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, 2015
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                                    to

Commission File No. 000-53908

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

Georgia (State or other jurisdiction of incorporation or organization)	58-1211925 (I.R.S. employer identification no.)
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices)	30084-5336 (Zip Code)
Registrant's telephone number, including area code	(770) 270-7600

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

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

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o    Accelerated Filer o    Non-Accelerated Filer ý    (Do not check if a smaller reporting company)    Smaller Reporting 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, 2015

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Condensed Balance Sheets as of March 31, 2015 and December 31, 2014	1
	Unaudited Condensed Statements of Revenues and Expenses For the Three Months ended March 31, 2015 and 2014	3
	Unaudited Condensed Statements of Comprehensive Margin For the Three Months ended March 31, 2015 and 2014	4
	Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit) For the Three Months ended March 31, 2015 and 2014	5
	Unaudited Condensed Statements of Cash Flows For the Three Months ended March 31, 2015 and 2014	6
	Notes to Unaudited Condensed Financial Statements For the Three Months ended March 31, 2015 and 2014	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	27
Item 4.	Controls and Procedures	27
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	Mine Safety Disclosures	28
Item 5.	Other Information	28
Item 6.	Exhibits	28
SIGNATURES		29

i

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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, 2014. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

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

•

cost increases and schedule delays with respect to our capital improvement and construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;

•

costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;

•

the regulation of carbon dioxide emissions, such as the proposed Clean Power Plan or other potential legislative and regulatory responses to climate change initiatives or efforts to reduce other greenhouse gas emissions;

•

legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;

•

increasing debt caused by significant capital expenditures which is weakening certain of our financial metrics;

•

commercial banking and financial market conditions;

•

our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;

•

uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy for construction of two additional nuclear units at Plant Vogtle;

•

actions by credit rating agencies;

•

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

ii

•

adequate funding of our nuclear decommissioning trust fund including investment performance and projected decommissioning costs;

•

continued efficient operation of our generation facilities by us and third-parties;

•

the availability of an adequate and economical supply of fuel, water and other materials;

•

reliance on third-parties to efficiently manage, distribute and deliver generated electricity;

•

acts of sabotage, wars or terrorist activities, including cyber attacks;

•

litigation or legal and administrative proceedings and settlements;

•

the credit quality and/or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;

•

our members' ability to perform their obligations to us;

•

changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;

•

changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories;

•

general economic conditions;

•

weather conditions and other natural phenomena;

•

unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation efforts and the general economy;

•

unanticipated changes in interest rates or rates of inflation;

•

significant changes in our relationship with our employees, including the availability of qualified personnel;

•

unanticipated changes in capital expenditures, operating expenses and liquidity needs;

•

significant changes in critical accounting policies material to us; and

•

hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.

iii

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

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

		(dollars in thousands)
	2015			2014
Assets
Electric plant:
In service	$	8,368,040		$	8,345,241
Less: Accumulated provision for depreciation		(3,801,533	)		(3,762,690	)
		4,566,507			4,582,551
Nuclear fuel, at amortized cost		365,506			369,529
Construction work in progress		2,465,420			2,374,392
		7,397,433			7,326,472
Investments and funds:
Nuclear decommissioning trust fund		374,575			366,004
Investment in associated companies		68,745			67,368
Long-term investments		87,836			85,728
Restricted cash and investments		118,976			118,390
Other		18,036			17,397
		668,168			654,887
Current assets:
Cash and cash equivalents		271,704			237,391
Restricted short-term investments		251,725			247,057
Receivables		119,895			130,366
Inventories, at average cost		252,818			270,849
Prepayments and other current assets		42,840			12,667
		938,982			898,330
Deferred charges:
Deferred debt expense, being amortized		98,530			97,902
Regulatory assets		507,496			484,049
Other		86,646			84,603
		692,672			666,554
	$	9,697,255		$	9,546,243

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

1

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

		(dollars in thousands)
	2015		2014
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	776,493	$	761,124
Accumulated other comprehensive margin		421		468
		776,914		761,592
Long-term debt		7,196,761		7,113,000
Obligation under capital leases		100,456		100,456
Other		16,708		16,434
		8,090,839		7,991,482
Current liabilities:
Long-term debt and capital leases due within one year		161,502		160,754
Short-term borrowings		343,729		234,369
Accounts payable		39,071		98,337
Accrued interest		53,138		58,841
Member power bill prepayments, current		184,446		166,013
Other current liabilities		38,574		70,748
		820,460		789,062
Deferred credits and other liabilities:
Gain on sale of plant, being amortized		20,306		20,676
Asset retirement obligations		438,510		432,260
Member power bill prepayments, non-current		37,240		31,941
Power sale agreement, being amortized		9,501		12,669
Regulatory liabilities		202,232		194,073
Other		78,167		74,080
		785,956		765,699
	$	9,697,255	$	9,546,243

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, 2015 and 2014

		(dollars in thousands)
	Three Months
	2015			2014
Operating revenues:
Sales to Members	$	308,776		$	334,759
Sales to non-Members		31,002			32,541
Total operating revenues		339,778			367,300
Operating expenses:
Fuel		108,409			132,276
Production		114,759			108,084
Depreciation and amortization		42,652			40,714
Purchased power		13,631			20,066
Accretion		6,382			6,018
Deferral of Hawk Road and Smith Energy
Facilities effect on net margin		(14,315	)		(9,715	)
Total operating expenses		271,518			297,443
Operating margin		68,260			69,857
Other income:
Investment income		9,849			9,282
Other		2,859			2,377
Total other income		12,708			11,659
Interest charges:
Interest expense		87,707			81,917
Allowance for debt funds used during construction		(26,253	)		(23,729	)
Amortization of debt discount and expense		4,145			4,105
Net interest charges		65,599			62,293
Net margin	$	15,369		$	19,223

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 Months Ended March 31, 2015 and 2014

		(dollars in thousands)
	Three Months
	2015			2014
Net margin	$	15,369		$	19,223
Other comprehensive margin:
Unrealized (loss) gain on available-for-sale securities		(47	)		396
Total comprehensive margin	$	15,322		$	19,619

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, 2015 and 2014

		(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin (Deficit)			Total
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
Balance at December 31, 2014	$	761,124	$	468		$	761,592
Components of comprehensive margin:
Net margin		15,369		—			15,369
Unrealized loss on available-for-sale securities		—		(47	)		(47	)
Balance at March 31, 2015	$	776,493	$	421		$	776,914

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

5

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

		(dollars in thousands)
	2015			2014
Cash flows from operating activities:
Net margin	$	15,369		$	19,223
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		76,642			74,880
Accretion cost		6,382			6,018
Amortization of deferred gains		(447	)		(447	)
Allowance for equity funds used during construction		(173	)		(389	)
Deferred outage costs		(17,169	)		(25,845	)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		(14,315	)		(9,715	)
Gain on sale of investments		(4,687	)		(3,996	)
Regulatory deferral of costs associated with nuclear decommissioning		1,222			(84	)
Other		6,448			1,384
Change in operating assets and liabilities:
Receivables		10,471			(1,799	)
Inventories		18,031			24,827
Prepayments and other current assets		(30,174	)		1,892
Accounts payable		(39,364	)		(33,330	)
Accrued interest		(5,703	)		(8,804	)
Accrued taxes		(8,914	)		(13,144	)
Other current liabilities		(10,545	)		(2,075	)
Member power bill prepayments		23,732			12,105
Total adjustments		11,437			21,478
Net cash provided by operating activities		26,806			40,701
Cash flows from investing activities:
Property additions		(165,397	)		(134,354	)
Activity in nuclear decommissioning trust fund—Purchases		(111,750	)		(101,894	)
—Proceeds		110,666			100,648
(Increase) decrease in restricted cash and investments		(586	)		24,239
Increase in restricted cash and short-term investments		(4,668	)		(16,783	)
Activity in other long-term investments—Purchases		(12,045	)		(12,220	)
—Proceeds		11,214			12,413
Activity on interest rate options—Collateral returned		—			(46,940	)
—Collateral received		—			22,700
Other		(5,278	)		(401	)
Net cash used in investing activities		(177,844	)		(152,592	)
Cash flows from financing activities:
Long-term debt proceeds		113,718			734,608
Long-term debt payments		(37,319	)		(295,740	)
Increase (decrease) in short-term borrowings, net		109,360			(474,720	)
Other		(408	)		(41,957	)
Net cash provided by (used in) financing activities		185,351			(77,809	)
Net increase (decrease) in cash and cash equivalents		34,313			(189,700	)
Cash and cash equivalents at beginning of period		237,391			408,193
Cash and cash equivalents at end of period	$	271,704		$	218,493
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	69,258		$	65,816
Supplemental disclosure of non-cash investing and financing activities:
Change in plant expenditures included in accounts payable	$	(22,510	)	$	6,463

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, 2015 and 2014

(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, 2015 and 2014. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. 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, 2014, as filed with the SEC. The results of operations for the three-month periods ended March 31, 2015 are not necessarily indicative of results to be expected for the full year. As noted in our 2014 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the condensed balance sheets are principally from our members. (See "Notes to Financial Statements" in our 2014 Form 10-K.)

(B)

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

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

•

Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.

•

Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.

•

Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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, 2015 and December 31, 2014.

	Fair Value Measurements at Reporting Date Using
		March 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	163,991	$	163,991	$	—	$	—
International equity trust		74,705		—		74,705		—
Corporate bonds		18,298		—		18,298		—
US Treasury and government agency securities		70,197		70,197		—		—
Agency mortgage and asset backed securities		14,957		—		14,957		—
Municipal bonds		19,565		—		19,565		—
Other		12,862		12,862		—		—
Long-term investments:
International equity trust		11,508		—		11,508		—
Corporate bonds		6,135		—		6,135		—
US Treasury and government agency securities		17,129		17,129		—		—
Agency mortgage and asset backed securities		870		—		870		—
Mutual funds		51,932		51,932		—		—
Other		262		262		—		—
Interest rate options		2,702		—		—		2,702
Natural gas swaps		21,096		—		21,096		—

8

	Fair Value Measurements at Reporting Date Using
		December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	159,536	$	159,536	$	—	$	—
International equity trust		72,474		—		72,474		—
Corporate bonds		34,446		—		34,446		—
US Treasury and government agency securities		68,854		68,854		—		—
Agency mortgage and asset backed securities		16,148		—		16,148		—
Municipal Bonds		743		—		743		—
Other		13,803		13,803		—		—
Long-term investments:
Corporate bonds		5,445		—		5,445		—
US Treasury and government agency securities		16,619		16,619		—		—
Agency mortgage and asset backed securities		643		—		643		—
International equity trust		11,162		—		11,162		—
Mutual funds		51,741		51,741		—		—
Other		118		118		—		—
Interest rate options		4,371		—		—		4,371
Natural gas swaps		18,914		—		18,914		—

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

9

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, 2015 and 2014.

		Three Months Ended March 31, 2015
		Interest rate options
		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2014	$	4,371
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(1,669	)
Balance at March 31, 2015	$	2,702

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

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

10

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

		2015				2014
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,344,321	$	8,713,348	$	7,256,995	$	8,460,685

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

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

(C)

Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on long-term debt in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.

We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31, 2015, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating

11

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

At March 31, 2015 and December 31, 2014, the fair value of our natural gas contracts was a net liability of approximately $21,096,000 and $18,914,000, respectively.

As of March 31, 2015 and December 31, 2014, neither we nor any counterparties were required to post credit support or collateral under these natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2015 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit in the amount of $21,096,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of March 31, 2015 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2015	19.0
2016	11.0
2017	2.8
Total	32.8

12

Interest rate options.     We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,433,078,000 have expired and as of March 31, 2015 the remaining notional amount of our outstanding swaptions was approximately $746,126,000.

The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 177 basis points above the corresponding LIBOR swap rates that were in effect as of March 31, 2015, and the weighted average fixed rate is 4.02%. Swaptions having notional amounts totaling $115,201,000 expired without value during the three months ended March 31, 2015. The remaining swaptions expire quarterly through 2017.

We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At March 31, 2015 and December 31, 2014, the fair value of these swaptions was approximately $2,702,000 and $4,371,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of March 31, 2015 and December 31, 2014, there were no collateral postings made by the counterparties, 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 $2,200,000,000 of debt that we hedged with the swaptions.

