received from counterparties against which fair value of derivative instruments offset	10,730	34,970
Natural gas swaps
Fair value measurement
Derivative assets	1,960	1,011
Recurring basis | Total Fair Value | Interest rate options
Fair value measurement
Derivative assets	31,463	63,471
Recurring basis | Total Fair Value | Natural gas swaps
Fair value measurement
Derivative assets	1,960	1,011
Recurring basis | Total Fair Value | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	145,202	143,929
Recurring basis | Total Fair Value | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	73,159	72,466
Long-term investments	11,259	11,148
Recurring basis | Total Fair Value | Corporate bonds
Fair value measurement
Nuclear decommissioning trust funds	39,492	39,863
Long-term investments	6,154	6,487
Recurring basis | Total Fair Value | US Treasury and government agency securities
Fair value measurement
Nuclear decommissioning trust funds	49,026	44,846
Long-term investments	9,883	8,563
Recurring basis | Total Fair Value | Agency mortgage and asset backed securities
Fair value measurement
Nuclear decommissioning trust funds	29,654	30,133
Long-term investments	3,267	3,679
Recurring basis | Total Fair Value | Municipal Bonds
Fair value measurement
Nuclear decommissioning trust funds		641
Recurring basis | Total Fair Value | Other
Fair value measurement
Nuclear decommissioning trust funds	11,564	11,820
Long-term investments	44	284
Recurring basis | Total Fair Value | Mutual funds
Fair value measurement
Long-term investments	51,986	51,559
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	145,202	143,929
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury and government agency securities
Fair value measurement
Nuclear decommissioning trust funds	49,026	44,846
Long-term investments	9,883	8,563
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value measurement
Nuclear decommissioning trust funds	11,564	11,820
Long-term investments	44	284
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mutual funds
Fair value measurement
Long-term investments	51,986	51,559
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value measurement
Derivative assets	1,960	1,011
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	73,159	72,466
Long-term investments	11,259	11,148
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds
Fair value measurement
Nuclear decommissioning trust funds	39,492	39,863
Long-term investments	6,154	6,487
Recurring basis | Significant Other Observable Inputs (Level 2) | Agency mortgage and asset backed securities
Fair value measurement
Nuclear decommissioning trust funds	29,654	30,133
Long-term investments	3,267	3,679
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal Bonds
Fair value measurement
Nuclear decommissioning trust funds		641
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate options
Fair value measurement
Derivative assets	$ 31,463	$ 63,471

XML

Restricted Short-term Investments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Restricted Short-term Investments
Deposit with Rural Utilities Service in Cushion of Credit Account	$ 289,469	$ 272,686
Guaranteed interest rate on deposit with Rural Utilities Service (as a percent)	5.00%	5.00%

XML

Derivative Instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments

Derivative 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. We do not apply hedge accounting for these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on natural gas swaps are reflected as a regulatory asset or liability. To hedge the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, we have entered into interest rate options. Hedge accounting is not applied to our interest rate options. Consistent with our rate-making, unrealized gains or losses from the interest rate options are recorded as a regulatory asset. We do not hold or enter into derivative transactions for trading or speculative purposes.

• 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 March 31, 2014, 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 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.

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

  At March 31, 2014 and December 31, 2013, the estimated fair values of our natural gas contracts were a net asset of approximately $1,960,000 and $1,011,000, respectively.

  As of March 31, 2014 and December 31, 2013, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2014 due to our credit rating being downgraded below investment grade, we would not have been required to post letters of credit with our counterparties.

  The following table reflects the volume activity of our natural gas derivatives as of March 31, 2014 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2014	3.9
2015	1.1
Total	5.0

• Interest rate options.     We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 to hedge the interest rates on approximately $2.2 billion of the expected debt that will be used to finance two additional nuclear units at Plant Vogtle. As of March 31, 2014, our outstanding swaptions hedged approximately $1.3 billion of the expected debt for the new Vogtle units.

