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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,~~June 30, 2016
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 Noo 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.

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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED ~~MARCH 31,~~JUNE 30, 2016

		Page No.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of ~~March 31,~~June 30, 2016 and December 31, 2015	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three and Six Months ended ~~March 31,~~June 30, 2016 and 2015	3
	Unaudited Consolidated Statements of Comprehensive Margin For the Three and Six Months ended ~~March 31,~~June 30, 2016 and 2015	4
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin For the ~~Three~~Six Months ended ~~March 31,~~June 30, 2016 and 2015	5
	Unaudited Consolidated Statements of Cash Flows For the ~~Three~~Six Months ended ~~March 31,~~June 30, 2016 and 2015	6
	Notes to Unaudited Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2324
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2933
Item 4.	Controls and Procedures	2933
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	3034
Item 1A.	Risk Factors	3134
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3134
Item 3.	Defaults Upon Senior Securities	3134
Item 4.	Mine Safety Disclosures	3134
Item 5.	Other Information	3134
Item 6.	Exhibits	3134
SIGNATURES		3235

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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 "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, ~~2015.~~2015 and in this quarterly report on Form 10-Q. 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;
•: the regulation of carbon dioxide emissions such as the Clean Power Plan, or other regulatory or legislative responses to climate change initiatives or efforts to reduce other greenhouse gas emissions;
•: costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;
•: 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 may weaken certain of our financial metrics;
•: commercial banking and financial market conditions;
•: our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;
•: uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy for construction of two additional nuclear units at Plant Vogtle;
•: actions by credit rating agencies;
•: risks and regulatory requirements related to the ownership and construction of nuclear facilities;

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•: adequate funding of our nuclear decommissioning trust funds 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;
•: changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories;
•: 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;
•: 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;
•: general economic conditions;
•: weather conditions and other natural phenomena;
•: unanticipated changes in interest rates or rates of inflation;
•: significant changes in our relationship with our employees, including the availability of qualified personnel;
•: unanticipated changes in capital expenditures, operating expenses and liquidity needs;
•: significant changes in critical accounting policies material to us; and
•: hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.

iii

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
~~March 31,~~June 30, 2016 and December 31, 2015

(dollars in thousands)

2016
2015
Assets

Electric plant:

In service
$ 8,630,779 $ 8,596,148
Less: Accumulated provision for depreciation
(3,968,968 ) (3,925,838 )

4,661,811 4,670,310
Nuclear fuel, at amortized cost
387,207 373,145
Construction work in progress
2,958,677 2,868,669

8,007,695 7,912,124

Investments and funds:

Nuclear decommissioning trust fund
369,441 363,829
Investment in associated companies
73,197 72,010
Long-term investments
90,470 86,771
Restricted cash and investments
144,109 134,690
Other
19,394 19,097

696,611 676,397

Current assets:

Cash and cash equivalents
111,093 213,038
Restricted short-term investments
250,541 253,204
Receivables
126,420 130,464
Inventories, at average cost
293,999 299,252
Prepayments and other current assets
16,640 16,913

798,693 912,871

Deferred charges:

Regulatory assets
554,494 530,254
Other
22,910 28,137

577,404 558,391

$ 10,080,403 $ 10,059,783

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

~~Table of Contents~~

~~Oglethorpe Power Corporation~~
~~Consolidated Balance Sheets (Unaudited)~~
~~March 31, 2016 and December 31, 2015~~

(dollars in thousands)

2016
2015
Equity and Liabilities

Capitalization:

Patronage capital and membership fees
$ 830,063 $ 809,465
Accumulated other comprehensive margin
342 58

830,405 809,523
Long-term debt

7,403,407
7,291,154
Obligation under capital leases
96,501 96,501
Other
17,857 17,561

8,348,170 8,214,739

Current liabilities:

Long-term debt and capital leases due within one year
189,938 189,840
Short-term borrowings
303,020 261,478
Accounts payable
44,241 157,432
Accrued interest
53,302 58,830
Member power bill prepayments, current
173,004 174,743
Other current liabilities
56,566 86,746

820,071 929,069

Deferred credits and other liabilities:

Asset retirement obligations
599,631 602,230
Member power bill prepayments, non-current
39,165 44,205
Contract retainage
62,552 66,515
Regulatory liabilities
177,351 166,967
Other
33,463 36,058

912,162 915,975

$ 10,080,403 $ 10,059,783


		(dollars in thousands)
	2016			2015
Assets
Electric plant:
In service	$	8,741,230		$	8,596,148
Less: Accumulated provision for depreciation		(4,011,683	)		(3,925,838	)

		4,729,547			4,670,310
Nuclear fuel, at amortized cost		375,723			373,145
Construction work in progress		3,008,270			2,868,669

		8,113,540			7,912,124

Investments and funds:
Nuclear decommissioning trust fund		375,440			363,829
Investment in associated companies		73,545			72,010
Long-term investments		95,139			86,771
Restricted cash and investments		103,116			134,690
Other		19,696			19,097

		666,936			676,397

Current assets:
Cash and cash equivalents		347,369			213,038
Restricted short-term investments		251,864			253,204
Receivables		170,464			130,464
Inventories, at average cost		279,390			299,252
Prepayments and other current assets		17,611			16,913

		1,066,698			912,871

Deferred charges:
Regulatory assets		538,290			530,254
Other		27,868			28,137

		566,158			558,391

	$	10,413,332		$	10,059,783

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

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Oglethorpe Power Corporation
Consolidated ~~Statements of Revenues and Expenses~~Balance Sheets (Unaudited)
~~For the Three Months Ended March 31,~~June 30, 2016 and December 31, 2015

(dollars in thousands)

Three Months

2016 2015
Operating revenues:

Sales to Members
$ 348,097 $ 308,776
Sales to non-Members
64 31,002
��
Total operating revenues
348,161 339,778

Operating expenses:

Fuel
98,952 108,409
Production
103,471 114,759
Depreciation and amortization
53,486 42,652
Purchased power
13,143 13,631
Accretion
8,016 6,382
Deferral of Hawk Road and Smith Energy Facilities effect on net margin
— (14,315 )

Total operating expenses
277,068 271,518

Operating margin
71,093 68,260

Other income:

Investment income
12,323 9,849
Other
2,301 2,859

Total other income
14,624 12,708

Interest charges:

Interest expense
88,517 87,707
Allowance for debt funds used during construction
(26,380 ) (26,253 )
Amortization of debt discount and expense
2,982 4,145

Net interest charges
65,119 65,599

Net margin
$ 20,598 $ 15,369


		(dollars in thousands)
	2016		2015
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	853,340	$	809,465
Accumulated other comprehensive margin		435		58

		853,775		809,523
Long-term debt		7,865,127		7,291,154
Obligation under capital leases		94,358		96,501
Other		18,154		17,561

		8,831,414		8,214,739

Current liabilities:
Long-term debt and capital leases due within one year		191,623		189,840
Short-term borrowings		75,995		261,478
Accounts payable		71,846		157,432
Accrued interest		60,836		58,830
Member power bill prepayments, current		148,245		174,743
Other current liabilities		45,314		86,746