The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31, 2015.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2015	$	355,424
2016		310,533
2017		80,169
Total	$	746,126

13

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

	Balance Sheet Location		Fair Value
			2015		2014
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options	Other deferred charges	$	2,702	$	4,371
Liabilities:
Natural gas swaps	Other current liabilities	$	12,241	$	13,418
Natural gas swaps	Other deferred credits		8,855		5,496

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

	Statement of Revenues and Expenses		Three months ended March 31,
	Location		2015			2014
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	—		$	279
Natural Gas Swaps	Fuel		(5,527	)		—
		$	(5,527	)	$	279

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

	Balance Sheet Location		2015			2014
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory asset	$	(21,096	)	$	(18,914	)
Interest rate options	Regulatory asset		(44,845	)		(49,232	)
Total not designated as hedges		$	(65,941	)	$	(68,146	)

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

		Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Cash Collateral		Net Amounts of Assets Presented on the Balance Sheet
		(dollars in thousands)
March 31, 2015
Assets:
Natural gas swaps	$	(21,096	)	$	—		$	—	$	(21,096	)
Interest rate options	$	47,547		$	(44,845	)	$	—	$	2,702
December 31, 2014
Assets:
Natural gas swaps	$	(18,914	)	$	—		$	—	$	(18,914	)
Interest rate options	$	53,603		$	(49,232	)	$	—	$	4,371

(D)

Investments in Debt and Equity Securities.    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. As of March 31, 2015, approximately 89% of these gross unrealized losses had been unrealized for a duration of less than one year.

The following tables summarize the activities for available-for-sale securities as of March 31, 2015 and December 31, 2014.

		Gross Unrealized
		(dollars in thousands)
March 31, 2015		Cost		Gains		Losses			Fair Value
Equity	$	206,199	$	71,575	$	(1,926	)	$	275,848
Debt		170,276		11,244		(8,082	)		173,438
Other		13,128		—		(3	)		13,125
Total	$	389,603	$	82,819	$	(10,011	)	$	462,411

		Gross Unrealized
		(dollars in thousands)
December 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	200,892	$	69,536	$	(2,163	)	$	268,265
Debt		168,182		9,981		(8,619	)		169,544
Other		13,927		—		(4	)		13,923
Total	$	383,001	$	79,517	$	(10,786	)	$	451,732

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(E)

Recently Issued or Adopted Accounting Pronouncements.    In May 2014, the Financial Accounting Standards Board issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted.

On April 1, 2015, the FASB proposed deferring the effective date by one year. Under the proposal, the standard would be effective for annual reporting periods beginning after December 15, 2017. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016.


We are currently evaluating the future impact of this standard to our consolidated financial position or results of operations.


In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30); Simplifying the Presentation of Debt Issuance Costs. The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in the standard are effective for the financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We are currently evaluating the impact of adoption on our consolidated financial position or results of operations.

(F)

Accumulated Comprehensive Margin (Deficit).    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2014 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Condensed Statement of Revenues and Expenses.

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, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)
Balance at December 31, 2014	$	468
Unrealized gain		107
(Gain) reclassified to net margin		(154	)
Balance at March 31, 2015	$	421

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(G)

Contingencies and Regulatory Matters.

We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

a.    Nuclear Construction

In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (the EPC Agreement) to design, engineer, procure, construct and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).

Under the EPC Agreement for Vogtle Units No. 3 and No. 4, 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.

In July 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and 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, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In March 2015, the U.S. Court of Appeals for the District of Columbia affirmed this dismissal which means the case will be tried in the U.S. District Court for the Southern District of Georgia. The portion of the additional costs claimed by the Contractor 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 extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. The Contractor did not specify amounts relating to these new allegations in its amended counterclaim; however, the Contractor has subsequently asserted related minimum damages, based on our ownership interest, of approximately $75,000,000. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not

17

agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues. Litigation is ongoing 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, 2015, no material amounts have been recorded related to this claim. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.

b.    Patronage Capital Litigation

On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level

18

where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

We intend to defend vigorously against all claims in the above-described litigation.

c.    Environmental Matters

As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.

In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

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

Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

(H)

Restricted Cash and Investments.    Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At March 31, 2015 and December 31, 2014, we had restricted cash and investments totaling $370,838,000 and $365,585,000, respectively, of which $118,976,000 and $118,390,000, respectively, were classified as long-term.

(I)

Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members extending through 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.

19

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

		2015		2014
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	69,277	$	71,731
Amortization on capital leases(b)		28,362		27,829
Outage costs(c)		51,969		45,795
Interest rate swap termination fees(d)		8,348		9,345
Depreciation expense(e)		46,582		46,938
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		33,643		32,501
Interest rate options cost(g)		100,470		98,671
Deferral of effects on net margin—Smith Energy Facility(h)		144,330		128,666
Other regulatory assets(m)		24,515		22,573
Total Regulatory Assets	$	507,496	$	484,049
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	15,774	$	18,559
Deferral of effects on net margin—Hawk Road Energy Facility(h)		31,178		29,867
Major maintenance reserve(j)		22,952		23,427
Amortization on capital leases(b)		23,924		21,693
Deferred debt service adder(k)		69,124		66,754
Asset retirement obligations(l)		34,394		28,870
Other regulatory liabilities(m)		4,886		4,903
Total Regulatory Liabilities	$	202,232	$	194,073
Net Regulatory Assets	$	305,264	$	289,976

^(a)

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

^(b)

Represents the difference between lease payments and the aggregate of the amortization on the capital lease assets and the interest on the capital lease obligations for rate-making purposes.

^(c)

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

^(d)

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

^(e)

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.

^(f)

Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.

^(g)

Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain 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.

^(h)

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

⁽ⁱ⁾

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

^(j)

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

^(k)

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

^(l)

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

^(m)

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

20

(J)

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

(K)

Debt.

a)

Department of Energy Loan Guarantee:

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations 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 two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through the Federal Financing Bank.


Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, $335,471,604 of which is designated for capitalized interest.


Advances may be requested under the Facility on a quarterly basis through December 31, 2020. At March 31, 2015, aggregate borrowings totaled $882,672,000, including capitalized interest advanced under the loan.

b)

Rural Utilities Service Guaranteed Loans:

For the three month period ended March 31, 2015, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $113,718,000 for general and environmental improvements at existing plants.

c)

Credit Facilities:

On March 23, 2015, we entered into a $1,210,000,000 credit agreement with a syndicate of thirteen lenders, led by the National Rural Utilities Cooperative Finance Corporation as administrative agent.

(L)

Nuclear Fuel Disposal Cost Litigation.    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract.

On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of January 1, 2005 through December 31, 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded in our March 31, 2015 financial statements and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service.

21

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

Results of Operations

For the Three Months Ended March 31, 2015 and 2014

Net Margin

Our net margin for the three-month period ended March 31, 2015 was $15.4 million compared to $19.2 million for the same period of 2014. Through March 31, 2015, we collected approximately 32% of our targeted net margin of $48.6 million for the year ending December 31, 2015. This is typical as our capacity revenues are recorded evenly throughout the year and our management generally budgets conservatively. We anticipate our board of directors will approve a budget adjustment by the end of the year so that net margins will achieve, but not exceed, the targeted margins for interest ratio. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" of our 2014 Form 10-K.

Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

Sales to Members.    We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, and are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operations and maintenance expense.

22

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

		Three Months Ended March 31,			2015 vs. 2014 % Change
		2015		2014
Capacity revenues	$	195,328	$	191,676	1.9%
Energy revenues		113,448		143,083	(20.7%)
Total	$	308,776	$	334,759	(7.8%)
kWh Sales to members		4,567,689		4,905,224	(6.9%)
Cents/kWh		6.76		6.82	(0.9%)

The decrease in energy revenues to members for the three-months ended March 31, 2015 compared to the same period in 2014 was primarily due to a decrease in fuel costs, a decrease in generation for member sales and, to lesser extent, a decrease in purchase power energy. Lower member demand as a result of milder weather experienced during the first quarter of 2015 contributed to these decreases. Primarily as a result of the decrease in fuel costs, average energy revenue per kilowatt-hour from sales to members decreased 14.9% for the three-month period ended March 31, 2015 as compared to the same period of 2014. For a discussion of fuel costs and purchased power costs, see "—Operating Expenses."

Sales to Non-members.    Our sales to non-members primarily consist of capacity and energy sales at the Smith Energy Facility.

Operating Expenses.    Operating expenses decreased 8.7% for the three-month period ended March 31, 2015 compared to the same period of 2014 which was driven by lower fuel and purchased power costs.

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

		Cost						Generation					Cents per kWh
		(dollars in thousands)						(kWh in thousands)					(kWh in thousands)
	Three Months Ended March 31,				2015 vs.		Three Months Ended March 31,			2015 vs.		Three Months Ended March 31,			2015 vs.
Fuel Source		2015		2014	2014 % Change			2015	2014	2014 % Change			2015	2014	2014 % Change
Coal	$	42,485	$	56,486	(24.8%	)		1,405,651	1,896,226	(25.9%	)		3.02	2.98	1.5%
Nuclear(1)		13,007		20,765	(37.4%	)		2,377,764	2,225,966	6.8%			0.55	0.93	(41.4%	)
Gas:
Combined Cycle		47,315		51,201	(7.6%	)		1,582,967	1,138,084	39.1%			2.99	4.50	(33.6%	)
Combustion Turbine		5,602		3,824	46.5%			46,157	21,425	115.4%			12.14	17.85	(32.0%	)
	$	108,409	$	132,276	(18.0%	)		5,412,539	5,281,701	2.5%			2.00	2.50	(20.0%	)

⁽¹⁾

The 2015 nuclear fuel cost amount includes a $7.1 million credit for nuclear fuel storage costs recovered as a result of litigation related to responsibility for nuclear fuel disposal costs. The exclusion of the credit would have resulted in total nuclear fuel costs of $20.1 million, a 3.3% decline and nuclear cost per kWh of 0.84 cents per kWh, a 9.5% decline from the same period of 2014. For information regarding this litigation, see Note L.

The decrease in total fuel costs for the three-month period ended March 31, 2015 compared to the same period of 2014 was primarily due to lower natural gas costs and the recognition of a $7.1 million reduction in fuel expense associated with the recovery of spent nuclear fuel storage costs from the U.S. Department of Energy. For additional information regarding nuclear fuel disposal cost recovery, see Note L. Generation from coal-fired plants decreased for the three-month period ended March 31, 2015

23

as compared to the same period of 2014 primarily due to a decrease in member demand as a result of more moderate weather as compared to the extreme cold weather experienced during the first quarter of 2014. Generation from natural-gas fired plants increased during the first quarter of 2015 primarily as a result of lower natural gas prices and an increase in non-member megawatt-hour sales.

Production costs increased 6.2% for the three-month period ended March 31, 2015 as compared to the same period of 2014. The increase resulted primarily from planned major maintenance outage work at Smith in 2015.

Purchase power costs decreased 32.1% for the three-month period ended March 31, 2015 as compared to the same period of 2014 primarily due to a decrease in energy purchases. This decrease was largely due to a decrease in demand as a result of more moderate weather during the first quarter of 2015.

Interest charges

Interest expense increased 7.1% for the three-month period ended March 31, 2015 as compared to the same period of 2014 primarily due to increased debt to finance construction of Vogtle Units No. 3 and No. 4.

Financial Condition

Balance Sheet Analysis as of March 31, 2015

Assets

Cash used for property additions for the three-month period ended March 31, 2015 totaled $165.4 million. Of this amount, approximately $80.1 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $14.4 million for nuclear fuel purchases and the remaining expenditures were for normal additions and replacements to existing generation facilities.

Prepayments and other current assets increased $30.2 million for the three-month period ended March 31, 2015 primarily as a result of the prepayment of major maintenance costs for an outage at our Smith facility.

Restricted cash and investments at March 31, 2015 consist primarily of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The funds, including interest earned thereon, can only be applied to debt service on Rural Utilities Service and Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding when to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.

Equity and Liabilities

Short-term borrowings increased $109.4 million for the three-month period ended March 31, 2015. These borrowings provided interim financing for capital expenditures related to the Vogtle Units No. 3 and No. 4 construction project.

Accounts payable decreased $59.3 million for the three-month period ended March 31, 2015 primarily as a result of a $31.7 million decrease in the payable to Georgia Power for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4. Also contributing to the decrease was $17.7 million in credits, applied to our members' bills in the first quarter of 2015, for a board approved reduction in 2014 revenue requirements as a result of margin collections in excess of our 2014 target.

Other current liabilities decreased $32.2 million for the three-month period ended March 31, 2015 primarily due to the payment of operation and maintenance expenses and property taxes accrued at December 31, 2014.