  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 85 basis points above the corresponding LIBOR swap rates that were in effect as of March 31, 2014 and the weighted average fixed rate is 4.12%. Swaptions having notional amounts totaling $138,317,000 expired without value during the three months ended March 31, 2014. 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 value. At March 31, 2014 and December 31, 2013, the fair value of these swaptions was approximately $31,463,000 and $63,471,000, 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 March 31, 2014 and December 31, 2013, we held $10,730,000 and $34,970,000 of funds posted as collateral 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 $20,733,000 and $28,501,000 at March 31, 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 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 March 31, 2014.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2014	$	425,107
2015		470,625
2016		310,533
2017		80,169
Total	$	1,286,434

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

	Balance Sheet Location		Fair Value
			2014		2013
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options(1)	Other deferred charges	$	31,463	$	63,471
Liabilities:
Natural gas swaps	Other current liabilities	$	1,960	$	1,011

⁽¹⁾

Excludes liability associated with cash collateral of $10,730,000 and $34,970,000 as of March 31, 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.

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

	Statement of Revenues and		Three months ended March 31,
	Expenses Location		2014		2013
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	279	$	117
Natural Gas Swaps	Fuel		—		(534	)
		$	279	$	(417	)

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

	Balance Sheet Location		2014			2013
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory liability	$	1,960		$	1,011
Interest rate options	Regulatory asset		(41,720	)		(15,003	)
		$	(39,760	)	$	(13,992	)

• 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
		(dollars in thousands)
March 31, 2014
Assets:
Natural gas swaps	$	2,054	$	(94	)	$	—		$	1,960
Interest rate options	$	31,463	$	—		$	(10,730	)	$	20,733
December 31, 2013
Assets:
Natural gas swaps	$	1,069	$	(58	)	$	—		$	1,011
Interest rate options	$	63,471	$	—		$	(34,970	)	$	28,501

XML

Derivative instruments (Details 2) (LIBOR swaptions, USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2011 item	Dec. 31, 2013
Derivative instruments and hedging activities
Purchased amount of derivative instrument		$ 100,000,000
Variable rate basis	LIBOR
Number of nuclear units expected to be financed		2
Cash settlement value, if swap rates are at or below the specified fixed rate on the expiration date	0
Weighted average fixed rate (as a percent)	4.12%
Notional amount of derivatives, expired without value	138,317,000
Additional premium payment obligations on interest rate option transactions	0
Fair value of assets	31,463,000		63,471,000
Funds posted as collateral by the counterparties	10,730,000		34,970,000
Carrying amount of derivative assets	20,733,000		28,501,000
Notional Dollar Amount	1,286,434,000
2014
Derivative instruments and hedging activities
Notional Dollar Amount	425,107,000
2015
Derivative instruments and hedging activities
Notional Dollar Amount	470,625,000
2016
Derivative instruments and hedging activities
Notional Dollar Amount	310,533,000
2017
Derivative instruments and hedging activities
Notional Dollar Amount	80,169,000
Minimum
Derivative instruments and hedging activities
Collateral thresholds range	0
Maximum
Derivative instruments and hedging activities
Collateral thresholds range	10,000,000
Average
Derivative instruments and hedging activities
Fixed interest rates above current LIBOR swap rates (as a percent)	0.85%
Department of Energy-guaranteed loan
Derivative instruments and hedging activities
Hedged amount of expected debt	$ 1,300,000,000	$ 2,200,000,000

XML

Derivative instruments (Details) (Natural Gas Swaps, USD $) In Thousands, unless otherwise specified	Mar. 31, 2014 MMBTU	Dec. 31, 2013
Gas hedges
Derivative assets	$ 1,960	$ 1,011
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	5,000,000
2014
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	3,900,000
2015
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	1,100,000

XML

Derivative instruments (Details 3) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Interest rate options
Assets:
Fair value of assets	$ 31,463,000	$ 63,471,000
Natural gas swaps
Assets:
Fair value of assets	1,960,000	1,011,000
Not designated as hedges | Interest rate options
Assets:
Fair value of assets	31,463,000	63,471,000
Liabilities:
Liability associated with cash collateral, which is recorded as an offset to the fair value of derivatives	10,730,000	34,970,000
Not designated as hedges | Natural gas swaps
Liabilities:
Fair Value of liabilities	$ 1,960,000	$ 1,011,000

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Derivative instruments (Details 4) (Not designated as hedges, USD $) In Thousands, unless otherwise specified					3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Natural gas swaps Regulatory liability	Dec. 31, 2013 Natural gas swaps Regulatory liability	Mar. 31, 2014 Natural gas swaps Fuel	Mar. 31, 2013 Natural gas swaps Fuel	Mar. 31, 2014 Interest rate options Regulatory asset	Dec. 31, 2013 Interest rate options Regulatory asset
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Gains					$ 279	$ 117
Losses						(534)
Total gains (losses) on derivatives					279	(417)
Unrealized losses on derivatives							(41,720)	(15,003)
Unrealized gains on derivatives			1,960	1,011
Unrealized gains and (losses) on derivatives	$ (39,760)	$ (13,992)

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Fair Value

3 Months Ended

Mar. 31, 2014

Fair Value

Fair Value

(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.