		593,859		929,069

Deferred credits and other liabilities:
Asset retirement obligations		688,330		602,230
Member power bill prepayments, non-current		45,827		44,205
Contract retainage		39,165		66,515
Regulatory liabilities		184,823		166,967
Other		29,914		36,058

		988,059		915,975

	$	10,413,332	$	10,059,783

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

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Oglethorpe Power Corporation
Consolidated Statements of ~~Comprehensive Margin~~Revenues and Expenses (Unaudited)
For the Three and Six Months Ended ~~March 31,~~June 30, 2016 and 2015


		(dollars in thousands)					(dollars in thousands)
	Three Months					Three Months						Six Months
	2016		2015			2016			2015			2016			2015
Operating revenues:
Sales to Members						$	379,154		$	311,148		$	727,251		$	619,924
Sales to non-Members							189			32,593			253			63,595

Total operating revenues							379,343			343,741			727,504			683,519

Operating expenses:
Fuel							126,588			115,211			225,540			223,620
Production							103,180			128,369			206,651			243,128
Depreciation and amortization							54,401			42,952			107,887			85,604
Purchased power							13,002			14,612			26,145			28,243
Accretion							8,024			6,477			16,040			12,859
Deferral of Hawk Road and Smith Energy Facilities effect on net margin							—			(27,374	)		—			(41,689	)

Total operating expenses							305,195			280,247			582,263			551,765

Operating margin							74,148			63,494			145,241			131,754

Other income:
Investment income							12,727			10,185			25,050			20,034
Other							2,427			2,441			4,728			5,300

Total other income							15,154			12,626			29,778			25,334

Interest charges:
Interest expense							91,005			88,132			179,522			175,839
Allowance for debt funds used during construction							(27,945	)		(26,699	)		(54,325	)		(52,952	)
Amortization of debt discount and expense							2,965			3,835			5,947			7,980

Net interest charges							66,025			65,268			131,144			130,867

Net margin	$	20,598	$	15,369		$	23,277		$	10,852		$	43,875		$	26,221

Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities		284		(47	)

Total comprehensive margin	$	20,882	$	15,322

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

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Oglethorpe Power Corporation
Consolidated Statements of ~~Patronage Capital and Membership Fees~~
~~and Accumulated Other~~ Comprehensive Margin (Unaudited)
For the Three and Six Months Ended ~~March 31,~~June 30, 2016 and 2015


		(dollars in thousands)								(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin			Total			Three Months					Six Months
Balance at December 31, 2014	$	761,124	$	468		$	761,592
									2016		2015			2016		2015
Net margin									$	23,277	$	10,852		$	43,875	$	26,221

Components of comprehensive margin:
Net margin		15,369		—			15,369
Unrealized loss on available-for-sale securities		—		(47	)		(47	)
Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities										93		(314	)		377		(361	)

Balance at March 31, 2015	$	776,493	$	421		$	776,914
Total comprehensive margin									$	23,370	$	10,538		$	44,252	$	25,860

Balance at December 31, 2015	$	809,465	$	58		$	809,523

Components of comprehensive margin:
Net margin		20,598		—			20,598
Unrealized gain on available-for-sale securities		—		284			284

Balance at March 31, 2016	$	830,063	$	342		$	830,405

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

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Oglethorpe Power Corporation
Consolidated Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin (Unaudited)
For the Six Months Ended June 30, 2016 and 2015

	Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin			Total

		(dollars in thousands)
Balance at December 31, 2014	$	761,124	$	468		$	761,592

Components of comprehensive margin:
Net margin		26,221		—			26,221
Unrealized loss on available-for-sale securities		—		(361	)		(361	)

Balance at June 30, 2015	$	787,345	$	107		$	787,452

Balance at December 31, 2015	$	809,465	$	58		$	809,523

Components of comprehensive margin:
Net margin		43,875		—			43,875
Unrealized gain on available-for-sale securities		—		377			377

Balance at June 30, 2016	$	853,340	$	435		$	853,775

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

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Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2016 and 2015


		(dollars in thousands)						(dollars in thousands)
	2016			2015			2016			2015
Cash flows from operating activities:
Net margin	$	20,598		$	15,369		$	43,875		$	26,221

Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		87,413			76,642			177,367			156,416
Accretion cost		8,016			6,382			16,040			12,859
Amortization of deferred gains		(447	)		(447	)		(894	)		(894	)
Allowance for equity funds used during construction		(177	)		(173	)		(352	)		(342	)
Deferred outage costs		(24,869	)		(17,169	)		(26,090	)		(18,274	)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		—			(14,315	)		—			(41,689	)
Gain on sale of investments		849			(4,687	)
Loss (gain) on sale of investments								633			(32,470	)
Regulatory deferral of costs associated with nuclear decommissioning		(5,814	)		1,222			(10,677	)		25,781
Other		(1,685	)		(1,617	)		(3,429	)		(3,312	)
Change in operating assets and liabilities:
Receivables		4,044			10,471			(37,697	)		(11,171	)
Inventories		5,253			18,031			4,386			2,857
Prepayments and other current assets		273			(30,174	)		(698	)		(10,664	)
Accounts payable		(39,787	)		(39,364	)		(73,698	)		(45,059	)
Accrued interest		(5,528	)		(5,703	)		2,006			(49	)
Accrued taxes		(13,160	)		(8,914	)		(3,597	)		820
Other current liabilities		(9,777	)		(10,545	)		(23,977	)		(8,681	)
Member power bill prepayments		(6,779	)		23,732			(24,876	)		(11,033	)

Total adjustments		(2,175	)		3,372			(5,553	)		15,095

Net cash provided by operating activities		18,423			18,741			38,322			41,316

Cash flows from investing activities:
Property additions		(259,447	)		(157,332	)		(301,545	)		(239,510	)
Activity in nuclear decommissioning trust fund—Purchases		(129,886	)		(111,750	)		(216,217	)		(281,938	)
—Proceeds		128,179			110,666			212,949			279,751
Increase in restricted cash and investments		(9,419	)		(586	)
Decrease in restricted cash and investments								31,574			41,855
Decrease (increase) in restricted short-term investments		2,663			(4,668	)		1,340			(5,524	)
Activity in other long-term investments—Purchases		(14,267	)		(12,045	)		(31,114	)		(23,746	)
—Proceeds		11,639			11,214			24,820			24,973
Other		3,147			(5,278	)		2,494			(8,450	)

Net cash used in investing activities		(267,391	)		(169,779	)		(275,699	)		(212,589	)

Cash flows from financing activities:
Long-term debt proceeds		7,998			113,718			628,358			271,892
Long-term debt payments		(36,677	)		(37,319	)		(75,537	)		(76,418	)
Increase in short-term borrowings, net		171,280			109,360
(Decrease) increase in short-term borrowings, net								(185,483	)		27,375
Other		4,422			(408	)		4,370			(2,190	)

Net cash provided by financing activities		147,023			185,351			371,708			220,659

Net (decrease) increase in cash and cash equivalents		(101,945	)		34,313
Net increase in cash and cash equivalents								134,331			49,386
Cash and cash equivalents at beginning of period		213,038			237,391			213,038			237,391

Cash and cash equivalents at end of period	$	111,093		$	271,704		$	347,369		$	286,777



Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	66,950		$	69,258		$	121,760		$	127,026
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	(10,425	)	$	—		$	70,780		$	20,711
Change in accrued property additions	$	(79,336	)	$	(22,510	)	$	(38,209	)	$	(8,454	)
Interest paid-in-kind	$	10,606		$	8,065		$	21,765		$	16,528

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

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Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements

(A): General. The consolidated 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 and six-month periods ended ~~March 31,~~June 30, 2016 and 2015. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. Certain prior year amounts have been reclassified to conform with the current year presentation.