24

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, 2015, our total investment in Vogtle Units No. 3 and No. 4 was $2.5 billion.

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 2014 Form 10-K. Also see Note G and Note K.

Environmental Regulations

The U.S. Environmental Protection Agency, or EPA, continues to develop a number of rules that significantly expand the scope of regulation of air emissions, water and waste management at power plants. Following are some of the recent developments that may affect future operations at our facilities.

On April 17, 2015 EPA published its final coal combustion residuals (CCR) rule, in which it decided to regulate CCRs as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act. The final rule contains requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. The rule takes effect on October 14, 2015. We are still reviewing the effects of the CCR, but they could include actions to address some or all of the requirements listed above. Significant operational changes for existing CCR storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities and additional material management and financial assurance requirements may be needed. Preliminary estimates suggest that our capital costs for compliance with the CCR (in combination with EPA's proposed effluent limitations guidelines rule which is to be finalized by September 2015) could be approximately $200 million. More definitive cost estimates will be developed as the process of rule evaluation, compliance approach design and construction implementation proceeds, and the ultimate impacts associated with the CCR rule cannot be determined with certainty at this time.

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 2014 Form 10-K.

Liquidity

At March 31, 2015, we had $1.3 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $272 million in cash and cash equivalents and $1.0 billion of unused and available committed credit arrangements.

25

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

Committed Credit Facilities
		Authorized Amount			Available March 31, 2015		Expiration Date
		(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by CFC	$	1,210	(1)	$	730	(2)	March 2020
CFC Line of Credit(3)		110			110		December 2018
JPMorgan Chase Line of Credit		150			34	(4)	November 2016
Secured Facilities:
CFC Term Loan(3)		250			250		December 2018

⁽¹⁾

The amount of this facility that can be used to support outstanding commercial paper is limited to $1.0 billion.

⁽²⁾

Of the portion of this facility that was unavailable at March 31, 2015, $344 million was dedicated to support outstanding commercial paper and $136 million was related to letters of credit issued to support variable rate demand bonds.

⁽³⁾

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

⁽⁴⁾

Of the portion of this facility that was unavailable at March 31, 2015, $114 million related to letters of credit issued to support variable rate demand bonds and $2 million related to letters of credit issued to post collateral to third parties.

As of March 31, 2015, we were using our commercial paper program to provide interim funding for 1) payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of permanent funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than quarterly and 2) the premium payments made in connection with our interest rate hedging program. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide for the interim financings described above.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding.

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $508 million remained available at March 31, 2015. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At March 31, 2015, the required minimum level was $675 million and our actual patronage capital was $776 million. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At March 31, 2015, we had $7.4 billion of secured indebtedness and $344 million of unsecured indebtedness outstanding.

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

26

Financing Activities

First Mortgage Indenture.    At March 31, 2015, we had $7.3 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2014 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    We currently have three approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These three loans total $561 million with $212 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of March 31, 2015, we had $2.7 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loan.    In February 2014, we closed on a loan with the Department of Energy that will fund up to the lesser of $3.057 billion or 70% of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.

As of March 31, 2015, our total investment in Vogtle Units No. 3 and No. 4 was $2.5 billion and we have incurred $2.3 billion of debt to provide long-term financing for this investment. This long-term debt includes $1.4 billion of taxable first mortgage bonds we previously issued and $883 million, including capitalized interest, under the Department of Energy loan facility. The facility may be used until no later than December 2020 to provide long-term funding for up to 70% of eligible project costs after they are incurred. As of March 31, 2015, we have the capacity to fund an additional $746 million under the facility based on the amount of eligible project costs we have incurred to date. We anticipate making draws on at least a semi-annual basis to meet our funding requirements as construction progresses. When advanced, the debt will be secured under our first mortgage indenture. For additional information regarding this loan, see Note K.

For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2014 Form 10-K.

Newly Adopted or Issued Accounting Standards

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

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" of our 2014 Form 10-K.

Item 4.    Controls and Procedures

As of March 31, 2015, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

27

PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

There have not been any material changes to legal proceedings from those reported in "Item 3—LEGAL PROCEEDINGS" of our 2014 Form 10-K.

Item 1A.    Risk Factors

There have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our 2014 Form 10-K.

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

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Mine Safety Disclosures

Not Applicable.

Item 5.    Other Information

Not Applicable.

Item 6.    Exhibits

Number		Description
	31.1	Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer).
	31.2	Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
	32.1	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer).
	32.2	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
	99.1	Member Financial and Statistical Information (For calendar years 2012-2014).
	101	XBRL Interactive Data File.

28

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 13, 2015	By:	/s/ Michael L. Smith Michael L. Smith President and Chief Executive Officer
Date: May 13, 2015		/s/ Elizabeth B. Higgins Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

29

EX-31.1

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 13, 2015

/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, 2015 (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 13, 2015

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, 2015 (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 13, 2015

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, 2014). 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 2012, 2013 and 2014, 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 (2)		Colquitt		Coweta- Fayette		Diverse (2)
2014
Avg. Monthly Residential Rev. ($)		150.05		137.04		146.54		148.86		124.40		173.32		127.10		136.55		136.84		166.67
Avg. Monthly Residential kWh		1,129		1,238		1,238		1,227		1,442		1,287		1,157		1,241		1,289		1,345
Avg. Residential Rev.(cents per kWh)		13.29		11.07		11.84		12.13		8.63		13.47		10.98		11.01		10.61		12.39
Times Interest Earned Ratio (1)		2.14		2.04		2.55		1.50		2.20		1.72		1.83		2.49		2.42		1.46
Equity / Assets (1)		61%		47%		46%		37%		37%		32%		43%		44%		41%		37%
Equity / Total Capitalization (1)		66%		61%		55%		44%		41%		36%		47%		52%		45%		43%
2013
Avg. Monthly Residential Rev. ($)		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		2.45		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. ($)		139.96		127.27		140.19		134.61		115.01		157.04		129.52		127.26		125.79		157.74
Avg. Monthly Residential kWh		1,046		1,115		1,160		1,124		1,253		1,205		1,141		1,184		1,224		1,297
Avg. Residential Rev.(cents per kWh)		13.39		11.41		12.08		11.98		9.18		13.03		11.35		10.75		10.28		12.16
Times Interest Earned Ratio (1)		3.18		1.84		2.62		1.78		2.04		1.41		2.32		2.61		2.32		1.72
Equity / Assets (1)		66%		44%		42%		37%		36%		30%		42%		42%		37%		47%
Equity / Total Capitalization (1)		71%		58%		49%		43%		39%		33%		48%		50%		41%		52%
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2014
Avg. Monthly Residential Rev. ($)		152.25		157.70		129.86		158.38		151.57		153.44		144.08		143.93		131.21		140.86
Avg. Monthly Residential kWh		1,309		1,231		1,053		1,238		1,203		1,265		1,084		1,267		1,261		1,181
Avg. Residential Rev.(cents per kWh)		11.63		12.81		12.33		12.79		12.60		12.13		13.30		11.36		10.41		11.93
Times Interest Earned Ratio (1)		2.58		2.18		2.87		1.92		1.78		2.69		1.68		3.04		2.06		2.66
Equity / Assets (1)		39%		51%		48%		34%		35%		50%		26%		43%		38%		40%
Equity / Total Capitalization (1)		43%		62%		57%		39%		42%		58%		30%		54%		51%		49%
2013
Avg. Monthly Residential Rev. ($)		145.83		152.93		119.44		134.78		144.22		140.85		134.25		140.87		129.20		134.53
Avg. Monthly Residential kWh		1,218		1,184		987		1,116		1,152		1,184		1,009		1,190		1,196		1,123
Avg. Residential Rev.(cents per kWh)		11.97		12.91		12.11		12.08		12.52		11.89		13.30		11.84		10.80		11.98
Times Interest Earned Ratio (1)		0.33		2.37		2.04		1.27		1.51		2.18		1.03		3.08		2.41		2.64
Equity / Assets (1)		34%		51%		45%		32%		35%		52%		25%		44%		41%		39%
Equity / Total Capitalization (1)		39%		60%		53%		40%		40%		58%		30%		54%		53%		49%
2012
Avg. Monthly Residential Rev. ($)		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%

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)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 1 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2014
Avg. Monthly Residential Rev. ($)		128.01		152.59		142.89		127.49		134.64		144.72		155.02		127.99		146.05	137.74
Avg. Monthly Residential kWh		1,325		1,368		1,150		1,223		1,076		1,153		1,124		1,297		1,180	1,054
Avg. Residential Rev.(cents per kWh)		9.66		11.15		12.42		10.43		12.52		12.55		13.79		9.87		12.37	13.07
Times Interest Earned Ratio (1)		2.30		1.77		2.59		2.15		1.71		2.71		1.98		2.18		2.05	1.97
Equity / Assets (1)		57%		36%		45%		43%		36%		42%		32%		41%		43%	33%
Equity / Total Capitalization (1)		65%		45%		54%		48%		42%		50%		34%		47%		53%	39%
2013
Avg. Monthly Residential Rev. ($)		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. ($)		117.33		130.70		131.50		117.94		120.42		126.30		137.42		120.52		139.06	127.10
Avg. Monthly Residential kWh		1,231		1,271		1,081		1,158		987		1,057		1,062		1,225		1,121	987
Avg. Residential Rev.(cents per kWh)		9.53		10.29		12.16		10.18		12.20		11.95		12.93		9.84		12.41	12.88
Times Interest Earned Ratio (1)		2.14		1.61		2.30		1.72		1.41		1.91		1.37		1.97		2.18	1.52
Equity / Assets (1)		59%		35%		45%		42%		31%		43%		33%		40%		40%	32%
Equity / Total Capitalization (1)		66%		41%		55%		47%		36%		52%		36%		46%		49%	37%
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER WTD. AVG.
2014
Avg. Monthly Residential Rev. ($)		130.30		167.16		170.35		127.77		154.42		130.22		134.79		129.59			137.07
Avg. Monthly Residential kWh		1,346		1,329		1,409		946		1,226		1,148		1,311		1,115			1,251
Avg. Residential Rev.(cents per kWh)		9.68		12.6		12.09		13.5		12.60		11.34		10.28		11.62			10.96
Times Interest Earned Ratio (1)		1.70		2.29		1.93		3.56		1.67		3.31		3.32		2.12			2.11
Equity / Assets (1)		39%		35%		47%		42%		36%		51%		44%		52%			41%
Equity / Total Capitalization (1)		53%		43%		52%		45%		39%		59%		63%		57%			49%
2013
Avg. Monthly Residential Rev. ($)		121.08		153.37		160.29		115.67		139.00		118.63		126.45		119.22			129.49
Avg. Monthly Residential kWh		1,252		1,252		1,317		887		1,142		1,063		1,238		1,036			1,179
Avg. Residential Rev.(cents per kWh)		9.67		12.25		12.18		13.03		12.17		11.16		10.21		11.50			10.99
Times Interest Earned Ratio (1)		1.52		2.00		1.85		1.64		1.56		2.45		3.48		2.17			1.92
Equity / Assets (1)		41%		33%		47%		38%		34%		51%		44%		52%			41%
Equity / Total Capitalization (1)		54%		40%		52%		43%		37%		59%		58%		57%			48%
2012
Avg. Monthly Residential Rev. ($)		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
Equity / Assets (1)		43%		36%		48%		40%		35%		51%		40%		51%			41%
Equity / Total Capitalization (1)		55%		43%		53%		44%		37%		59%		53%		56%			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)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

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 (1)		Colquitt		Coweta- Fayette		Diverse (1)
2014
Residential Service		18,051		42,094		20,021		46,812		48,158		15,122		176,178		57,965		70,031		29,365
Commercial & Industrial		1,795		4,411		341		2,453		4,457		2,171		15,917		3,448		5,926		4,161
Other		207		9		405		370		298		148		5,078		2,715		746		901
Total Consumers Served		20,053		46,514		20,767		49,635		52,913		17,441		197,173		64,128		76,703		34,427
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
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2014
Residential Service		5,099		21,160		10,794		10,497		32,302		15,043		15,743		49,349		143,789		7,850
Commercial & Industrial		1,705		1,177		660		1,866		2,376		580		2,556		2,558		15,707		375
Other		1,056		2,782		539		169		434		895		—		2,228		1,383		252
Total Consumers Served		7,860		25,119		11,993		12,532		35,112		16,518		18,299		54,135		160,879		8,477
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 2 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2014
Residential Service		20,422		71,442		18,345		113,228		31,545		28,134		10,771		192,993		31,112		10,575
Commercial & Industrial		1,349		9,763		477		8,697		2,396		7,242		143		16,383		1,699		135
Other		364		979		638		137		7		10		1,293		4,621		385		395
Total Consumers Served		22,135		82,184		19,460		122,062		33,948		35,386		12,207		213,997		33,196		11,105
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
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2014
Residential Service		88,901		17,525		14,630		13,809		19,044		8,294		112,271		14,590				1,653,054
Commercial & Industrial		4,048		1,091		4,862		529		1,923		694		7,791		615				144,477
Other		1,136		16		635		911		—		113		1,733		106				34,094
Total Consumers Served		94,085		18,632		20,127		15,249		20,967		9,101		121,795		15,311				1,831,625
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