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

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

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

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

  The tables below detail assets and liabilities measured at fair value on a recurring basis at March 31, 2014 and December 31, 2013.

			Fair Value Measurements at Reporting Date Using
		March 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	$	145,202	$	145,202	$	—	$	—
International equity trust		73,159		—		73,159		—
Corporate bonds		39,492		—		39,492		—
US Treasury and government agency securities		49,026		49,026		—		—
Agency mortgage and asset backed securities		29,654		—		29,654		—
Other		11,564		11,564		—		—
Long-term investments:
Corporate bonds		6,154		—		6,154		—
US Treasury and government agency securities		9,883		9,883		—		—
Agency mortgage and asset backed securities		3,267		—		3,267		—
International equity trust		11,259		—		11,259		—
Mutual funds		51,986		51,986		—		—
Other		44		44		—		—
Interest rate options		31,463		—		—		31,463	(1)
Natural gas swaps		1,960		—		1,960		—

			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 $10,730,000 and $34,970,000 of collateral received from the counterparties at March 31, 2014 and December 31, 2013, respectively.

• The Level 2 investments above in international equity trust, 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 following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three months ended March 31, 2014 and 2013.

		Three Months Ended March 31, 2014
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2013	$	63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(32,008	)
Balance at March 31, 2014	$	31,463

		Three Months Ended March 31, 2013
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2012	$	25,783
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		756
Balance at March 31, 2013	$	26,539

• 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.

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

		2014				2013
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	6,933,851	$	7,534,625	$	6,954,293	$	7,317,476

• 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, 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 March 31, 2014 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 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.

  For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.

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Derivative instruments (Details 5) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Natural gas swaps
Assets:
Gross Amounts of Recognized Assets (Liabilities)	$ 2,054	$ 1,069
Gross Amounts offset on the Balance Sheet	(94)	(58)
Net Amounts of Assets Presented on the Balance Sheet	1,960	1,011
Interest rate options
Assets:
Gross Amounts of Recognized Assets (Liabilities)	31,463	63,471
Cash Collateral	(10,730)	(34,970)
Net Amounts of Assets Presented on the Balance Sheet	$ 20,733	$ 28,501

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Subsequent Events (Details) (Subsequent event, Precedent agreement, Transcontinental Gas Pipeline Company, LLC, USD $)	0 Months Ended
	Apr. 11, 2014
Subsequent event | Precedent agreement | Transcontinental Gas Pipeline Company, LLC
Subsequent Events
Base term of an agreement	25 years
Agreement fixed charge for the base term	$ 37,700,000

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Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Electric plant:
In service	$ 8,078,128	$ 8,050,103
Less: Accumulated provision for depreciation	(3,648,091)	(3,615,375)
Total in service	4,430,037	4,434,728
Nuclear fuel, at amortized cost	347,044	341,012
Construction work in progress	2,290,024	2,212,224
Total electric plant	7,067,105	6,987,964
Investments and funds:
Nuclear decommissioning trust fund	348,097	343,698
Investment in associated companies	66,393	66,437
Long-term investments	82,593	81,720
Restricted cash	10,736	34,975
Other	16,357	16,098
Total investments and funds	524,176	542,928
Current assets:
Cash and cash equivalents	218,493	408,193
Restricted short-term investments	289,469	272,686
Receivables	130,884	128,992
Inventories, at average cost	261,341	286,168
Prepayments and other current assets	15,950	16,894
Total current assets	916,137	1,112,933
Deferred charges:
Deferred debt expense, being amortized	97,831	57,175
Regulatory assets	385,769	331,108
Other	55,976	63,104
Total deferred charges	539,576	451,387
Total assets	9,046,994	9,095,212
Capitalization:
Patronage capital and membership fees	733,712	714,489
Accumulated other comprehensive deficit	(153)	(549)
Total patronage capital and membership fees and accumulated other comprehensive margin	733,559	713,940
Long-term debt	6,795,655	6,817,518
Obligations under capital leases	118,871	121,731
Other	15,639	15,379
Total capitalization	7,663,724	7,668,568
Current liabilities:
Long-term debt and capital leases due within one year	153,772	152,153
Short-term borrowings	269,687	279,407
Accounts payable	72,865	101,529
Accrued interest	49,389	58,193
Members power bill prepayments, current	92,460	82,405
Other current liabilities	27,624	42,253
Total current liabilities	665,797	715,940
Deferred credits and other liabilities:
Gain on sale of plant, being amortized	21,787	22,157
Asset retirement obligations	413,977	408,050
Member power bill prepayments, non-current	34,363	32,313
Power sale agreement, being amortized	22,747	26,107
Regulatory liabilities	160,437	158,789
Other	64,162	63,288
Total deferred credits and other liabilities	717,473	710,704
Total equity and liabilities	$ 9,046,994	$ 9,095,212