For the ~~three month~~six-month period ended ~~March 31,~~June 30, 2015, we made an adjustment of ~~$8,065,000~~$16,528,000 in the Consolidated Statement of Cash Flows to decrease other adjustments to reconcile net margin to net cash provided by operating activities and decrease cash paid for property additions. This adjustment reflects the non-cash nature of the allowance for debt funds used during construction related to interest paid-in-kind associated with loans under our Department of Energy Loan Guarantee. The change properly reflects an immaterial adjustment to cash flows provided by operations and cash used in investing activities, and is consistent with the ~~2016 presentation.~~presentation beginning with the statement of cash flows for the year ended December 31, 2015.

These consolidated 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, 2015, as filed with the SEC. The results of operations for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 are not necessarily indicative of results to be expected for the full year. As noted in our 2015 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. (See "~~Notes~~"Notes to Consolidated Financial ~~Statements~~"Statements" in our 2015 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.

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•: 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,~~June 30, 2016 and December 31, 2015.



	Fair Value Measurements at Reporting Date Using								Fair Value Measurements at Reporting Date Using
		March 31, 2016		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		June 30, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)

		(dollars in thousands)								(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	152,412	$	152,412	$	—	$	—	$	156,154		$	156,154	$	—		$	—
International equity trust		69,040		—		69,040		—		68,115			—		68,115			—
Corporate bonds		46,223		—		46,223		—		51,058			—		51,058			—
US Treasury and government agency securities		80,644		80,644		—		—		75,784			75,784		—			—
Agency mortgage and asset backed securities		16,463		—		16,463		—		16,810			—		16,810			—
Municipal bonds		380		—		380		—		400			—		400			—
Other		4,279		4,279		—		—		7,119			7,119		—			—
Long-term investments:
International equity trust		12,904		—		12,904		—		13,892			—		13,892			—
Corporate bonds		9,516		—		9,516		—		11,625			—		11,625			—
US Treasury and government agency securities		14,692		14,692		—		—		13,367			13,367		—			—
Agency mortgage and asset backed securities		1,482		—		1,482		—		1,181			—		1,181			—
Mutual funds		51,721		51,721		—		—		54,798			54,798		—			—
Other		155		155		—		—		276			276		—			—
Interest rate options		95		—		—		95		5			—		—			5
Natural gas swaps		25,919		—		25,919		—		(2,645	)		—		(2,645	)		—

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	Fair Value Measurements at Reporting Date Using
		December 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	$	151,178	$	151,178	$	—	$	—
International equity trust		68,753		—		68,753		—
Corporate bonds		48,450		—		48,450		—
US Treasury and government agency securities		75,173		74,698		475		—
Agency mortgage and asset backed securities		15,503		—		15,503		—
Other		4,772		4,772		—		—
Long-term investments:
Corporate bonds		9,903		—		9,903		—
US Treasury and government agency securities		13,772		13,772		—		—
Agency mortgage and asset backed securities		1,121		—		1,121		—
International equity trust		12,846		—		12,846		—
Mutual funds		48,649		48,649		—		—
Other		479		479		—		—
Interest rate options		1,010		—		—		1,010
Natural gas swaps		24,995		—		24,995		—

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

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The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended ~~March 31,~~June 30, 2016 and 2015.



		Three Months Ended March 31, 2016			Three Months Ended June 30, 2016

		Interest rate options			Interest rate options

		(dollars in thousands)			(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2015	$	1,010
Balance at March 31, 2016				$	95
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(915	)		(90	)

Balance at March 31, 2016	$	95
Balance at June 30, 2016				$	5



		Three Months Ended March 31, 2015			Three Months Ended June 30, 2015

		Interest rate options			Interest rate options

		(dollars in thousands)			(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2014	$	4,371
Balance at March 31, 2015				$	2,702
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(1,669	)		2,013

Balance at March 31, 2015	$	2,702
Balance at June 30, 2015				$	4,715



		Six Months Ended June 30, 2016

		Interest rate options

		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2015	$	1,010
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(1,005	)

Balance at June 30, 2016	$	5

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		Six Months Ended June 30, 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)		344

Balance at June 30, 2015	$	4,715

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

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The estimated fair values of our long-term debt, including current maturities at ~~March 31,~~June 30, 2016 and December 31, 2015 were as follows (in thousands):



		2016				2015				2016				2015

		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,686,691	$	8,991,014	$	7,575,027	$	8,445,630	$	8,155,612	$	9,900,207	$	7,575,027	$	8,445,630

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 reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of ~~March 31,~~June 30, 2016 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 similar loans.

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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 a portion of our anticipated long-term debt to be incurred 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,~~June 30, 2016, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

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

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contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

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

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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,~~June 30, 2016 and December 31, 2015, the estimated fair value of our natural gas contracts was a net ~~liability~~asset of approximately ~~$25,919,000~~$2,645,000 and a net liability of $22,848,000, respectively.

As of ~~March 31,~~June 30, 2016 and December 31, 2015, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on ~~March 31,~~June 30, 2016 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of ~~$25,919,000~~$2,887,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of ~~March 31,~~June 30, 2016 that is expected to settle or mature each year:



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

2016	21.6	15.1
2017	18.1	19.3
2018	15.4	16.5
2019	10.0	11.4
2020	2.5	5.5

Total	67.6	67.8

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

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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 ~~$1,864,393,000~~$1,941,169,000 have expired and, as of ~~March 31,~~June 30, 2016, the remaining notional amount of our outstanding swaptions was approximately ~~$314,810,000.~~$238,034,000.

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 ~~198~~224 basis points above the corresponding LIBOR swap rates that were in effect as of ~~March 31,~~June 30, 2016, and the weighted average fixed rate is ~~3.93%~~3.88%. Swaptions having notional amounts totaling ~~$75,892,000~~$152,668,000 expired without value during the ~~three~~six months ended ~~March 31,~~June 30, 2016. The remaining swaptions expire quarterly through March 31, 2017.

We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At ~~March 31,~~June 30, 2016 and December 31, 2015, the fair value of these swaptions was approximately ~~$95,000~~$5,000 and $1,010,000, respectively. To manage our credit exposure to our

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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,~~June 30, 2016 and December 31, 2015, there were no collateral postings required of the counterparties.

We are deferring realized and unrealized gains or losses from the change in fair value of each LIBOR swaption as well as related carrying and other incidental costs in accordance with our rate-making treatment. The deferral will continue until February 2020, at which time the deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $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,~~June 30, 2016.



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

2016	$	234,641	$	157,865
2017		80,169		80,169

Total	$	314,810	$	238,034

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The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at ~~March 31,~~June 30, 2016 and December 31, 2015.



	Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value

			2016		2015			2016			2015
			(dollars in thousands)					(dollars in thousands)
Not designated as hedge:
Assets:
Interest rate options	Other deferred charges	$	95	$	1,010	Other deferred charges	$	5		$	1,010
Natural gas swaps						Other deferred charges	$	4,982		$	—
Liabilities:
Natural gas swaps	Other current liabilities	$	25,919	$	22,848	Other current liabilities	$	(2,337	)	$	22,848

The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended ~~March 31,~~June 30, 2016 and 2015.



	Statement of Revenues and Expenses		Three months ended March 31,					Statement of Revenues and Expenses		Three months ended June 30,					Six months ended June 30,
	Location		2016			2015		Location		2016			2015		2016			2015

			(dollars in thousands)							(dollars in thousands)
Not Designated as hedge:
Natural Gas Swaps	Fuel	$	11		$	—		Fuel	$	7		$	956	$	18		$	1,236
Natural Gas Swaps	Fuel		(4,228	)		(5,527	)	Fuel		(8,111	)		—		(12,339	)		—

		$	(4,217	)	$	(5,527	)		$	(8,104	)	$	956	$	(12,321	)	$	1,236

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The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at ~~March 31,~~June 30, 2016 and December 31, 2015.



	Balance Sheet Location		2016			2015		Balance Sheet Location		2016			2015

			(dollars in thousands)							(dollars in thousands)
Not designated as hedge:
Natural gas swaps								Regulatory liability	$	2,645		$	—
Natural gas swaps	Regulatory asset	$	(25,919	)	$	(22,848	)	Regulatory asset		—			(22,848	)
Interest rate options	Regulatory asset		(21,962	)		(25,915	)	Regulatory asset		(16,901	)		(25,915	)

Total not designated as hedge		$	(47,881	)	$	(48,763	)
Total unrealized gains (losses)									$	(14,256	)	$	(48,763	)

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



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

		(dollars in thousands)											(dollars in thousands)
March 31, 2016
June 30, 2016
Assets:
Natural gas swaps	$	(25,919	)	$	—		$	—	$	(25,919	)	$	2,645		$	—		$	—	$	2,645
Interest rate options	$	22,057		$	(21,962	)	$	—	$	95		$	16,906		$	(16,901	)	$	—	$	5
December 31, 2015
Assets:
Natural gas swaps	$	(22,848	)	$	—		$	—	$	(22,848	)	$	(22,848	)	$	—		$	—	$	(22,848	)
Interest rate options	$	26,925		$	(25,915	)	$	—	$	1,010		$	26,925		$	(25,915	)	$	—	$	1,010

(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,~~June 30, 2016, approximately ~~83%~~87% 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,~~June 30, 2016 and December 31, 2015.

Gross Unrealized

(dollars in thousands)
March 31, 2016 Cost Gains Losses Fair
Value

Equity $ 231,117 $ 39,324 $ (9,263 ) $ 261,178
Debt 193,012 3,174 (1,887 ) 194,299
Other 4,435 — (1 ) 4,434

Total $ 428,564 $ 42,498 $ (11,151 ) $ 459,911



		Gross Unrealized									Gross Unrealized

		(dollars in thousands)									(dollars in thousands)
December 31, 2015		Cost		Gains		Losses			Fair Value
June 30, 2016											Cost		Gains		Losses			Fair Value

Equity	$	230,123	$	37,494	$	(9,635	)	$	257,982	$	233,116	$	41,280	$	(8,644	)	$	265,752
Debt		189,700		1,158		(3,491	)		187,367		193,497		5,209		(1,273	)		197,433
Other		5,255		—		(4	)		5,251		7,395		—		(1	)		7,394

Total	$	425,078	$	38,652	$	(13,130	)	$	450,600	$	434,008	$	46,489	$	(9,918	)	$	470,579

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		Gross Unrealized

		(dollars in thousands)
December 31, 2015		Cost		Gains		Losses			Fair Value

Equity	$	230,123	$	37,494	$	(9,635	)	$	257,982
Debt		189,700		1,158		(3,491	)		187,367
Other		5,255		—		(4	)		5,251

Total	$	425,078	$	38,652	$	(13,130	)	$	450,600

(E): Recently Issued or Adopted Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (FASB) 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. In March 2016, the FASB issued an amendment to the new revenue standard, which provides guidance on assessing whether an entity is a principal or an agent in a revenue transaction. The conclusion determines whether an entity reports revenue on a gross or net basis. The amendment focuses on who controls the good or service in an arrangement before it is transferred to a customer and further clarifies the unit of account and indicators of when an entity is the principal. In April 2016, the FASB further amended the new revenue standard by clarifying: (i) how an entity should evaluate the nature of its promise in granting a license of intellectual property, which will determine whether it recognizes revenue over time or at a point in time, and (ii) when a promised good or service is separately identifiable (i.e., distinct within the context of the contract) and allowing entities to disregard items that are immaterial in the context of a contract. In May 2016, the FASB further amended the new revenue standard on transition, collectability, noncash consideration and the presentation of sales and other similar taxes.

In August 2015, the FASB issued an update to Topic 606 deferring the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits 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 on our consolidated financial statements.

In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of ~~Inventory."~~Inventory". Under the new inventory standard, inventories are required to be measured at the lower of cost and net realizable value, the latter representing the estimated selling price in the ordinary course of business, reduced by costs of completion, disposal, and transportation. Under current guidance, inventories are required to be measured at the lower of cost or market, but depending upon specific circumstances, market could be replacement cost, net realizable value, or net realizable value reduced by a normal profit margin. The amendments do not apply to inventory measured using the last-in, first-out or the retail inventory method. The amendments apply to all other inventory, which includes inventory that is measured using first-in, first out or average cost, the method used to measure all of our inventories. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. ~~We are currently evaluating this standard but do not expect~~As permitted, on April 1, 2016, we early adopted these amendments and applied their provisions prospectively.

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The adoption of ~~the standard to~~this amendment did not have a material impact on our consolidated financial statements.

In November 2015, the FASB issued "Income Taxes (Topic 740): Balance Sheet Classification of Deferred ~~Taxes."~~Taxes". The amendments in this standard simplifies the presentation of deferred income taxes by eliminating the separate classification of deferred income tax assets and liabilities into current and noncurrent amounts in the statement of financial position. The amendments in the update require that all deferred tax assets and liabilities be classified as noncurrent in the consolidated balance sheet. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2016, and interim periods therein. Early adoption is permitted as of the beginning of an interim or annual reporting period. We are currently

~~Table~~ evaluating the future impact of ~~Contents~~

~~evaluating~~ this standard but do not expect adoption of the standard to have a material impact on our consolidated financial statements.

In January 2016, the FASB issued "Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities". The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative-effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. We are currently evaluating the future impact of this standard on our consolidated financial statements.

In February 2016, the FASB issued "Leases (Topic 842)"." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospectively approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements.

In June 2016, the FASB issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments". The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements.

(F): Accumulated Comprehensive Margin. The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin. There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2015 Form 10-K. Amounts reclassified to net margin in the table below are reflected in "Other income" on our unaudited Consolidated Statements of Revenues and Expenses.