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 (1)		Colquitt		Coweta- Fayette		Diverse (1)
2014
Residential Service		244,571		625,220		297,399		689,101		833,126		233,496		2,446,619		862,949		1,083,647		473,907
Commercial & Industrial		159,484		108,137		115,963		365,050		421,039		225,448		1,180,381		256,093		437,499		194,732
Other		7,622		181		6,196		6,737		4,006		2,592		211,364		99,631		8,456		42,485
Total MWh Sales		411,677		733,538		419,559		1,060,888		1,258,171		461,537		3,838,363		1,218,673		1,529,602		711,124
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
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2014
Residential Service		80,096		312,645		136,439		156,004		466,312		228,340		204,693		750,516		2,175,190		111,259
Commercial & Industrial		38,908		71,674		45,979		190,962		62,470		31,407		58,815		312,458		1,076,306		58,167
Other		30,714		77,033		9,003		4,598		17,487		25,103		—		42,750		29,526		3,769
Total MWh Sales		149,718		461,352		191,420		351,564		546,269		284,850		263,508		1,105,725		3,281,022		173,195
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 3 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2014
Residential Service		324,757		1,172,804		253,164		1,661,068		407,131		389,349		145,285		3,003,211		440,649		133,781
Commercial & Industrial		69,978		555,935		37,944		1,044,869		99,347		190,072		27,139		1,907,420		110,236		49,311
Other		5,249		49,215		18,829		16,608		142		739		29,410		290,569		20,351		6,802
Total MWh Sales		399,983		1,777,953		309,937		2,722,545		506,620		580,159		201,834		5,201,199		571,236		189,894
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
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2014
Residential Service		1,436,457		279,492		247,375		156,754		280,141		114,297		1,766,715		195,241				24,819,199
Commercial & Industrial		464,861		49,770		92,571		28,453		90,238		14,969		672,702		160,465				11,077,249
Other		17,188		4,970		39,855		47,983		—		3,204		75,643		5,849				1,261,860
Total MWh Sales		1,918,506		334,232		379,801		233,189		370,379		132,470		2,515,060		361,555				37,158,308
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

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 (1)		Colquitt		Coweta- Fayette			Diverse (1)
2014
Residential Service	$	32,502,906	$	69,221,808		$	35,206,165	$	83,621,543		$	71,889,185	$	31,451,542	$	268,711,028	$	94,979,008	$	115,000,171		$	58,730,616
Commercial & Industrial		15,318,133		13,192,521			11,214,679		29,763,343			31,473,290		20,688,752		110,323,157		24,603,753		39,532,563			19,326,447
Other		870,701		36,049			887,327		909,728			642,185		408,480		24,410,146		10,949,665		1,775,470			4,616,663
Total Electric Sales	$	48,691,740	$	82,450,378		$	47,308,171	$	114,294,614		$	104,004,660	$	52,548,774	$	403,444,330	$	130,532,426	$	156,308,204		$	82,673,726
Other Operating Revenue		286,802		3,449,429			6,287,011		1,521,840			3,622,259		746,554		9,211,084		3,231,663		3,478,495			3,113,734
Total Operating Revenue	$	48,978,542	$	85,899,807		$	53,595,182	$	115,816,454		$	107,626,919	$	53,295,328	$	412,655,414	$	133,764,089	$	159,786,699		$	85,787,460
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
	Middle Georgia		Mitchell			Ocmulgee		Oconee			Okefenoke		Planters		Rayle		Satilla		Sawnee			Slash Pine
2014
Residential Service	$	9,315,777	$	40,042,568		$	16,819,951	$	19,950,337		$	58,752,429	$	27,697,481	$	27,218,498	$	85,236,127	$	226,405,531		$	13,268,642
Commercial & Industrial		4,896,847		8,197,450			4,447,893		14,086,620			7,598,333		3,047,313		7,580,040		23,352,895		99,206,916			5,725,497
Other		3,987,215		10,079,486			1,334,532		552,473			2,055,754		3,335,160		—		5,350,513		5,551,082			478,490
Total Electric Sales	$	18,199,839	$	58,319,504		$	22,602,376	$	34,589,430		$	68,406,516	$	34,079,954	$	34,798,538	$	113,939,535	$	331,163,529		$	19,472,629
Other Operating Revenue		572,366		(637,525	)		781,808		708,039			969,161		1,653,677		483,650		3,276,493		(5,321,351	)		772,306
Total Operating Revenue	$	18,772,205	$	57,681,979		$	23,384,184	$	35,297,469		$	69,375,677	$	35,733,631	$	35,282,188	$	117,216,028	$	325,842,178		$	20,244,935
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 4 (continued)

	Excelsior			Flint		Grady		GreyStone		Habersham		Hart		Irwin			Jackson		Jefferson		Little Ocmulgee
2014
Residential Service	$	31,369,776		$	130,815,290	$	31,454,811	$	173,231,715	$	50,964,997	$	48,859,313	$	20,036,743		$	296,423,591	$	54,526,532	$	17,479,296
Commercial & Industrial		6,916,742			52,165,387		3,844,017		95,186,140		11,117,366		22,389,790		3,152,184			166,426,540		10,621,678		4,450,005
Other		660,250			4,896,819		2,357,523		2,576,204		10,838		77,313		3,955,758			30,459,903		2,605,315		988,687
Total Electric Sales	$	38,946,768		$	187,877,496	$	37,656,351	$	270,994,059	$	62,093,201	$	71,326,416	$	27,144,685		$	493,310,034	$	67,753,525	$	22,917,988
Other Operating Revenue		(53,657	)		8,113,583		1,691,541		8,373,725		1,987,790		2,430,256		760,098			17,425,900		4,073,898		998,298
Total Operating Revenue	$	38,893,111		$	195,991,079	$	39,347,892	$	279,367,784	$	64,080,991	$	73,756,672	$	27,904,783		$	510,735,934	$	71,827,423	$	23,916,286
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
	Snapping Shoals			Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton			Washington				MEMBER TOTAL
2014
Residential Service	$	139,003,760		$	35,153,830	$	29,906,410	$	21,171,783	$	35,288,799	$	12,961,010	$	181,601,959		$	22,689,151			$	2,718,960,079
Commercial & Industrial		36,602,849			5,312,315		11,676,789		3,898,302		9,307,516		1,786,663		62,223,219			12,584,310				1,013,238,254
Other		2,949,211			421,726		5,227,065		8,225,068		—		399,321		9,143,413			611,735				153,797,268
Total Electric Sales	$	178,555,820		$	40,887,871	$	46,810,264	$	33,295,153	$	44,596,315	$	15,146,994	$	252,968,591		$	35,885,196			$	3,885,995,600
Other Operating Revenue		(4,561,532	)		1,154,770		1,246,778		782,458		1,225,393		475,790		(2,329,997	)		935,917				82,938,504
Total Operating Revenue	$	173,994,288		$	42,042,641	$	48,057,042	$	34,077,611	$	45,821,708	$	15,622,784	$	250,638,594		$	36,821,113			$	3,968,934,104
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

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 (1)		Colquitt		Coweta- Fayette		Diverse (1)
2014
Operating Revenue & Patronage Capital	$	48,978,545		$	85,899,807	$	53,595,182	$	115,816,454	$	107,626,919	$	53,295,328	$	412,655,414	$	133,764,089	$	159,786,698	$	85,787,460
Depreciation and Amortization		3,210,826			5,899,816		3,938,456		8,398,486		5,944,196		2,832,851		30,262,072		7,691,600		9,213,497		7,289,346
Other Operating Expenses		44,384,266			76,522,930		44,551,325		101,503,042		93,035,911		47,246,975		356,690,448		117,085,488		140,323,834		73,477,881
Electric Operating Margin	$	1,383,453		$	3,477,061	$	5,105,401	$	5,914,926	$	8,646,812	$	3,215,502	$	25,702,893	$	8,987,001	$	10,249,367	$	5,020,233
Other Income		1,288,009			2,463,251		1,691,844		2,366,138		3,065,334		776,115		19,464,540		1,807,982		6,629,031		1,470,719
Gross Operating Margin	$	2,671,462		$	5,940,312	$	6,797,245	$	8,281,064	$	11,712,146	$	3,991,617	$	45,167,434	$	10,794,983	$	16,878,398	$	6,490,952
Interest on Long-term Debt		1,238,177			2,911,273		2,659,289		5,509,467		5,307,952		2,278,518		24,412,233		4,330,037		6,918,759		4,413,911
Other Deductions		25,620			335		22,404		—		38,391		72,296		560,838		—		147,510		60,028
Net Margins	$	1,407,665		$	3,028,704	$	4,115,552	$	2,771,597	$	6,365,803	$	1,640,803	$	20,194,363	$	6,464,946	$	9,812,129	$	2,017,013
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	$	8,621,425	$	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	$	10,354,408	$	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		—		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
	Middle Georgia			Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2014
Operating Revenue & Patronage Capital	$	18,772,204		$	57,681,979	$	23,384,184	$	35,297,469	$	69,375,677	$	35,733,630	$	35,282,188	$	117,216,027	$	325,842,179	$	20,244,935
Depreciation and Amortization		1,394,849			4,063,617		1,388,825		1,958,405		4,706,524		1,935,394		2,529,534		5,977,384		16,088,754		895,077
Other Operating Expenses		15,080,689			50,614,745		19,465,936		30,343,502		59,696,084		31,301,024		29,999,790		102,786,811		294,294,130		17,862,267
Electric Operating Margin	$	2,296,666		$	3,003,617	$	2,529,423	$	2,995,562	$	4,973,069	$	2,497,212	$	2,752,864	$	8,451,832	$	15,459,295	$	1,487,591
Other Income		447,307			1,385,349		476,627		685,351		1,314,236		1,343,718		1,073,794		2,745,072		7,059,756		432,470
Gross Operating Margin	$	2,743,973		$	4,388,966	$	3,006,050	$	3,680,913	$	6,287,305	$	3,840,930	$	3,826,658	$	11,196,904	$	22,519,051	$	1,920,061
Interest on Long-term Debt		1,039,364			1,986,017		1,044,393		1,913,020		3,429,694		1,406,769		2,261,997		3,635,239		10,915,332		720,818
Other Deductions		62,780			57,084		12,656		9,981		183,230		55,836		17,718		139,950		16,120		—
Net Margins	$	1,641,829		$	2,345,865	$	1,949,001	$	1,757,912	$	2,674,381	$	2,378,325	$	1,546,943	$	7,421,715	$	11,587,599	$	1,199,243
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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 5 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin			Jackson		Jefferson		Little Ocmulgee
2014
Operating Revenue & Patronage Capital	$	38,893,111	$	195,991,079	$	39,347,893	$	279,367,784	$	64,080,991	$	73,756,672	$	27,904,783		$	510,735,934	$	71,827,423	$	23,916,286
Depreciation and Amortization		2,306,743		12,511,775		2,852,517		15,213,655		5,144,862		4,746,875		2,784,623			29,962,072		4,607,648		1,528,241
Other Operating Expenses		34,609,054		171,655,312		35,165,880		244,762,075		55,312,102		62,772,433		21,695,835			451,354,943		62,887,394		20,595,659
Electric Operating Margin	$	1,977,314	$	11,823,992	$	1,329,496	$	19,392,054	$	3,624,027	$	6,237,364	$	3,424,325		$	29,418,919	$	4,332,381	$	1,792,386
Other Income		1,299,706		2,527,479		1,710,894		4,813,036		1,888,401		2,915,253		703,134			17,055,455		2,210,033		563,544
Gross Operating Margin	$	3,277,020	$	14,351,471	$	3,040,390	$	24,205,090	$	5,512,428	$	9,152,617	$	4,127,459		$	46,474,374	$	6,542,414	$	2,355,930
Interest on Long-term Debt		1,424,324		7,983,423		1,131,219		11,254,807		3,094,308		3,372,130		2,042,871			21,288,525		3,169,302		1,197,564
Other Deductions		—		182,156		112,254		—		219,837		5,398		76,121			7,432		52,741		—
Net Margins	$	1,852,696	$	6,185,892	$	1,796,917	$	12,950,283	$	2,198,283	$	5,775,089	$	2,008,467		$	25,178,417	$	3,320,371	$	1,158,366
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
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton			Washington				MEMBER TOTAL
2014
Operating Revenue & Patronage Capital	$	173,994,288	$	42,042,641	$	48,057,042	$	34,077,611	$	45,821,708	$	15,618,930	$	250,638,594		$	36,821,113			$	3,968,930,251
Depreciation and Amortization		8,988,948		2,334,809		2,962,791		1,918,026		3,529,861		832,828		13,023,390			2,186,210				243,055,383
Other Operating Expenses		159,262,445		36,400,584		41,596,493		28,495,165		38,023,667		13,273,205		229,975,109			32,476,457				3,486,580,890
Electric Operating Margin	$	5,742,895	$	3,307,248	$	3,497,758	$	3,664,421	$	4,268,180	$	1,512,897	$	7,640,095		$	2,158,446			$	239,293,978
Other Income		2,203,404		527,586		1,574,205		1,297,583		1,302,330		592,266		9,593,840			914,335				111,679,127
Gross Operating Margin	$	7,946,299	$	3,834,834	$	5,071,963	$	4,962,004	$	5,570,510	$	2,105,163	$	17,233,935		$	3,072,781			$	350,973,105
Interest on Long-term Debt		4,562,839		1,676,186		2,628,876		1,373,376		3,323,359		630,013		5,136,341			1,430,061				165,051,783
Other Deductions		201,720		—		10,429		76,259		16,591		21,231		200,897			38,342				2,704,185
Net Margins	$	3,181,740	$	2,158,648	$	2,432,658	$	3,512,368	$	2,230,560	$	1,453,919	$	11,896,697		$	1,604,378			$	183,217,137
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			$	3,729,216,962
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				3,263,221,043
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			$	233,174,509
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			$	320,500,628
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				7,675,633
Net Margins	$	2,504,051	$	1,694,472	$	2,133,957	$	866,876	$	1,769,665	$	954,725	$	13,332,188		$	1,713,757			$	149,758,545
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				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