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Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash flows from operating activities:
Net margin	$ 19,223	$ 22,024
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	74,880	68,384
Accretion cost	6,018	5,630
Amortization of deferred gains	(447)	(447)
Allowance for equity funds used during construction	(389)	(752)
Deferred outage costs	(25,845)	(23,911)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin	(9,715)	(11,890)
Gain on sale of investments	(3,996)	(3,529)
Regulatory deferral of costs associated with nuclear decommissioning	(84)	(97)
Other	1,384	(2,119)
Change in operating assets and liabilities:
Receivables	(1,799)	6,124
Inventories	24,827	10,181
Prepayments and other current assets	1,892	1,794
Accounts payable	(33,330)	(70,675)
Accrued interest	(8,804)	14,451
Accrued taxes	(13,144)	4,634
Other current liabilities	(2,075)	(2,892)
Member power bill prepayments	12,105	84,903
Total adjustments	21,478	79,789
Net cash provided by operating activities	40,701	101,813
Cash flows from investing activities:
Property additions	(134,354)	(180,365)
Activity in decommissioning trust fund - Purchases	(101,894)	(106,460)
Activity in decommissioning trust fund - Proceeds	100,648	105,148
Decrease (increase) in restricted cash	24,239	(4,410)
Increase in restricted short-term investments	(16,783)	(139,127)
Activity in other long-term investments - Purchases	(12,220)	(6,394)
Activity in other long-term investments - Proceeds	12,413	6,633
Activity on interest rate options - Collateral returned	(46,940)	(17,440)
Activity on interest rate options - Collateral received	22,700	21,850
Other	(401)	2,076
Net cash used in investing activities	(152,592)	(318,489)
Cash flows from financing activities:
Long-term debt proceeds	734,608	20,734
Long-term debt payments	(295,740)	(215,663)
Decrease (Increase) in short-term borrowings, net	(474,720)	351,944
Other	(41,957)	610
Net cash (used in) provided by financing activities	(77,809)	157,625
Net decrease in cash and cash equivalents	(189,700)	(59,051)
Cash and cash equivalents at beginning of period	408,193	298,565
Cash and cash equivalents at end of period	218,493	239,514
Cash paid for -
Interest (net of amounts capitalized)	65,816	35,312
Supplemental disclosure of non-cash investing and financing activities:
Change in plant expenditures included in accounts payable	$ 6,463	$ 1,420

XML

Contingencies and Regulatory Matters (Details) (USD $)	3 Months Ended	1 Months Ended		0 Months Ended
	Mar. 31, 2014 item	Apr. 30, 2008 Vogtle Units No.3 and No.4 item MW	Mar. 31, 2014 Costs associated with design changes, delays in the project schedule and issuance of the combined construction permits and operating licenses Vogtle Units No.3 and No.4	Mar. 13, 2014 Patronage Capital Litigation item
Nuclear Construction
Number of Westinghouse AP1000 nuclear generating units		2
Nominally rated generating capacity for each unit		1,100
Contractor's estimated adjustment attributable to the entity			$ 280,000,000
Number of defendant members				3
Number of excluded members against whom defendant class action is certified				1
Number of electric distribution cooperative members	38			38
Number of former consumer members				4
Percentage of cooperatives total booked patronage capital				30.00%
Period of revolving plan				13 years
Percentage of total equity owed to former members				7.70%

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Accumulated Comprehensive Margin (Deficit) (Tables)

3 Months Ended

Mar. 31, 2014

Accumulated Comprehensive Margin (Deficit)

Schedule of changes in accumulated other comprehensive margin (deficit)

	Accumulated Other Comprehensive Margin (Deficit) Three Months Ended
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2012	$	903
Unrealized (loss)		(148	)
(Gain) reclassified to net margin		(64	)
Balance at March 31, 2013	$	691
Balance at December 31, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)