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



		Accumulated Other Comprehensive Margin Three Months Ended			Accumulated Other Comprehensive Margin Three Months Ended June 30, 2015

		(dollars in thousands)			(dollars in thousands)
		Available-for-sale Securities			Available-for-sale Securities

Balance at December 31, 2014	$	468
Balance at March 31, 2015				$	421
Unrealized gain		107			(161	)
(Gain) reclassified to net margin		(154	)		(153	)

Balance at March 31, 2015	$	421
Balance at June 30, 2015				$	107

Balance at December 31, 2015	$	58
Unrealized gain		294
(Gain) reclassified to net margin		(10	)

Balance at March 30, 2016	$	342


		Three Months Ended June 30, 2016

		(dollars in thousands)
		Available-for-sale Securities

Balance at March 31, 2016	$	342
Unrealized gain		143
(Gain) reclassified to net margin		(50	)

Balance at June 30, 2016	$	435


		Six Months Ended June 30, 2015

		(dollars in thousands)
		Available-for-sale Securities

Balance at December 31, 2014	$	468
Unrealized loss		(54	)
(Gain) reclassified to net margin		(307	)

Balance at June 30, 2015	$	107


		Six Months Ended June 30, 2016

		(dollars in thousands)
		Available-for-sale Securities

Balance at December 31, 2015	$	58
Unrealized gain		437
(Gain) reclassified to net margin		(60	)

Balance at June 30, 2016	$	435

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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 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle, Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%, representing 660 megawatts of total capacity.

On December 31, 2015, Westinghouse and the Co-owners entered into a settlement agreement to resolve certain disputes between the Co-owners and the Contractor under the EPC Agreement which were dismissed with prejudice on January 5, 2016. Future claims by the Contractor or Georgia Power, on behalf of the Co-owners, could arise throughout construction. These claims may be resolved through formal and informal dispute resolution procedures under the EPC Agreement and, under the resolution procedures, may be resolved through litigation after the completion of nuclear fuel load for both units.

For additional information about the Vogtle construction project, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our 2015 Form ~~10-K.~~10-K and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Vogtle Units No. 3 and No. 4."

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b. Patronage Capital Litigation

On May 31, 2016, plaintiffs for both of the cases described under Note G of Notes to Unaudited Consolidated Financial Statements in our Form 10-Q for the quarterly period ended March ~~13, 2014, a lawsuit was filed in~~31, 2016 appealed 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.

In May 2015, the Superior Court judge appointed a special master to oversee all pre-trial issues relating to these cases, including motions to dismiss that we and the other defendants filed in connection with each lawsuit. In September, the special master issued proposed orders to the judgeCourt's decision to grant our and the other defendants' motions to dismiss both ~~patronage capital~~of those lawsuits on all ~~counts. On May 2, 2016,~~counts to the ~~Superior~~Georgia Court ~~judge adopted~~of Appeals. For additional information about the ~~special master's proposed orders and granted~~Patronage Capital Litigation, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA—Notes to Consolidated Financial Statements" in our ~~and the other defendants' motions to dismiss both of these lawsuits on all counts. The Court's decision remains subject to appeal.~~

~~Table of Contents~~2015 Form 10-K.

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

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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,~~June 30, 2016 and December 31, 2015, we had restricted cash and investments totaling ~~$394,717,000~~$355,031,000 and $387,961,000, respectively, of which ~~$144,109,000~~$103,116,000 and $134,690,000, 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.

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The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of ~~March 31,~~June 30, 2016 and December 31, 2015.



		2016		2015		2016		2015
		(dollars in thousands)				(dollars in thousands)

Regulatory Assets:
Premium and loss on reacquired debt^(a)	$	60,147	$	61,916	$	58,459	$	61,916
Amortization on capital leases^(b)		30,759		30,253		31,264		30,253
Outage costs^(c)		56,327		42,027		46,896		42,027
Interest rate swap termination fees^(d)		4,909		5,355		4,463		5,355
Depreciation expense^(e)		45,159		45,514		44,803		45,514
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs^(f)		38,899		37,646		40,303		37,646
Interest rate options cost^(g)		103,713		102,554		105,011		102,554
Deferral of effects on net margin—Smith Energy Facility^(h)		176,857		178,343		175,371		178,343
Other regulatory assets^(m)		37,724		26,646		31,720		26,646

Total Regulatory Assets	$	554,494	$	530,254	$	538,290	$	530,254
Regulatory Liabilities:
Accumulated retirement costs for other obligations⁽ⁱ⁾	$	10,728	$	8,910	$	12,553	$	8,910
Deferral of effects on net margin—Hawk Road Energy Facility^(h)		20,622		20,775		20,469		20,775
Major maintenance reserve^(j)		24,872		22,422		26,354		22,422
Amortization on capital leases^(b)		25,647		26,502		24,793		26,502
Deferred debt service adder^(k)		78,767		76,334		81,206		76,334
Asset retirement obligations^(l)		12,917		8,316		13,303		8,316
Other regulatory liabilities^(m)		3,798		3,708		6,145		3,708

Total Regulatory Liabilities	$	177,351	$	166,967	$	184,823	$	166,967

Net Regulatory Assets	$	377,143	$	363,287	$	353,467	$	363,287

^(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 28 years.
^(b): Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation.
^(c): Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired maintenance outage costs are amortized on a straight-line basis to expense over a 24-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.~~2018.
^(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 unrealized and realized change in fair value 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 were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.
⁽ⁱ⁾: Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.
^(j): Represents collections for future major maintenance expenses; 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 34 years and the amortization period of other regulatory liabilities range up to 11 years.

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(J): Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through July 2021, with the majority of the balance scheduled to be credited by the end of 2016.

(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 $3,057,069,461 of which $335,471,604 is designated for capitalized interest.

Advances may be requested under the Facility on a quarterly basis through December 31, ~~2020.~~2020 and are secured under our first mortgage indenture. On June 8, 2016, we received a $300,000,000 advance under the Facility. At ~~March 31,~~June 30, 2016, aggregate borrowings totaled ~~$1,191,234,000,~~$1,502,393,000, including capitalized interest.

b): Rural Utilities Service Guaranteed Loans:

For the ~~three month~~six-month period ended ~~March 31,~~June 30, 2016 we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling ~~$7,998,000~~$82,432,000 for general and environmental improvements at existing plants.

On ~~April~~July 28, 2016, we received an additional ~~$74,435,000~~$4,581,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants.

These advances are secured under our first mortgage indenture.

c): Bond Issuance:

On April 21, 2016, we issued $250,000,000 of 4.25% first mortgage bonds, Series 2016A primarily for the purpose of providing long-term financing for expenditures related to Vogtle Units No. 3 and No. 4 and the Smith Energy Facility. In conjunction with the issuance of the bonds, we repaid $129,737,500 of outstanding commercial paper, which was classified as long-term debt at March 31, 2016. The bonds are secured under our first mortgage indenture.

(L): Asset Retirement Obligations. Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs

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for an asset's future retirement and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to ash ponds, gypsum, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.