Footnote:

(1)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

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 (2)		Colquitt		Coweta- Fayette		Diverse (2)
2014
ASSETS
Total Utility Plant (1)	$	103,702,328	$	191,419,986	$	132,340,029	$	244,397,261	$	208,721,343	$	91,022,394	$	843,919,715	$	253,677,771	$	312,936,348	$	194,167,829
Depreciation		30,954,887		67,483,774		37,476,955		71,965,848		52,644,082		18,357,438		254,568,792		68,121,391		98,618,901		65,459,430
Net Plant		72,747,441		123,936,212		94,863,074		172,431,413		156,077,261		72,664,956		589,350,924		185,556,380		214,317,447		128,708,399
Other Assets		36,895,799		25,153,763		24,343,139		55,683,076		52,270,618		19,181,564		286,749,924		54,110,907		86,585,569		26,723,408
Total Assets	$	109,643,240	$	149,089,975	$	119,206,213	$	228,114,489	$	208,347,879	$	91,846,520	$	876,100,847	$	239,667,287	$	300,903,016	$	155,431,807
EQUITY & LIABILITIES
Equity	$	66,992,352	$	69,421,254	$	54,942,651	$	84,459,686	$	76,993,830	$	29,022,386	$	378,571,057	$	104,427,269	$	122,649,928	$	57,861,309
Long-term Debt		34,502,373		44,742,781		45,639,555		108,424,172		112,608,767		51,879,842		424,452,744		98,327,380		150,700,430		78,143,509
Other Liabilities		8,148,515		34,925,940		18,624,007		35,230,631		18,745,282		10,944,292		73,077,046		36,912,638		27,552,658		19,426,989
Total Equity and Liabilities	$	109,643,240	$	149,089,975	$	119,206,213	$	228,114,489	$	208,347,879	$	91,846,520	$	876,100,847	$	239,667,287	$	300,903,016	$	155,431,807
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		35,879,871		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		91,781,500		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		24,092,358		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		44,414,027		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
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2014
ASSETS
Total Utility Plant (1)	$	46,243,283	$	149,097,282	$	55,065,860	$	71,172,041	$	165,697,101	$	69,054,523	$	96,571,352	$	189,465,711	$	528,800,766	$	35,038,617
Depreciation		8,655,362		33,685,800		16,545,901		18,357,361		51,192,109		20,760,254		33,713,705		40,780,506		119,028,994		9,334,015
Net Plant		37,587,921		115,411,482		38,519,959		52,814,680		114,504,992		48,294,269		62,857,647		148,685,205		409,771,772		25,704,602
Other Assets		8,216,651		29,779,138		10,999,201		19,767,938		35,439,822		21,381,056		18,128,755		55,091,341		152,539,098		10,931,736
Total Assets	$	45,804,572	$	145,190,620	$	49,519,160	$	72,582,618	$	149,944,814	$	69,675,325	$	80,986,402	$	203,776,546	$	562,310,870	$	36,636,338
EQUITY & LIABILITIES
Equity	$	17,769,105	$	73,728,365	$	23,780,520	$	24,579,941	$	52,479,923	$	34,527,891	$	20,688,251	$	87,154,089	$	214,635,760	$	14,668,822
Long-term Debt		23,995,262		45,715,118		17,774,768		38,836,756		73,745,142		24,996,892		48,175,502		72,991,885		208,358,080		15,266,775
Other Liabilities		4,040,205		25,747,137		7,963,872		9,165,921		23,719,749		10,150,542		12,122,649		43,630,572		139,317,030		6,700,741
Total Equity and Liabilities	$	45,804,572	$	145,190,620	$	49,519,160	$	72,582,618	$	149,944,814	$	69,675,325	$	80,986,402	$	203,776,546	$	562,310,870	$	36,636,338
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

Footnotes:

(1)

Including construction work in progress.

(2)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

Table 6 (continued)

	Excelsior		Flint		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee
2014
ASSETS
Total Utility Plant (1)	$	77,541,273	$	378,110,540	$	97,409,739	$	455,059,562	$	144,670,028	$	164,643,500	$	85,013,762	$	918,813,985	$	154,642,510	$	58,037,474
Depreciation		20,612,448		111,429,282		22,742,170		104,666,337		61,225,591		52,089,446		26,312,218		271,425,477		41,805,845		13,038,941
Net Plant		56,928,825		266,681,258		74,667,569		350,393,225		83,444,437		112,554,054		58,701,544		647,388,508		112,836,665		44,998,533
Other Assets		26,125,157		62,400,143		24,797,610		138,665,444		40,951,216		61,432,184		13,162,082		247,006,868		40,846,034		9,892,912
Total Assets	$	83,053,982	$	329,081,401	$	99,465,179	$	489,058,669	$	124,395,653	$	173,986,238	$	71,863,626	$	894,395,376	$	153,682,699	$	54,891,445
EQUITY & LIABILITIES
Equity	$	47,648,336	$	119,162,754	$	44,971,335	$	209,412,721	$	44,569,792	$	73,595,225	$	22,748,603	$	364,489,846	$	66,833,591	$	18,176,888
Long-term Debt		25,648,032		145,671,654		38,263,196		227,883,090		62,747,454		72,975,099		44,053,244		408,081,586		58,243,132		28,340,602
Other Liabilities		9,757,614		64,246,993		16,230,648		51,762,858		17,078,407		27,415,914		5,061,779		121,823,944		28,605,976		8,373,955
Total Equity and Liabilities	$	83,053,982	$	329,081,401	$	99,465,179	$	489,058,669	$	124,395,653	$	173,986,238	$	71,863,626	$	894,395,376	$	153,682,699	$	54,891,445
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
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington				MEMBER TOTAL
2014
ASSETS
Total Utility Plant (1)	$	263,740,894	$	76,305,285	$	110,543,526	$	68,036,779	$	112,491,167	$	27,467,785	$	396,063,905	$	79,955,467			$	7,651,058,721
Depreciation		93,823,152		22,375,890		26,343,740		20,029,231		22,675,101		9,738,278		134,798,386		27,080,405				2,199,917,443
Net Plant		169,917,742		53,929,395		84,199,786		48,007,548		89,816,066		17,729,507		261,265,519		52,875,062				5,451,141,278
Other Assets		66,099,345		18,642,953		28,448,172		20,084,015		19,220,023		16,510,526		203,757,828		22,668,387				2,090,683,401
Total Assets	$	236,017,087	$	72,572,348	$	112,647,958	$	68,091,562	$	109,036,089	$	34,240,033	$	465,023,347	$	75,543,449			$	7,541,824,679
EQUITY & LIABILITIES
Equity	$	91,467,795	$	25,598,424	$	53,459,512	$	28,637,695	$	38,912,446	$	17,474,048	$	204,832,775	$	39,190,917			$	3,120,537,092
Long-term Debt		80,162,498		33,639,834		48,542,607		35,072,798		61,057,965		12,033,940		120,940,166		29,780,149				3,252,414,779
Other Liabilities		64,386,794		13,334,090		10,645,839		4,381,069		9,065,678		4,732,045		139,250,406		6,572,383				1,168,872,808
Total Equity and Liabilities	$	236,017,087	$	72,572,348	$	112,647,958	$	68,091,562	$	109,036,089	$	34,240,033	$	465,023,347	$	75,543,449			$	7,541,824,679
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				2,070,400,602
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				5,324,112,862
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				2,071,898,774
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			$	7,396,011,635
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			$	3,017,701,906
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				1,110,656,298
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			$	7,396,011,635
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

Footnotes:

(1)

Including construction work in progress.

(2)

In 2012, Cobb owned the distribution system and served the load of Pataula EMC; therefore, Pataula's information was reported with Cobb's. However, the service territory and customers previously transferred from Pataula to Cobb were transferred to Diverse Power Corporation in 2013. Pataula's information is now reported with Diverse Power's.

QuickLinks

Exhibit 99.1

FINANCIAL AND STATISTICAL INFORMATION FOR 38 MEMBERS OF OGLETHORPE POWER CORPORATION
FINANCIAL AND STATISTICAL INFORMATION FOR THE 38 MEMBERS OF OGLETHORPE POWER CORPORATION
Table 1 SELECTED STATISTICS OF EACH MEMBER (as of December 31)
Table 1 (continued)
FINANCIAL AND STATISTICAL INFORMATION FOR THE 38 MEMBERS OF OGLETHORPE POWER CORPORATION
FINANCIAL AND STATISTICAL INFORMATION FOR THE 38 MEMBERS OF OGLETHORPE POWER CORPORATION
Table 4 ANNUAL REVENUES BY CONSUMER CLASS OF EACH MEMBER
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)

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Nuclear Fuel Disposal Cost Litigation (Details) (Nuclear Fuel Disposal Cost Settlement, January 1, 2005 through December 31, 2010, Plant Hatch and Plant Vogtle, USD $)	0 Months Ended	3 Months Ended
	Dec. 14, 2014	Mar. 31, 2015	Dec. 14, 2014
Nuclear Fuel Disposal Cost Settlement, January 1, 2005 through December 31, 2010 | Plant Hatch and Plant Vogtle
Settlement amount, entity share	$ 10,949,000
Settlement amount, all parties	36,474,000		36,474,000
Reduction of total operating expenses		7,320,000
Reduction to plant in service		$ 3,629,000

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Investments in Debt and Equity Securities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
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)	89.00%
Available-for-sale securities
Cost	$ 389,603	$ 383,001
Gross Unrealized Gains	82,819	79,517
Gross Unrealized Losses	(10,011)	(10,786)
Fair Value	462,411	451,732
Equity
Available-for-sale securities
Cost	206,199	200,892
Gross Unrealized Gains	71,575	69,536
Gross Unrealized Losses	(1,926)	(2,163)
Fair Value	275,848	268,265
Debt.
Available-for-sale securities
Cost	170,276	168,182
Gross Unrealized Gains	11,244	9,981
Gross Unrealized Losses	(8,082)	(8,619)
Fair Value	173,438	169,544
Other
Available-for-sale securities
Cost	13,128	13,927
Gross Unrealized Losses	(3)	(4)
Fair Value	$ 13,125	$ 13,923