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Restricted Cash (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Restricted Cash
Restricted cash balance	$ 10,892,000	$ 35,131,000
Long-term restricted cash	$ 10,736,000	$ 34,975,000

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General (Details)	3 Months Ended
	Mar. 31, 2014 item
General
Number of electric distribution cooperative members	38

XML

General

3 Months Ended

Mar. 31, 2014

General

General

(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-month periods ended March 31, 2014 and 2013. 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, as filed with the SEC. The results of operations for the three-month period ended March 31, 2014 are not necessarily indicative of results to be expected for the full year. As noted in our 2013 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 Form 10-K.)

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Condensed Statements of Revenues and Expenses (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating revenues:
Sales to Members	$ 334,759	$ 286,653
Sales to non-Members	32,541	19,261
Total operating revenues	367,300	305,914
Operating expenses:
Fuel	132,276	100,150
Production	108,084	94,720
Depreciation and amortization	40,714	37,083
Purchased power	20,066	12,667
Accretion	6,018	5,630
Deferral of Hawk Road and Smith Energy Facilities effect on net margin	(9,715)	(11,890)
Total operating expenses	297,443	238,360
Operating margin	69,857	67,554
Other income:
Investment income	9,282	7,277
Other	2,377	2,277
Total other income	11,659	9,554
Interest charges:
Interest expense	81,917	75,777
Allowance for debt funds used during construction	(23,729)	(24,854)
Amortization of debt discount and expense	4,105	4,161
Net interest charges	62,293	55,084
Net margin	$ 19,223	$ 22,024

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Debt

3 Months Ended

Mar. 31, 2014

Debt

Debt

(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, each dated February 20, 2014, made by us to Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The Federal Financing Bank Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through 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 Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to 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 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.

  Maturity, Interest Rate and Amortization.    The final maturity date for each advance 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 prior to February 20, 2020, up to a maximum of $335,471,604, is reflected as additional borrowings under the Facility.

  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 Federal Financing Bank 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).

  b)

  Rural Utilities Service Guaranteed Loans:

• For the three month period ended March 31, 2014, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $9,608,000 for general and environmental improvements at existing plants.

  In April 2014, we received an additional $10,674,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants as well.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014
Document and Entity Information
Entity Registrant Name	OGLETHORPE POWER CORP
Entity Central Index Key	0000788816
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1

XML

Subsequent Events

3 Months Ended

Mar. 31, 2014

Subsequent Events

Subsequent Events

(L)

Subsequent Events.    On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC for additional firm natural gas transportation to our Smith facility. The agreement has a base term of 25 years, and the fixed charge for the base term is $37,700,000 per year. Our obligation to make payments begins when the pipeline expansion project goes into service, which is projected to be May 1, 2017.

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Condensed Statements of Comprehensive Margin (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Condensed Statements of Comprehensive Margin
Net margin	$ 19,223	$ 22,024
Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities	396	(212)
Total comprehensive margin	$ 19,619	$ 21,812

XML

Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 2014

Contingencies and Regulatory Matters

Contingencies and Regulatory Matters

(F)

Contingencies and Regulatory Matters.

• Management does 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 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 Units 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.

  Current 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 portion of the additional costs claimed by the Contractor that would be 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 further 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. 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. 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.

  If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of March 31, 2014, 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. The lawsuit 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. The lawsuit also alleges 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 the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a regular 13-year revolving plan that retires 7.7% of total patronage capital owed to former consumer-members annually and seek relief to effect such retirements within the stated 13 year period. 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 we and Georgia Transmission should be required to implement a rate structure that would allow us and Georgia Transmission to begin retiring 7.7% of our allocated patronage capital annually. We intend to defend vigorously against all claims in this 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.

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Accumulated Comprehensive Margin (Deficit)

3 Months Ended

Mar. 31, 2014

Accumulated Comprehensive Margin (Deficit)

Accumulated Comprehensive Margin (Deficit)

(E)

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 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.