On April 17, 2015 the Environmental Protection Agency (EPA) published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Based on additional assessments of the impact of the final CCR rule and refinement of cost estimates in 2016, we revised the forecasted cash flows for our existing coal ash related asset retirement obligations, and as a result, increased the obligations and corresponding assets in electric plant in service by approximately $70,000,000. The liabilities are estimates based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The increase is primarily related to closure cost estimates which are based on advanced engineering methods to close the ash ponds in place. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule on our estimates and assumptions. For information regarding the impact of the final CCR rule on asset retirement obligations, see "Item 8—FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA—Notes to Consolidated Financial Statements" in our 2015 Form 10-K.

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, 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~~Six Months Ended ~~March 31,~~June 30, 2016 and 2015

Net Margin

Our net margin for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 ~~was $20.6~~were $23.3 million and $43.9 million compared to ~~$15.4~~$10.8 million and $26.2 million for the same ~~period~~periods of 2015. Through ~~March 31,~~June 30, 2016, we collected approximately ~~40%~~87% of our targeted net margin of ~~$51.0~~$50.6 million for the year ending December 31, 2016. ~~This is~~These collections are 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 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" ofin our 2015 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 operation and maintenance expense.

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The components of member revenues for the three-month and six-month periods ended ~~March 31,~~June 30, 2016 and 2015 were as follows:



		Three Months Ended March 31,			2016 vs. 2015 % Change		Three Months Ended June 30,			2016 vs. 2015 % Change			Six Months Ended June 30,			2016 vs. 2015 % Change

		(dollars in thousands)					(dollars in thousands)				��		(dollars in thousands)
		2016		2015			2016		2015				2016		2015

Capacity revenues	$	224,924	$	195,328	15.2%	$	228,449	$	194,824	17.3%		$	453,373	$	390,152	16.2%
Energy revenues		123,173		113,448	8.6%		150,705		116,324	29.6%			273,878		229,772	19.2%

Total	$	348,097	$	308,776	12.7%	$	379,154	$	311,148	21.9%		$	727,251	$	619,924	17.3%



MWh Sales to members		5,380,861		4,567,689	17.8%		6,549,671		4,752,295	37.8%			11,930,532		9,319,984	28.0%
Cents/kWh		6.47		6.76	(4.3%)		5.79		6.55	(11.6%)			6.10		6.65	(8.4%)

The increase in member capacity sales was primarily a result of the recovery of fixed costs at the Smith and Hawk Road Energy Facilities which began in 2016. Prior to 2016 our members generally did not require the energy generation from Smith and Hawk Road and the effects ~~on net margin~~ of the costs and revenues of these plants on net margin were deferred.

The increase in energy revenues from members for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods in 2015 was primarily due to an increase in generation for member sales as a result of Smith and Hawk Road becoming available to the members in 2016. ~~Partially offsetting the effects~~Our members' ability to schedule these additional natural-gas fired facilities, which currently provide an economical source of ~~the~~energy due to low natural gas prices, significantly increased ~~generation was~~our megawatt-hour sales to our members and allowed us to provide a ~~decrease~~larger percentage of our members' load requirements to date in ~~fuel costs. Primarily as~~2016. As a result, ~~of the decrease in fuel costs,~~ average energy revenue per kilowatt-hour from sales to members decreased ~~7.8%~~6.0% and 6.9% for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016, respectively, as compared to the same ~~period~~periods of 2015. For a discussion of fuel costs, see "—Operating Expenses."

Sales to Non-members. Prior to 2016, sales to non-members primarily consisted of capacity and energy sales at Smith. Non-member sales decreased nearly 100% for both the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods of 2015 as Smith became available for scheduling by our members. We do not anticipate any significant non-member sales for the remainder of 2016.

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Operating Expenses

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



		Cost						Generation					Cents per kWh					Cost				Generation			Cents per kWh

		(dollars in thousands)						(MWh)										(dollars in thousands)				(MWh)
	Three Months Ended March 31,				2016 vs.		Three Months Ended March 31,			2016 vs.		Three Months Ended March 31,			2016 vs.			Three Months Ended June 30,			2016 vs.	Three Months Ended June 30,		2016 vs.	Three Months Ended June 30,		2016 vs.

Fuel Source		2016		2015	2015 % Change			2016	2015	2015 % Change			2016	2015	2015 % Change			2016		2015	2015 % Change	2016	2015	2015 % Change	2016	2015	2015 % Change

Coal	$	32,293	$	42,485	(24.0%	)		1,105,030	1,405,651	(21.4%	)		2.92	3.02	(3.3%	)	$	33,191	$	39,317	(15.6%)	1,136,430	1,403,234	(19.0%)	2.92	2.80	4.2%
Nuclear⁽¹⁾		18,805		13,007	44.6%			2,317,510	2,377,764	(2.5%	)		0.81	0.55	48.3%			21,031		22,469	(6.4%)	2,596,627	2,667,554	(2.7%)	0.81	0.84	(3.8%)
Gas:
Combined Cycle		41,495		47,315	(12.3%	)		1,966,483	1,582,967	24.2%			2.11	2.99	(29.4%	)		50,560		42,300	19.5%	2,395,362	1,583,860	51.2%	2.11	2.67	(21.0%)
Combustion Turbine		6,359		5,602	13.5%			159,478	46,157	245.5%			3.99	12.14	(67.1%	)		21,806		11,125	96.0%	638,007	244,634	160.8%	3.42	4.55	(24.8%)

	$	98,952	$	108,409	(8.7%	)		5,548,501	5,412,539	2.5%			1.78	2.00	(11.0%	)	$	126,588	$	115,211	9.9%	6,766,426	5,899,282	14.7%	1.87	1.95	(4.2%)


		Cost				Generation			Cents per kWh

		(dollars in thousands)				(MWh)
		Six Months Ended June 30,			2016 vs.	Six Months Ended June 30,		2016 vs.	Six Months Ended June 30,		2016 vs.

Fuel Source		2016		2015	2015 % Change	2016	2015	2015 % Change	2016	2015	2015 % Change

Coal	$	65,484	$	81,802	(19.9%)	2,241,460	2,808,885	(20.2%)	2.92	2.91	0.3%
Nuclear⁽¹⁾		39,835		35,476	12.3%	4,914,137	5,045,318	(2.6%)	0.81	0.70	15.3%
Gas:
Combined Cycle		92,051		89,617	2.7%	4,361,845	3,166,827	37.7%	2.11	2.83	(25.4%)
Combustion Turbine		28,170		16,725	68.4%	797,485	290,791	174.2%	3.53	5.75	(38.6%)

	$	225,540	$	223,620	0.9%	12,314,927	11,311,821	8.9%	1.83	1.98	(7.4%)

⁽¹⁾: The 2015 nuclear fuel cost amount includes a $7.1 million credit recorded in the first quarter of 2015 for nuclear fuel storage costs recovered as a result of litigation related to responsibility for nuclear disposal costs. The exclusion of the credit would have resulted in total nuclear fuel costs of ~~$20.1~~$42.5 million in 2015, and the 2016 versus ~~2015 %~~2015% change would have been a decrease of ~~6.3%~~6.4%. Nuclear cost per kWh would have been 0.84 cents per kWh and the 2016 versus 2015% change would have been a decrease of 3.9%.