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Fair Value (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Fair value measurement
Long-term investments	$ 87,836,000	$ 85,728,000
Interest rate options
Fair value measurement
Derivative assets	2,702,000	4,371,000
Natural gas swaps
Fair value measurement
Derivative liabilities	21,096,000	18,914,000
International equity trust
Fair value measurement
Unfunded commitments	0
Redemption notice period	3 days
Recurring basis | Total Fair Value | Interest rate options
Fair value measurement
Derivative assets	2,702,000	4,371,000
Recurring basis | Total Fair Value | Natural gas swaps
Fair value measurement
Derivative liabilities	21,096,000	18,914,000
Recurring basis | Total Fair Value | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	163,991,000	159,536,000
Recurring basis | Total Fair Value | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	74,705,000	72,474,000
Long-term investments	11,508,000	11,162,000
Recurring basis | Total Fair Value | Corporate bonds
Fair value measurement
Nuclear decommissioning trust funds	18,298,000	34,446,000
Long-term investments	6,135,000	5,445,000
Recurring basis | Total Fair Value | US Treasury and government agency securities
Fair value measurement
Nuclear decommissioning trust funds	70,197,000	68,854,000
Long-term investments	17,129,000	16,619,000
Recurring basis | Total Fair Value | Agency mortgage and asset backed securities
Fair value measurement
Nuclear decommissioning trust funds	14,957,000	16,148,000
Long-term investments	870,000	643,000
Recurring basis | Total Fair Value | Municipal Bonds
Fair value measurement
Nuclear decommissioning trust funds	19,565,000	743,000
Recurring basis | Total Fair Value | Mutual funds
Fair value measurement
Long-term investments	51,932,000	51,741,000
Recurring basis | Total Fair Value | Other
Fair value measurement
Nuclear decommissioning trust funds	12,862,000	13,803,000
Long-term investments	262,000	118,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	163,991,000	159,536,000
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	70,197,000	68,854,000
Long-term investments	17,129,000	16,619,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mutual funds
Fair value measurement
Long-term investments	51,932,000	51,741,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value measurement
Nuclear decommissioning trust funds	12,862,000	13,803,000
Long-term investments	262,000	118,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value measurement
Derivative liabilities	21,096,000	18,914,000
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	74,705,000	72,474,000
Long-term investments	11,508,000	11,162,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds
Fair value measurement
Nuclear decommissioning trust funds	18,298,000	34,446,000
Long-term investments	6,135,000	5,445,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Agency mortgage and asset backed securities
Fair value measurement
Nuclear decommissioning trust funds	14,957,000	16,148,000
Long-term investments	870,000	643,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal Bonds
Fair value measurement
Nuclear decommissioning trust funds	19,565,000	743,000
Recurring basis | Significant Unobservable Inputs (Level 3) | Interest rate options
Fair value measurement
Derivative assets	$ 2,702,000	$ 4,371,000

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Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Regulatory assets and liabilities
Total Regulatory Assets	507,496	$ 484,049
Total Regulatory Liabilities	202,232	194,073
Net Regulatory Assets	305,264	289,976
Accumulated retirement costs for other obligations
Regulatory assets and liabilities
Total Regulatory Liabilities	15,774	18,559
Deferral of effects on net margin- Hawk Road Energy Facility | Hawk Road
Regulatory assets and liabilities
Total Regulatory Liabilities	31,178	29,867
Major maintenance reserve
Regulatory assets and liabilities
Total Regulatory Liabilities	22,952	23,427
Amortization on capital leases
Regulatory assets and liabilities
Total Regulatory Liabilities	23,924	21,693
Deferred debt service adder
Regulatory assets and liabilities
Total Regulatory Liabilities	69,124	66,754
Asset retirement obligations
Regulatory assets and liabilities
Total Regulatory Liabilities	34,394	28,870
Other regulatory liabilities
Regulatory assets and liabilities
Total Regulatory Liabilities	4,886	4,903
Other regulatory liabilities | Maximum
Regulatory assets and liabilities
Amortization period	18 years
Premium and loss on reacquired debt
Regulatory assets and liabilities
Total Regulatory Assets	69,277	71,731
Premium and loss on reacquired debt | Maximum
Regulatory assets and liabilities
Amortization period	30 years
Amortization on capital leases
Regulatory assets and liabilities
Total Regulatory Assets	28,362	27,829
Outage costs
Regulatory assets and liabilities
Total Regulatory Assets	51,969	45,795
Interest rate swap termination fees
Regulatory assets and liabilities
Total Regulatory Assets	8,348	9,345
Depreciation expense
Regulatory assets and liabilities
Total Regulatory Assets	46,582	46,938
Depreciation expense | Plant Vogtle
Regulatory assets and liabilities
Operating license expected extension period for Plant Vogtle	20 years
Operating license, expected extension period, for Plant Vogtle	40 years
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units Number 3 And Number 4
Regulatory assets and liabilities
Total Regulatory Assets	33,643	32,501
Interest rate options cost
Regulatory assets and liabilities
Total Regulatory Assets	100,470	98,671
Deferral of effects on net margin - Smith Energy Facility | Smith
Regulatory assets and liabilities
Total Regulatory Assets	144,330	128,666
Other regulatory assets
Regulatory assets and liabilities
Total Regulatory Assets	24,515	$ 22,573
Other regulatory assets | Maximum
Regulatory assets and liabilities
Amortization period	35 years
Coal-fired outage costs | Minimum
Regulatory assets and liabilities
Amortization period	18 months
Coal-fired outage costs | Maximum
Regulatory assets and liabilities
Amortization period	36 months
Nuclear refueling outage costs | Minimum
Regulatory assets and liabilities
Amortization period	18 months
Nuclear refueling outage costs | Maximum
Regulatory assets and liabilities
Amortization period	24 months

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Derivative Instruments

3 Months Ended

Mar. 31, 2015

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. To hedge the risk of rising interest rates on long-term debt in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.

We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of March 31, 2015, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating 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 our natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.

At March 31, 2015 and December 31, 2014, the fair value of our natural gas contracts was a net liability of approximately $21,096,000 and $18,914,000, respectively.

As of March 31, 2015 and December 31, 2014, neither we nor any counterparties were required to post credit support or collateral under these natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements had been triggered on March 31, 2015 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit in the amount of $21,096,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of March 31, 2015 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2015	19.0
2016	11.0
2017	2.8
Total	32.8

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 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,433,078,000 have expired and as of March 31, 2015 the remaining notional amount of our outstanding swaptions was approximately $746,126,000.

The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 177 basis points above the corresponding LIBOR swap rates that were in effect as of March 31, 2015, and the weighted average fixed rate is 4.02%. Swaptions having notional amounts totaling $115,201,000 expired without value during the three months ended March 31, 2015. The remaining swaptions expire quarterly through 2017.

We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At March 31, 2015 and December 31, 2014, the fair value of these swaptions was approximately $2,702,000 and $4,371,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of March 31, 2015 and December 31, 2014, there were no collateral postings made by the counterparties, 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 $2,200,000,000 of debt that we hedged with the swaptions.

The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of March 31, 2015.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2015	$	355,424
2016		310,533
2017		80,169
Total	$	746,126

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

	Balance Sheet Location		Fair Value
			2015		2014
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options	Other deferred charges	$	2,702	$	4,371
Liabilities:
Natural gas swaps	Other current liabilities	$	12,241	$	13,418
Natural gas swaps	Other deferred credits		8,855		5,496

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

	Statement of Revenues and Expenses		Three months ended March 31,
	Location		2015			2014
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	—		$	279
Natural Gas Swaps	Fuel		(5,527	)		—
		$	(5,527	)	$	279

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

	Balance Sheet Location		2015			2014
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory asset	$	(21,096	)	$	(18,914	)
Interest rate options	Regulatory asset		(44,845	)		(49,232	)
Total not designated as hedges		$	(65,941	)	$	(68,146	)

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, 2015
Assets:
Natural gas swaps	$	(21,096	)	$	—		$	—	$	(21,096	)
Interest rate options	$	47,547		$	(44,845	)	$	—	$	2,702
December 31, 2014
Assets:
Natural gas swaps	$	(18,914	)	$	—		$	—	$	(18,914	)
Interest rate options	$	53,603		$	(49,232	)	$	—	$	4,371

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Derivative instruments (Details 2) (Interest rate options, USD $)	3 Months Ended
	Dec. 31, 2011 item	Mar. 31, 2015	Dec. 31, 2014
Derivative instruments and hedging activities
Purchased amount of derivative instrument	$ 100,000,000
Notional Dollar Amount	2,200,000,000	746,126,000
Number of nuclear units expected to be financed	2
Derivative notional amount expired		1,433,078,000
Derivative remaining notional amount		746,126,000
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)		4.02%
Notional amount of derivatives, expired without value		115,201,000
Fair value of assets		2,702,000	4,371,000
Funds posted as collateral by the counterparties		0	0
2015
Derivative instruments and hedging activities
Notional Dollar Amount		355,424,000
2016
Derivative instruments and hedging activities
Notional Dollar Amount		310,533,000
2017
Derivative instruments and hedging activities
Notional Dollar Amount		80,169,000
LIBOR
Derivative instruments and hedging activities
Variable rate basis		LIBOR
Minimum
Derivative instruments and hedging activities
Collateral thresholds range		0
Maximum
Derivative instruments and hedging activities
Collateral thresholds range		10,000,000
Average | LIBOR
Derivative instruments and hedging activities
Basis spread (as a percent)		1.77%
Department of Energy-guaranteed loan
Derivative instruments and hedging activities
Hedged amount of expected debt		2,200,000,000

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Derivative instruments (Details) (Natural gas swaps, USD $)	Mar. 31, 2015 item	Dec. 31, 2014
Gas hedges
Derivative liabilities	$ 21,096,000	$ 18,914,000
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	32,800,000
Letters of credit required to be posted with counterparties, if credit-risk-related contingent features were triggered due to credit rating being downgraded below investment grade	$ 21,096,000
2015
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	19,000,000
2016
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	11,000,000
2017
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	2,800,000

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Derivative instruments (Details 3) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Interest rate options
Assets:
Fair value of assets	$ 2,702,000	$ 4,371,000
Natural gas swaps
Liabilities:
Fair Value of liabilities	21,096,000	18,914,000
Not designated as hedges | Interest rate options
Assets:
Fair value of assets	2,702,000	4,371,000
Not designated as hedges | Natural gas swaps
Liabilities:
Fair Value of liabilities	12,241,000	13,418,000
Not designated as hedges | Natural gas swaps | Other Deferred Credits
Liabilities:
Fair Value of liabilities	$ 8,855,000	$ 5,496,000

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Derivative instruments (Details 4) (Not designated as hedges, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized gains and (losses) on derivatives	$ (65,941)		$ (68,146)
Natural gas swaps | Regulatory Asset
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized losses on derivatives	(21,096)		(18,914)
Natural gas swaps | Fuel
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Gains		279
Losses	(5,527)
Total gains (losses) on derivatives	(5,527)	279
Interest rate options | Regulatory Asset
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized losses on derivatives	$ (44,845)		$ (49,232)

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Fair Value

3 Months Ended

Mar. 31, 2015

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, 2015 and December 31, 2014.

	Fair Value Measurements at Reporting Date Using
		March 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	163,991	$	163,991	$	—	$	—
International equity trust		74,705		—		74,705		—
Corporate bonds		18,298		—		18,298		—
US Treasury and government agency securities		70,197		70,197		—		—
Agency mortgage and asset backed securities		14,957		—		14,957		—
Municipal bonds		19,565		—		19,565		—
Other		12,862		12,862		—		—
Long-term investments:
International equity trust		11,508		—		11,508		—
Corporate bonds		6,135		—		6,135		—
US Treasury and government agency securities		17,129		17,129		—		—
Agency mortgage and asset backed securities		870		—		870		—
Mutual funds		51,932		51,932		—		—
Other		262		262		—		—
Interest rate options		2,702		—		—		2,702
Natural gas swaps		21,096		—		21,096		—

	Fair Value Measurements at Reporting Date Using
		December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	159,536	$	159,536	$	—	$	—
International equity trust		72,474		—		72,474		—
Corporate bonds		34,446		—		34,446		—
US Treasury and government agency securities		68,854		68,854		—		—
Agency mortgage and asset backed securities		16,148		—		16,148		—
Municipal Bonds		743		—		743		—
Other		13,803		13,803		—		—
Long-term investments:
Corporate bonds		5,445		—		5,445		—
US Treasury and government agency securities		16,619		16,619		—		—
Agency mortgage and asset backed securities		643		—		643		—
International equity trust		11,162		—		11,162		—
Mutual funds		51,741		51,741		—		—
Other		118		118		—		—
Interest rate options		4,371		—		—		4,371
Natural gas swaps		18,914		—		18,914		—

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

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, 2015 and 2014.