• 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 December 31, 2012	$	903
Unrealized (loss)		(148	)
(Gain) reclassified to net margin		(64	)
Balance at March 31, 2013	$	691
Balance at December 31, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities

Schedule of regulatory assets and liabilities

		2014		2013
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	79,804	$	82,499
Amortization on capital leases(b)		14,756		16,124
Outage costs(c)		50,814		35,155
Interest rate swap termination fees(d)		12,338		13,336
Depreciation expense(f)		48,006		48,362
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g)		28,675		27,678
Interest rate options cost(h)		71,185		38,984
Deferral of effects on net margin—Smith Energy Facility(i)		75,168		63,491
Other regulatory assets(j)		5,023		5,479
Total Regulatory Assets	$	385,769	$	331,108
Regulatory Liabilities:
Accumulated retirement costs for other obligations(e)	$	23,195	$	24,520
Deferral of effects on net margin—Hawk Road Energy Facility(i)		25,289		23,379
Major maintenance reserve(k)		25,900		28,064
Deferred debt service adder(l)		59,617		57,223
Asset retirement obligations(e)		19,456		19,508
Other regulatory liabilities(j)		6,980		6,095
Total Regulatory Liabilities	$	160,437	$	158,789
Net Regulatory Assets	$	225,332	$	172,319

^(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 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)

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 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⁾

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 35 years and the amortization period of other regulatory liabilities range up to 18 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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Fair Value (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value

Schedule of assets and liabilities measured at fair value on a recurring basis

			Fair Value Measurements at Reporting Date Using
		March 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	$	145,202	$	145,202	$	—	$	—
International equity trust		73,159		—		73,159		—
Corporate bonds		39,492		—		39,492		—
US Treasury and government agency securities		49,026		49,026		—		—
Agency mortgage and asset backed securities		29,654		—		29,654		—
Other		11,564		11,564		—		—
Long-term investments:
Corporate bonds		6,154		—		6,154		—
US Treasury and government agency securities		9,883		9,883		—		—
Agency mortgage and asset backed securities		3,267		—		3,267		—
International equity trust		11,259		—		11,259		—
Mutual funds		51,986		51,986		—		—
Other		44		44		—		—
Interest rate options		31,463		—		—		31,463	(1)
Natural gas swaps		1,960		—		1,960		—

			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 $10,730,000 and $34,970,000 of collateral received from the counterparties at March 31, 2014 and December 31, 2013, respectively.

Schedule of changes in Level 3 assets and liabilities measured at fair value on a recurring basis

		Three Months Ended March 31, 2014
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2013	$	63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(32,008	)
Balance at March 31, 2014	$	31,463

		Three Months Ended March 31, 2013
		Interest rate options
		(dollars in thousands)
Balance at December 31, 2012	$	25,783
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		756
Balance at March 31, 2013	$	26,539

Schedule of estimated fair values of long term debt, including current maturities

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

		2014				2013
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	6,933,851	$	7,534,625	$	6,954,293	$	7,317,476

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

(I)

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

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

		2014		2013
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	79,804	$	82,499
Amortization on capital leases(b)		14,756		16,124
Outage costs(c)		50,814		35,155
Interest rate swap termination fees(d)		12,338		13,336
Depreciation expense(f)		48,006		48,362
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(g)		28,675		27,678
Interest rate options cost(h)		71,185		38,984
Deferral of effects on net margin—Smith Energy Facility(i)		75,168		63,491
Other regulatory assets(j)		5,023		5,479
Total Regulatory Assets	$	385,769	$	331,108
Regulatory Liabilities:
Accumulated retirement costs for other obligations(e)	$	23,195	$	24,520
Deferral of effects on net margin—Hawk Road Energy Facility(i)		25,289		23,379
Major maintenance reserve(k)		25,900		28,064
Deferred debt service adder(l)		59,617		57,223
Asset retirement obligations(e)		19,456		19,508
Other regulatory liabilities(j)		6,980		6,095
Total Regulatory Liabilities	$	160,437	$	158,789
Net Regulatory Assets	$	225,332	$	172,319

^(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 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)

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 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⁾

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 35 years and the amortization period of other regulatory liabilities range up to 18 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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Restricted Cash

3 Months Ended

Mar. 31, 2014

Restricted Cash

Restricted Cash

(G)

Restricted Cash.    At March 31, 2014 and December 31, 2013, we had restricted cash totaling $10,892,000 and $35,131,000, respectively, of which $10,736,000 and $34,975,000, respectively, was classified as long-term. The long-term restricted cash balance at March 31, 2014 and December 31, 2013 consisted primarily of funds posted as collateral by counterparties to our interest rate options.

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Restricted Short-term Investments

3 Months Ended

Mar. 31, 2014

Restricted Short-term Investments

Restricted Short-term Investments

(H)

Restricted Short-term Investments.    At March 31, 2014 and December 31, 2013, we had $289,469,000 and $272,686,000, 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.