~~The decrease in total~~Total fuel costs increased for the three-month and six-month periods ended June 30, 2016 as compared to the same periods of 2015 primarily due to increased generation at our natural gas-fired facilities. See "—Operating Revenues." An increase in nuclear fuel burn expense for the six-month period ended ~~March 31,~~June 30, 2016 compared to the same period of 2015 ~~was primarily due to lower natural gas prices and a shift in the generation mix from the coal-fired units~~also contributed to the ~~relatively more economical natural gas-fired combined cycle units. Slightly offsetting the decrease was an~~ increase in ~~nuclear~~total fuel ~~burn~~ costs. During the first quarter of 2015 we recognized 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. Somewhat offsetting the effect of increased generation on the three-month and six-month total fuel costs was a decrease in the average cost per kilowatt-hour of generation largely a result of a shift in the generation mix from the coal-fired units to the relatively more economical natural gas-fired units.

Production costs decreased ~~9.8%~~19.6% and 15.0% for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 as compared to the same ~~period~~periods of 2015. Costs incurred during the first ~~quarter~~half of 2015 were somewhat higher as a result of planned major maintenance work at ~~Smith.~~Smith and Hawk Road.

Depreciation and amortization expense increased ~~$10.8 million~~26.7% and 26.0% for the three-month ~~period~~and six-month periods ended ~~March 31,~~June 30, 2016 compared to the same ~~period~~periods of 2015. The increase was primarily due to the January 1, 2016 adoption of revised depreciation rates for our co-owned coal-fired and nuclear facilities which average 2.55% and 1.89%, respectively. We anticipate the effect of the revised rates will increase depreciation expense for the year by approximately $24.0 million. The increases in the

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depreciation rates were largely due to capital additions for environmental controls and costs associated with interim retirements. The increase in depreciation and amortization expense was also due in part to the 2015 completion of the amortization of a deferred liability associated with the Hawk Road ~~acquisition.~~acquisition as well as in increase in depreciation associated with certain asset retirement obligations.

Financial Condition

Balance Sheet Analysis as of ~~March 31,~~June 30, 2016

Assets

Cash used for property additions for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2016 totaled ~~$259.4~~$301.5 million. Of this amount, approximately ~~$180.4~~$267.7 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 ~~$19.3~~and $29.3 million for nuclear fuel ~~purchases and the remaining expenditures were for normal additions and replacements to existing generation facilities.~~purchases.

Restricted cash and investments 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.

~~Table~~Receivables increased $40.0 million for the six-month period ended June 30, 2016 primarily as a result of ~~Contents~~amounts billed or billable to the members due to higher energy costs during the period, which were a result of increased generation.

Equity and Liabilities

Long-term debt increased $573.4 million due to the issuance of 2016A First Mortgage Bonds, Department of Energy loan guarantee advances and Rural Utilities Service-guaranteed loan advances during the six-month period ended June 30, 2016 for the purpose of providing long-term financing for the Vogtle construction project and other general and environmental expenditures. For additional information on these borrowings, see Note K of Notes to Unaudited Consolidated Financial Statements.

Short-term borrowings, ~~increased $41.5 million during the three-month period ended March 31, 2016 to~~which provide interim financing for Vogtle Units No. 3 and No. 4 construction ~~costs.~~costs, decreased $185.5 million during the six-month period ended June 30, 2016. Total borrowings atand repayments during the ~~end of the quarter~~period were ~~$432.8~~$114.8 million ~~of which $129.7~~and $300.3 million, ~~was~~respectively. The repayments were refinanced with long-term debt through a portion of the ~~issuance of~~ first mortgage bonds issued in April 2016 and ~~classified as long-term debt as~~under the Department of ~~March 31, 2016.~~Energy guaranteed-loan. See Note K of Notes to Unaudited Consolidated Financial Statements for information regarding the debt ~~issuance of first mortgage bonds and commercial paper repayment.~~issuances.

Accounts payable decreased ~~$113.2~~$85.6 million for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2016 primarily as a result of a ~~$96.3~~$93.1 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 $9.2 million in credits applied to our members' bills in the first quarter of 2016, for a board approved reduction in 2015 revenue requirements as a result of margin collections in excess of our 2015 target. Partially offsetting the decrease was an increase in payables related to natural gas purchases.

Other current liabilities decreased ~~$30.2~~$41.4 million for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2016 primarily due to a decrease in estimates for unrecorded liabilities, a decrease in the unrealized losses associated with natural gas hedges and the payment of certain property taxes.

Asset retirement obligations increased $86.1 million during the six-month period ended June 30, 2016 primarily due to changes in cash flow estimates associated with future coal ash pond related decommissioning costs and partially due to increases in the current year's accreted value of all of our

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asset retirement obligations. See Note L of Notes to Unaudited Consolidated Financial Statements for information regarding the impact of the final CCR rule on asset retirement obligations.

In connection with the Vogtle Units No. 3 and No. 4 construction project, we are accruing long-term contract retainage amounts for substantial and mechanical completion milestones. For the six-month period ended June 30, 2016 there was a $27.4 million decrease in the long-term contract retainage amounts as a result of modifications to the construction contract. For information regarding the Vogtle construction project, see Note G of Notes to Unaudited Consolidated Financial Statements.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4.

~~We, along with~~For additional information on Vogtle Units No. 3 and No. 4, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Vogtle Units No. 3 and No. 4" in our 2015 Form 10-K.

In 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, ~~are participating in~~Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the ~~construction of~~Co-owners) and Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 ~~nuclear generating units~~technology and related facilities at Plant Vogtle, ~~each with a nominally rated generating capacity of approximately 1,100 megawatts.~~Units No. 3 and No. 4. Our ownership interest and proportionate share of the cost to construct these units is 30%.

Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75 million. Each Co-owner is severally, not jointly, liable to the Contractor for its proportionate share, based on ownership interest, of all amounts owed under the EPC Agreement. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.

On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Co. N.V. (the Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name to WECTEC Global Project Services Inc. (WECTEC). In connection with the Acquisition, Westinghouse engaged Fluor Enterprises, Inc., ~~representing 660 megawatts~~a subsidiary of ~~total capacity.~~Fluor Corporation, as a new construction subcontractor.

The current estimated in-service dates are June 30, 2019 for Unit No. 3 and June 30, 2020 for Unit No. 4. Our project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, is $5.0 billion. Included in the project budget is our share of owner-related costs, including property taxes, oversight costs, compliance costs and other operational readiness costs, as well as financing costs, totaling approximately $20 million per month, on average, through the estimated in-service dates. As of ~~March 31,~~June 30, 2016, our total investment in the additional Vogtle units was $3.1 billion. For information regarding the financing of Vogtle Units No. 3 and No. 4, ~~was $3.0 billion.~~see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION—Financial Condition—Financing Activities—Department of Energy-Guaranteed Loan" and "—Capital Requirements—Capital Expenditures" and Note 7(a) of Notes to Consolidated Financial Statements in our 2015 Form 10-K.

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Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses and acceptance criteria by the Nuclear Regulatory Commission may arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners, the Contractor, or both.