		Three Months Ended March 31, 2015
		Interest rate options
		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2014	$	4,371
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(1,669	)
Balance at March 31, 2015	$	2,702

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

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

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

		2015				2014
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,344,321	$	8,713,348	$	7,256,995	$	8,460,685

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

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

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Derivative instruments (Details 5) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Natural gas swaps
Liabilities:
Gross Amounts of Recognized Assets (Liabilities)	$ (21,096)	$ (18,914)
Net Amounts of (Liabilities) Presented on the Balance Sheet	(21,096)	(18,914)
Interest rate options
Assets:
Gross Amounts of Recognized Assets (Liabilities)	47,547	53,603
Gross Amounts offset on the Balance Sheets	(44,845)	(49,232)
Net Amounts of Assets Presented on the Balance Sheet	$ 2,702	$ 4,371

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Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Electric plant:
In service	$ 8,368,040	$ 8,345,241
Less: Accumulated provision for depreciation	(3,801,533)	(3,762,690)
Total in service	4,566,507	4,582,551
Nuclear fuel, at amortized cost	365,506	369,529
Construction work in progress	2,465,420	2,374,392
Total electric plant	7,397,433	7,326,472
Investments and funds:
Nuclear decommissioning trust fund	374,575	366,004
Investment in associated companies	68,745	67,368
Long-term investments	87,836	85,728
Restricted cash and investments	118,976	118,390
Other	18,036	17,397
Total investments and funds	668,168	654,887
Current assets:
Cash and cash equivalents	271,704	237,391
Restricted short-term investments	251,725	247,057
Receivables	119,895	130,366
Inventories, at average cost	252,818	270,849
Prepayments and other current assets	42,840	12,667
Total current assets	938,982	898,330
Deferred charges:
Deferred debt expense, being amortized	98,530	97,902
Regulatory assets	507,496	484,049
Other	86,646	84,603
Total deferred charges	692,672	666,554
Total assets	9,697,255	9,546,243
Capitalization:
Patronage capital and membership fees	776,493	761,124
Accumulated other comprehensive margin	421	468
Total patronage capital and membership fees and accumulated other comprehensive margin	776,914	761,592
Long-term debt	7,196,761	7,113,000
Obligation under capital leases	100,456	100,456
Other	16,708	16,434
Total capitalization	8,090,839	7,991,482
Current liabilities:
Long-term debt and capital leases due within one year	161,502	160,754
Short-term borrowings	343,729	234,369
Accounts payable	39,071	98,337
Accrued interest	53,138	58,841
Member power bill prepayments, current	184,446	166,013
Other current liabilities	38,574	70,748
Total current liabilities	820,460	789,062
Deferred credits and other liabilities:
Gain on sale of plant, being amortized	20,306	20,676
Asset retirement obligations	438,510	432,260
Member power bill prepayments, non-current	37,240	31,941
Power sale agreement, being amortized	9,501	12,669
Regulatory liabilities	202,232	194,073
Other	78,167	74,080
Total deferred credits and other liabilities	785,956	765,699
Total equity and liabilities	$ 9,697,255	$ 9,546,243

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Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net margin	$ 15,369	$ 19,223
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	76,642	74,880
Accretion cost	6,382	6,018
Amortization of deferred gains	(447)	(447)
Allowance for equity funds used during construction	(173)	(389)
Deferred outage costs	(17,169)	(25,845)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin	(14,315)	(9,715)
Gain on sale of investments	(4,687)	(3,996)
Regulatory deferral of costs associated with nuclear decommissioning	1,222	(84)
Other	6,448	1,384
Change in operating assets and liabilities:
Receivables	10,471	(1,799)
Inventories	18,031	24,827
Prepayments and other current assets	(30,174)	1,892
Accounts payable	(39,364)	(33,330)
Accrued interest	(5,703)	(8,804)
Accrued taxes	(8,914)	(13,144)
Other current liabilities	(10,545)	(2,075)
Member power bill prepayments	23,732	12,105
Total adjustments	11,437	21,478
Net cash provided by operating activities	26,806	40,701
Cash flows from investing activities:
Property additions	(165,397)	(134,354)
Activity in nuclear decommissioning trust fund - Purchases	(111,750)	(101,894)
Activity in decommissioning trust fund - Proceeds	110,666	100,648
(Increase) decrease in restricted cash and investments	(586)	24,239
Increase in restricted cash and short-term investments	(4,668)	(16,783)
Activity in other long-term investments - Purchases	(12,045)	(12,220)
Activity in other long-term investments - Proceeds	11,214	12,413
Activity on interest rate options - Collateral returned		(46,940)
Activity on interest rate options - Collateral received		22,700
Other	(5,278)	(401)
Net cash used in investing activities	(177,844)	(152,592)
Cash flows from financing activities:
Long-term debt proceeds	113,718	734,608
Long-term debt payments	(37,319)	(295,740)
Increase (decrease) in short-term borrowings, net	109,360	(474,720)
Other	(408)	(41,957)
Net cash provided by (used in) financing activities	185,351	(77,809)
Net increase (decrease) in cash and cash equivalents	34,313	(189,700)
Cash and cash equivalents at beginning of period	237,391	408,193
Cash and cash equivalents at end of period	271,704	218,493
Cash paid for -
Interest (net of amounts capitalized)	69,258	65,816
Supplemental disclosure of non-cash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (22,510)	$ 6,463

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Contingencies and Regulatory Matters (Details) (USD $)	3 Months Ended	0 Months Ended	1 Months Ended	0 Months Ended
	Mar. 31, 2015 item	Jul. 28, 2014	Apr. 30, 2008 item MW	Aug. 20, 2014 item	May 22, 2014
Nuclear Construction
Number of electric distribution cooperative members	38
Maximum
Nuclear Construction
Period of revolving schedule to retire the patronage capital of former consumer-members		13 years
Period of revolving schedule to adopt policies to periodically retire the patronage capital of all consumer-members		13 years
Vogtle Units Number 3 And Number 4
Nuclear Construction
Number of Westinghouse AP1000 nuclear generating units			2
Nominally rated generating capacity for each unit			1,100
Costs Associated With Design Changes Delays In Project Schedule And Issuance Of Combined Construction Permits And Operating Licenses | Vogtle Units Number 3 And Number 4
Nuclear Construction
Contractor's estimated adjustment attributable to the entity	280,000,000
Patronage Capital Litigation
Nuclear Construction
Number of defendant members		3		2
Number of excluded members against whom defendant class action is certified		1
Number of electric distribution cooperative members		38
Number of former consumer members		4
Number of members in which the former consumer members filing the lawsuit belonged		4
Percentage of cooperatives total booked patronage capital		30.00%
Number of current consumer members				2
Number of plaintiffs				3
Amended counterclaim associated with design changes, delays in Project Schedule and issuance of permits and operating licenses | Vogtle Units Number 3 And Number 4
Nuclear Construction
Contractor's estimated adjustment attributable to the entity					$ 75,000,000

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Accumulated Comprehensive Margin (Deficit) (Tables)

3 Months Ended

Mar. 31, 2015

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, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)
Balance at December 31, 2014	$	468
Unrealized gain		107
(Gain) reclassified to net margin		(154	)
Balance at March 31, 2015	$	421

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Restricted Cash and Investments (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Restricted Cash and Investments.
Restricted Cash and Investments	$ 370,838,000	$ 365,585,000
Restricted Cash And Investments, Noncurrent	$ 118,976,000	$ 118,390,000
Guaranteed interest rate on deposit with Rural Utilities Service (as a percent)	5.00%	5.00%

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General (Details)	3 Months Ended
	Mar. 31, 2015 item
General
Number of electric distribution cooperative members	38

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General

3 Months Ended

Mar. 31, 2015

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, 2015 and 2014. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. 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, 2014, as filed with the SEC. The results of operations for the three-month periods ended March 31, 2015 are not necessarily indicative of results to be expected for the full year. As noted in our 2014 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the condensed balance sheets are principally from our members. (See "Notes to Financial Statements" in our 2014 Form 10-K.)

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Condensed Statements of Revenues and Expenses (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating revenues:
Sales to Members	$ 308,776	$ 334,759
Sales to non-Members	31,002	32,541
Total operating revenues	339,778	367,300
Operating expenses:
Fuel	108,409	132,276
Production	114,759	108,084
Depreciation and amortization	42,652	40,714
Purchased power	13,631	20,066
Accretion	6,382	6,018
Deferral of Hawk Road and Smith Energy Facilities effect on net margin	(14,315)	(9,715)
Total operating expenses	271,518	297,443
Operating margin	68,260	69,857
Other income:
Investment income	9,849	9,282
Other	2,859	2,377
Total other income	12,708	11,659
Interest charges:
Interest expense	87,707	81,917
Allowance for equity funds used during construction	(26,253)	(23,729)
Amortization of debt discount and expense	4,145	4,105
Net interest charges	65,599	62,293
Net margin	$ 15,369	$ 19,223

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Debt

3 Months Ended

Mar. 31, 2015

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

Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, $335,471,604 of which is designated for capitalized interest.

Advances may be requested under the Facility on a quarterly basis through December 31, 2020. At March 31, 2015, aggregate borrowings totaled $882,672,000, including capitalized interest advanced under the loan.

b)Rural Utilities Service Guaranteed Loans:

For the three month period ended March 31, 2015, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $113,718,000 for general and environmental improvements at existing plants.

c)Credit Facilities:

On March 23, 2015, we entered into a $1,210,000,000 credit agreement with a syndicate of thirteen lenders, led by the National Rural Utilities Cooperative Finance Corporation as administrative agent.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2015
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, 2015
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	2015
Document Fiscal Period Focus	Q1

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Nuclear Fuel Disposal Cost Litigation

3 Months Ended

Mar. 31, 2015

Nuclear Fuel Disposal Cost Litigation

Nuclear Fuel Disposal Cost Litigation

(L)Nuclear Fuel Disposal Cost Litigation.    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract.

On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of January 1, 2005 through December 31, 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded in our March 31, 2015 financial statements and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service.

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Condensed Statements of Comprehensive Margin (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Condensed Statements of Comprehensive Margin
Net margin	$ 15,369	$ 19,223
Other comprehensive margin:
Unrealized (loss) gain on available-for-sale securities	(47)	396
Total comprehensive margin	$ 15,322	$ 19,619

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Accumulated Comprehensive Margin (Deficit)

3 Months Ended

Mar. 31, 2015

Accumulated Comprehensive Margin (Deficit)

Accumulated Comprehensive Margin (Deficit)

(F)Accumulated Comprehensive Margin (Deficit).    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2014 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Condensed Statement of Revenues and Expenses.

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, 2013	$	(549	)
Unrealized gain		390
Loss reclassified to net margin		6
Balance at March 31, 2014	$	(153	)
Balance at December 31, 2014	$	468
Unrealized gain		107
(Gain) reclassified to net margin		(154	)
Balance at March 31, 2015	$	421

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Recently Issued or Adopted Accounting Pronouncements

3 Months Ended

Mar. 31, 2015

Recently Issued or Adopted Accounting Pronouncements

Recently Issued or Adopted Accounting Pronouncements

(E)Recently Issued or Adopted Accounting Pronouncements.    In May 2014, the Financial Accounting Standards Board issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is not permitted.

On April 1, 2015, the FASB proposed deferring the effective date by one year. Under the proposal, the standard would be effective for annual reporting periods beginning after December 15, 2017. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016.

We are currently evaluating the future impact of this standard to our consolidated financial position or results of operations.

In April 2015, the FASB issued "Interest-Imputation of Interest (Subtopic 835-30); Simplifying the Presentation of Debt Issuance Costs. The amendments in this standard require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The amendments in the standard are effective for the financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. We are currently evaluating the impact of adoption on our consolidated financial position or results of operations.