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Member Power Bill Prepayments

3 Months Ended

Mar. 31, 2014

Member Power Bill Prepayments

Member Power Bill Prepayments

(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 2014.

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Accumulated Comprehensive Margin (Deficit) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accumulated Comprehensive Margin (Deficit)
Effective income tax rate (as a percent)	0.00%
Accumulated other comprehensive margin (deficit)
Balance at the beginning of the period	$ (549)	$ 903
Unrealized gain (loss)	390	(148)
Loss (Gain) reclassified to net margin	6	(64)
Balance at the end of the period	$ (153)	$ 691

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Investments in Debt and Equity Securities (Tables)

3 Months Ended

Mar. 31, 2014

Investments in Debt and Equity Securities

Summary of activities for available-for-sale securities

	Gross Unrealized
		(dollars in thousands)
March 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	187,463	$	66,283	$	(1,190	)	$	252,556
Debt		165,776		8,509		(7,759	)		166,526
Other		11,607		2		(1	)		11,608
Total	$	364,846	$	74,794	$	(8,950	)	$	430,690

	Gross Unrealized
		(dollars in thousands)
December 31, 2013		Cost		Gains		Losses			Fair Value
Equity	$	182,755	$	68,424	$	(1,053	)	$	250,126
Debt		164,941		7,319		(9,070	)		163,190
Other		12,101		2		—			12,103
Total	$	359,797	$	75,745	$	(10,123	)	$	425,419

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Fair Value (Details 2) (Interest rate options, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Interest rate options
Assets (Liabilities):
Balance at the beginning of the period	$ 63,471	$ 25,783
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)	(32,008)	756
Balance at the end of the period	$ 31,463	$ 26,539

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Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Increase (Decrease) in Members' Capital
Balance	$ 713,940	$ 673,912
Components of comprehensive margin:
Net margin	19,223	22,024
Unrealized gain (loss) on available-for-sale securities	396	(212)
Balance	733,559	695,724
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Balance	714,489	673,009
Components of comprehensive margin:
Net margin	19,223	22,024
Balance	733,712	695,033
Accumulated Other Comprehensive Margin (Deficit)
Increase (Decrease) in Members' Capital
Balance	(549)	903
Components of comprehensive margin:
Unrealized gain (loss) on available-for-sale securities	396	(212)
Balance	$ (153)	$ 691

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Investments in Debt and Equity Securities

3 Months Ended

Mar. 31, 2014

Investments in Debt and Equity Securities

Investments in Debt and Equity Securities

(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 trust fund are directly added to or deducted from 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 86% of these gross unrealized losses were in effect for less than one year.

• The following tables summarize the activities for available-for-sale securities as of March 31, 2014 and December 31, 2013.

	Gross Unrealized
		(dollars in thousands)
March 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	187,463	$	66,283	$	(1,190	)	$	252,556
Debt		165,776		8,509		(7,759	)		166,526
Other		11,607		2		(1	)		11,608
Total	$	364,846	$	74,794	$	(8,950	)	$	430,690

	Gross Unrealized
		(dollars in thousands)
December 31, 2013		Cost		Gains		Losses			Fair Value
Equity	$	182,755	$	68,424	$	(1,053	)	$	250,126
Debt		164,941		7,319		(9,070	)		163,190
Other		12,101		2		—			12,103
Total	$	359,797	$	75,745	$	(10,123	)	$	425,419

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Fair Value (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Carrying Value
Grouping Financial Statement Captions
Long-term debt	$ 6,933,851	$ 6,954,293
Fair Value
Grouping Financial Statement Captions
Long-term debt	$ 7,534,625	$ 7,317,476

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Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified															3 Months Ended			3 Months Ended									3 Months Ended									3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Accumulated retirement costs for other obligations	Dec. 31, 2013 Accumulated retirement costs for other obligations	Mar. 31, 2014 Deferral of effects on net margin - Hawk Road Energy Facility Hawk Road	Dec. 31, 2013 Deferral of effects on net margin - Hawk Road Energy Facility Hawk Road	Mar. 31, 2014 Major maintenance sinking fund	Dec. 31, 2013 Major maintenance sinking fund	Mar. 31, 2014 Deferred debt service adder	Dec. 31, 2013 Deferred debt service adder	Mar. 31, 2014 Asset retirement obligations	Dec. 31, 2013 Asset retirement obligations	Mar. 31, 2014 Other regulatory liabilities	Dec. 31, 2013 Other regulatory liabilities	Mar. 31, 2014 Other regulatory liabilities Maximum	Mar. 31, 2014 Premium and loss on reacquired debt	Dec. 31, 2013 Premium and loss on reacquired debt	Mar. 31, 2014 Premium and loss on reacquired debt Maximum	Mar. 31, 2014 Amortization on capital leases	Dec. 31, 2013 Amortization on capital leases	Mar. 31, 2014 Outage costs	Dec. 31, 2013 Outage costs	Mar. 31, 2014 Interest rate swap termination fees	Dec. 31, 2013 Interest rate swap termination fees	Mar. 31, 2014 Depreciation expense	Dec. 31, 2013 Depreciation expense	Mar. 31, 2014 Depreciation expense Plant Vogtle	Mar. 31, 2014 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs Vogtle Units No.3 and No.4	Dec. 31, 2013 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs Vogtle Units No.3 and No.4	Mar. 31, 2014 Interest rate options cost	Dec. 31, 2013 Interest rate options cost	Mar. 31, 2014 Deferral of effects on net margin - Smith Energy Facility Smith	Dec. 31, 2013 Deferral of effects on net margin - Smith Energy Facility Smith	Mar. 31, 2014 Other regulatory assets	Dec. 31, 2013 Other regulatory assets	Mar. 31, 2014 Other regulatory assets Maximum	Mar. 31, 2014 Coal-fired outage costs Minimum	Mar. 31, 2014 Coal-fired outage costs Maximum	Mar. 31, 2014 Nuclear refueling outage costs Minimum	Mar. 31, 2014 Nuclear refueling outage costs Maximum
Regulatory assets and liabilities
Total Regulatory Assets	$ 385,769	$ 331,108														$ 79,804	$ 82,499		$ 14,756	$ 16,124	$ 50,814	$ 35,155	$ 12,338	$ 13,336	$ 48,006	$ 48,362		$ 28,675	$ 27,678	$ 71,185	$ 38,984	$ 75,168	$ 63,491	$ 5,023	$ 5,479
Total Regulatory Liabilities	160,437	158,789	23,195	24,520	25,289	23,379	25,900	28,064	59,617	57,223	19,456	19,508	6,980	6,095
Net Regulatory Assets	$ 225,332	$ 172,319
Amortization period																		30 years																		35 years	18 months	36 months	18 months	24 months
Operating license expected extension period for Plant Vogtle																											20 years
Operating license, expected extension period, for Plant Vogtle																											40 years
Amortization period															18 years

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Derivative instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments

Schedule of volume activity of natural gas derivatives that is expected to settle or mature each year

• The following table reflects the volume activity of our natural gas derivatives as of March 31, 2014 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2014	3.9
2015	1.1
Total	5.0

Schedule of remaining notional amount of forecasted debt issuances hedged in each year with LIBOR swaptions

• The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31, 2014.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2014	$	425,107
2015		470,625
2016		310,533
2017		80,169
Total	$	1,286,434

Schedule of fair value of derivative instruments and their effect on condensed balance sheets

	Balance Sheet Location		Fair Value
			2014		2013
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options(1)	Other deferred charges	$	31,463	$	63,471
Liabilities:
Natural gas swaps	Other current liabilities	$	1,960	$	1,011

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Excludes liability associated with cash collateral of $10,730,000 and $34,970,000 as of March 31, 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.

Schedule of the gross realized gains and (losses) on derivative instruments recognized in margin

	Statement of Revenues and		Three months ended March 31,
	Expenses Location		2014		2013
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	279	$	117
Natural Gas Swaps	Fuel		—		(534	)
		$	279	$	(417	)

Schedule of gross unrealized gains and (losses) on derivative instruments deferred on the balance sheet

	Balance Sheet Location		2014			2013
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory liability	$	1,960		$	1,011
Interest rate options	Regulatory asset		(41,720	)		(15,003	)
		$	(39,760	)	$	(13,992	)

Schedule of gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligation 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
		(dollars in thousands)
March 31, 2014
Assets:
Natural gas swaps	$	2,054	$	(94	)	$	—		$	1,960
Interest rate options	$	31,463	$	—		$	(10,730	)	$	20,733
December 31, 2013
Assets:
Natural gas swaps	$	1,069	$	(58	)	$	—		$	1,011
Interest rate options	$	63,471	$	—		$	(34,970	)	$	28,501