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2015

Regulatory Assets and Liabilities

Schedule of regulatory assets and liabilities

		2015		2014
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	69,277	$	71,731
Amortization on capital leases(b)		28,362		27,829
Outage costs(c)		51,969		45,795
Interest rate swap termination fees(d)		8,348		9,345
Depreciation expense(e)		46,582		46,938
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		33,643		32,501
Interest rate options cost(g)		100,470		98,671
Deferral of effects on net margin—Smith Energy Facility(h)		144,330		128,666
Other regulatory assets(m)		24,515		22,573
Total Regulatory Assets	$	507,496	$	484,049
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	15,774	$	18,559
Deferral of effects on net margin—Hawk Road Energy Facility(h)		31,178		29,867
Major maintenance reserve(j)		22,952		23,427
Amortization on capital leases(b)		23,924		21,693
Deferred debt service adder(k)		69,124		66,754
Asset retirement obligations(l)		34,394		28,870
Other regulatory liabilities(m)		4,886		4,903
Total Regulatory Liabilities	$	202,232	$	194,073
Net Regulatory Assets	$	305,264	$	289,976

(a)	Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 30 years.
(b)	Represents the difference between lease payments and the aggregate of the amortization on the capital lease assets and the interest on the capital lease obligations for rate-making purposes.
(c)	Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over an 18 to 36-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit.
(d)	Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019.
(e)	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.
(f)	Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.
(g)	Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain 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.
(h)	Effects on net margin for Smith and Hawk Road Energy Facilities are deferred until the end of 2015 and will be amortized over the remaining life of each respective plant.
(i)	Represents difference in timing of recognition of retirement costs associated with long-lived assets in which there are no legal obligations to retire for financial statement purposes and for ratemaking purposes.
(j)	Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.
(k)	Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.
(l)	Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes.
(m)	The amortization period for other regulatory assets range up to 35 years and the amortization period of other regulatory liabilities range up to 18 years.

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Fair Value (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value

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

	Fair Value Measurements at Reporting Date Using
		March 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	163,991	$	163,991	$	—	$	—
International equity trust		74,705		—		74,705		—
Corporate bonds		18,298		—		18,298		—
US Treasury and government agency securities		70,197		70,197		—		—
Agency mortgage and asset backed securities		14,957		—		14,957		—
Municipal bonds		19,565		—		19,565		—
Other		12,862		12,862		—		—
Long-term investments:
International equity trust		11,508		—		11,508		—
Corporate bonds		6,135		—		6,135		—
US Treasury and government agency securities		17,129		17,129		—		—
Agency mortgage and asset backed securities		870		—		870		—
Mutual funds		51,932		51,932		—		—
Other		262		262		—		—
Interest rate options		2,702		—		—		2,702
Natural gas swaps		21,096		—		21,096		—

	Fair Value Measurements at Reporting Date Using
		December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	159,536	$	159,536	$	—	$	—
International equity trust		72,474		—		72,474		—
Corporate bonds		34,446		—		34,446		—
US Treasury and government agency securities		68,854		68,854		—		—
Agency mortgage and asset backed securities		16,148		—		16,148		—
Municipal Bonds		743		—		743		—
Other		13,803		13,803		—		—
Long-term investments:
Corporate bonds		5,445		—		5,445		—
US Treasury and government agency securities		16,619		16,619		—		—
Agency mortgage and asset backed securities		643		—		643		—
International equity trust		11,162		—		11,162		—
Mutual funds		51,741		51,741		—		—
Other		118		118		—		—
Interest rate options		4,371		—		—		4,371
Natural gas swaps		18,914		—		18,914		—

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

		Three Months Ended March 31, 2015
		Interest rate options
		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2014	$	4,371
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(1,669	)
Balance at March 31, 2015	$	2,702

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

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, 2015 and December 31, 2014 were as follows (in thousands):

		2015				2014
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	7,344,321	$	8,713,348	$	7,256,995	$	8,460,685

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2015

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, 2015 and December 31, 2014.

		2015		2014
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	69,277	$	71,731
Amortization on capital leases(b)		28,362		27,829
Outage costs(c)		51,969		45,795
Interest rate swap termination fees(d)		8,348		9,345
Depreciation expense(e)		46,582		46,938
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		33,643		32,501
Interest rate options cost(g)		100,470		98,671
Deferral of effects on net margin—Smith Energy Facility(h)		144,330		128,666
Other regulatory assets(m)		24,515		22,573
Total Regulatory Assets	$	507,496	$	484,049
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	15,774	$	18,559
Deferral of effects on net margin—Hawk Road Energy Facility(h)		31,178		29,867
Major maintenance reserve(j)		22,952		23,427
Amortization on capital leases(b)		23,924		21,693
Deferred debt service adder(k)		69,124		66,754
Asset retirement obligations(l)		34,394		28,870
Other regulatory liabilities(m)		4,886		4,903
Total Regulatory Liabilities	$	202,232	$	194,073
Net Regulatory Assets	$	305,264	$	289,976

(a)	Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 30 years.
(b)	Represents the difference between lease payments and the aggregate of the amortization on the capital lease assets and the interest on the capital lease obligations for rate-making purposes.
(c)	Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over an 18 to 36-month period. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 to 24-month operating cycles of each unit.
(d)	Represents losses on settled interest rate swap arrangements that are being amortized through 2016 and 2019.
(e)	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.
(f)	Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.
(g)	Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain 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.
(h)	Effects on net margin for Smith and Hawk Road Energy Facilities are deferred until the end of 2015 and will be amortized over the remaining life of each respective plant.
(i)	Represents difference in timing of recognition of retirement costs associated with long-lived assets in which there are no legal obligations to retire for financial statement purposes and for ratemaking purposes.
(j)	Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.
(k)	Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.
(l)	Represents difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes.
(m)	The amortization period for other regulatory assets range up to 35 years and the amortization period of other regulatory liabilities range up to 18 years.

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Contingencies and Regulatory Matters

3 Months Ended

Mar. 31, 2015

Contingencies and Regulatory Matters

Contingencies and Regulatory Matters

(G)Contingencies and Regulatory Matters.

We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

a.    Nuclear Construction

In April 2008, Georgia Power Company, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC and CB&I Stone & Webster, Inc. (formerly known as Stone & Webster, Inc.) (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (the EPC Agreement) to design, engineer, procure, construct and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).

Under the EPC Agreement for Vogtle Units No. 3 and No. 4, 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.

In July 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the Westinghouse AP1000 Design Control Document (DCD) and 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, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In March 2015, the U.S. Court of Appeals for the District of Columbia affirmed this dismissal which means the case will be tried in the U.S. District Court for the Southern District of Georgia. The portion of the additional costs claimed by the Contractor 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 extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. The Contractor did not specify amounts relating to these new allegations in its amended counterclaim; however, the Contractor has subsequently asserted related minimum damages, based on our ownership interest, of approximately $75,000,000. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues. Litigation is ongoing 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, 2015, no material amounts have been recorded related to this claim. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.

b.    Patronage Capital Litigation

On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

We intend to defend vigorously against all claims in the above-described litigation.

c.    Environmental Matters

As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.

In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

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

Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

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Restricted cash and investments

3 Months Ended

Mar. 31, 2015

Restricted Cash and Investments.

Restricted cash and investments

(H)Restricted Cash and Investments.    Restricted cash and investments primarily consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At March 31, 2015 and December 31, 2014, we had restricted cash and investments totaling $370,838,000 and $365,585,000, respectively, of which $118,976,000 and $118,390,000, respectively, were classified as long-term.

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Member Power Bill Prepayments

3 Months Ended

Mar. 31, 2015

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 2015.

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Accumulated Comprehensive Margin (Deficit) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Accumulated Comprehensive Margin (Deficit)
Effective income tax rate (as a percent)	0.00%
Accumulated Comprehensive Margin (Defcit)
Balance at the beginning of the period	$ 468	$ (549)
Unrealized gain	107	390
(Gain) loss reclassified to net margin	(154)	6
Balance at the end of the period	$ 421	$ (153)

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Investments in Debt and Equity Securities (Tables)

3 Months Ended

Mar. 31, 2015

Investments in Debt and Equity Securities

Summary of activities for available-for-sale securities

		Gross Unrealized
		(dollars in thousands)
March 31, 2015		Cost		Gains		Losses			Fair Value
Equity	$	206,199	$	71,575	$	(1,926	)	$	275,848
Debt		170,276		11,244		(8,082	)		173,438
Other		13,128		—		(3	)		13,125
Total	$	389,603	$	82,819	$	(10,011	)	$	462,411

		Gross Unrealized
		(dollars in thousands)
December 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	200,892	$	69,536	$	(2,163	)	$	268,265
Debt		168,182		9,981		(8,619	)		169,544
Other		13,927		—		(4	)		13,923
Total	$	383,001	$	79,517	$	(10,786	)	$	451,732

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Fair Value (Details 2) (Interest rate options, USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Interest rate options
Assets (Liabilities):
Balance at the beginning of the period	$ 4,371	$ 63,471
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)	(1,669)	(32,008)
Balance at the end of the period	$ 2,702	$ 31,463

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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, 2015	Mar. 31, 2014
Increase (Decrease) in Members' Capital
Balance	$ 761,592	$ 713,940
Components of comprehensive margin:
Net margin	15,369	19,223
Unrealized (loss) gain on available-for-sale securities	(47)	396
Balance	776,914	733,559
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Balance	761,124	714,489
Components of comprehensive margin:
Net margin	15,369	19,223
Balance	776,493	733,712
Accumulated Other Comprehensive Margin (Deficit)
Increase (Decrease) in Members' Capital
Balance	468	(549)
Components of comprehensive margin:
Unrealized (loss) gain on available-for-sale securities	(47)	396
Balance	$ 421	$ (153)

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Investments in Debt and Equity Securities

3 Months Ended

Mar. 31, 2015

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 funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset. All realized and unrealized gains and losses are determined using the specific identification method. As of March 31, 2015, approximately 89% of these gross unrealized losses had been unrealized for a duration of less than one year.

The following tables summarize the activities for available-for-sale securities as of March 31, 2015 and December 31, 2014.

		Gross Unrealized
		(dollars in thousands)
March 31, 2015		Cost		Gains		Losses			Fair Value
Equity	$	206,199	$	71,575	$	(1,926	)	$	275,848
Debt		170,276		11,244		(8,082	)		173,438
Other		13,128		—		(3	)		13,125
Total	$	389,603	$	82,819	$	(10,011	)	$	462,411

		Gross Unrealized
		(dollars in thousands)
December 31, 2014		Cost		Gains		Losses			Fair Value
Equity	$	200,892	$	69,536	$	(2,163	)	$	268,265
Debt		168,182		9,981		(8,619	)		169,544
Other		13,927		—		(4	)		13,923
Total	$	383,001	$	79,517	$	(10,786	)	$	451,732

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Fair Value (Details 3) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Carrying Value
Grouping Financial Statement Captions
Long-term debt	$ 7,344,321	$ 7,256,995
Total Fair Value
Grouping Financial Statement Captions
Long-term debt	$ 8,713,348	$ 8,460,685

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Debt (Details) (USD $)	0 Months Ended
	Feb. 20, 2014	Mar. 31, 2015	Mar. 23, 2015 item
Facility
Debt
Aggregate borrowings including capitalized interest		$ 882,672,000
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 through November 20, 2019, is reflected as additional borrowings under the Facility	335,471,604
Rural Utilities Service Guaranteed Loans
Debt
Principal amount		113,718,000
Committed credit arrangements
Debt
Aggregate borrowings			$ 1,210,000,000
Number of lenders			13

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Derivative instruments (Tables)

3 Months Ended

Mar. 31, 2015

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, 2015 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2015	19.0
2016	11.0
2017	2.8
Total	32.8

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, 2015.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2015	$	355,424
2016		310,533
2017		80,169
Total	$	746,126

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

	Balance Sheet Location		Fair Value
			2015		2014
			(dollars in thousands)
Not designated as hedges:
Assets:
Interest rate options	Other deferred charges	$	2,702	$	4,371
Liabilities:
Natural gas swaps	Other current liabilities	$	12,241	$	13,418
Natural gas swaps	Other deferred credits		8,855		5,496

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

	Statement of Revenues and Expenses		Three months ended March 31,
	Location		2015			2014
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	—		$	279
Natural Gas Swaps	Fuel		(5,527	)		—
		$	(5,527	)	$	279

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

	Balance Sheet Location		2015			2014
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory asset	$	(21,096	)	$	(18,914	)
Interest rate options	Regulatory asset		(44,845	)		(49,232	)
Total not designated as hedges		$	(65,941	)	$	(68,146	)

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, 2015
Assets:
Natural gas swaps	$	(21,096	)	$	—		$	—	$	(21,096	)
Interest rate options	$	47,547		$	(44,845	)	$	—	$	2,702
December 31, 2014
Assets:
Natural gas swaps	$	(18,914	)	$	—		$	—	$	(18,914	)
Interest rate options	$	53,603		$	(49,232	)	$	—	$	4,371