~~For~~In connection with Georgia Power's participation in the development and construction of the additional ~~information about~~Vogtle Units and its certification of Georgia Power's costs to construct the additional Vogtle Units, the Georgia Public Service Commission engaged an independent construction monitor to evaluate and report on the progress of the Vogtle project. In June 2016, in connection with the 14^th Vogtle Construction Monitoring report, the independent monitor provided testimony stating that Georgia Power had not demonstrated to the Georgia Public Service Commission Staff that the current estimated in-service dates for Vogtle Units No. 3 and No. 4 have a reasonable chance of being met. He also expressed his opinion that there exists a strong likelihood of further delayed operation dates for both Units. We have been advised by Georgia Power, as agent for the Co-owners, that it disagrees with these opinions and believes that the current estimated in-service dates for Vogtle Units No. 3 and No. 4 are challenging but remain achievable.

As construction ~~project, see~~continues, the risk remains that challenges with the Contractor's performance, including additional challenges in labor productivity and its fabrication, assembly, delivery, and installation of the plant equipment, the shield building and structural modules, could further impact the estimated in-service dates and cost and the Contractor must improve its schedule performance in order to mitigate this risk. As discussed under "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~~"1A—RISK FACTORS" in our 2015 Form ~~10-K. Also see Note G~~10-K, other issues could arise and may further impact the project schedule and cost. The ultimate outcome of ~~Notes to Unaudited Consolidated Financial Statements.~~these matters cannot be determined at this time.

Environmental Regulations

Existing federal and state laws and regulations regarding environmental matters continue to affect operations at our facilities. Following are some substantial developments relating to environmental regulations and litigation that have occurred since the filing of our ~~2015 10-K~~Form 10-Q for the quarterly period ended March 31, 2016 that may impact the operation of our facilities.

On ~~April 25,~~June 30, 2016, the ~~U.S. Environmental Protection Agency (EPA) signed~~EPA proposed the design details for a ~~rule proposing revisions~~Clean Energy Incentive Program (CEIP), a voluntary program that states can adopt to incentivize early emission reduction projects under the Clean Power Plan (CPP). Under the CEIP, states can distribute allowances (for mass-based plans) or emission rate credits (ERCs) (for rate-based plans) to eligible clean energy projects that generate savings in 2020 and 2021. Such projects would include demand-side energy efficiency and solar projects implemented to serve low-income communities, and zero-emitting renewable energy projects using wind, solar, geothermal or hydropower generation in all communities. EPA would award matching allowances (or ERCs), from a national pool of 300 million short tons of CO₂ emissions (or 375 million ERCs) to state-approved projects, which in turn could then sell or transfer the allowances (or ERCs) to electric generating units subject to CPP CO₂ emission limits. The national pool would be allocated to each CEIP-participating state, based on its emissions reductions requirements from 2012 levels relative to the regional haze program, describing actions the states must take when submitting regional haze state implementation plans and progress reports for the period 2019 - 2028. The purpose of the program is to protect visibility in designated sensitive federal areas such as national parks, like the nearby Great Smokey Mountains National Park, and certain wilderness areas (including the Cohutta, Okefenokee and Wolf Island areas in Georgia). Potentially affected entities include states, Federal Land Managers and owners and/or operators of sources that emit visibility-impairing substances including fossil fuel-fired power plants. The proposed revisions would make several technical and administrative changes to the program, including a one-time adjustment to the due date for the next state implementation plans (from July 21, 2018 to July 31, 2021).other CEIP-participating states. We cannot determine the outcome of this proposal on our operations, if any, the effect of ~~any plan~~the program should Georgia ~~may develop and submit~~choose to participate in

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~~response to EPA's rule when finalized, the result of EPA review and approval of any Georgia submission~~ it, or the outcome of any litigation that could be brought challenging the CEIP if finalized.

On April 17, 2015, EPA published a final coal combustion residuals (CCR) rule, in which it decided to regulate CCRs from electric utilities as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act. The final rule, which became effective in October 2015, contains

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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. On November 3, 2015, the EPA also published a final rule to revise the effluent limitations guidelines that apply to certain wastewater discharges from fossil fuel-fired steam electric power plants (including our co-owned Plants Wansley and Scherer). Subsequently, in May and July of 2016, and in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division (EPD) proposed to add specific provisions for CCR wastes to its existing solid waste management rules. EPD's rules would contain the requirements in EPA's CCR Rule but would add further requirements for CCR wastes in Georgia. Such requirements would be administered in a state permit system, with permits to be issued and enforced by EPD. Citizen groups would retain the authority to enforce federal CCR requirements. The proposed EPD regulations are expected to be finalized in October 2016 and are not anticipated to have a material impact on our compliance obligations under the federal CCR rule.

In September 2015, Georgia Power announced that it is preparing a schedule to close existing ash ponds at all of its Georgia coal-fired facilities, including at our co-owned Plants Scherer and Wansley. On June 13, 2016, Georgia Power further announced that it will cease sending CCR to all of its ash ponds in Georgia within three years. It also announced that it will close the ash ponds in place using advanced engineering methods at Plants Wansley and Scherer, among other locations. Our current estimated expenditures for the settlement of related asset retirement obligations are approximately $172 million for the closure and post-closure of existing coal ash ponds. See Note L of Notes to Unaudited Consolidated Financial Statements. Preliminary estimates suggest that our capital expenditures to comply with the CCR rule and effluent limitations guidelines will be approximately $170 million for conversion to dry ash handling, landfill construction and wastewater treatment. More definitive cost estimates will be developed as the process of rule evaluation, compliance approach and design and construction implementation proceeds. The ultimate impacts associated with the federal and state CCR rules and the federal effluent limitations guidelines cannot be determined with certainty at this time.

On June 12, 2015, EPA published a rule in the Federal Register requiring certain states to revise the provisions of their State Implementation Plans (SIPs) relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). EPA is requiring revision to the SSM-related SIPs for 36 states, including Georgia, by November 22, 2016. In response to EPA's rule, in July 2016 EPD proposed to amend its state SSM rules and related SIP provisions accordingly. Litigation challenging EPA's SSM rule continues in the U.S. Court of Appeals for the District of Columbia Circuit. We cannot determine the outcome of EPD's proposed SSM rule on our operations, the outcome of any litigation on EPA's SSM rule, or any litigation that could be brought challenging EPD's SSM rule (and related SIP provisions) once finalized.

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 2015 Form 10-K.

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Liquidity

At ~~March 31,~~June 30, 2016, we had ~~$1.0~~$1.63 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$111~~$347 million in cash and cash equivalents and ~~$925 million~~$1.28 billion of unused and available committed credit arrangements.

At ~~March 31,~~June 30, 2016, we had ~~in excess of $1.6~~$1.61 billion of committed credit arrangements in place, the details of which are reflected in the table below:

Committed Credit Facilities

Authorized
Amount

Available
March 31,
2016

Expiration Date

Authorized
Amount

Available
June 30, 2016

Expiration Date

(dollars in millions)

Unsecured Facilities:

Syndicated Line of Credit led by CFC

1,210

⁽¹⁾

641

⁽²⁾

March 2020

1,210

⁽¹⁾

998

⁽²⁾

March 2020

CFC Line of Credit⁽³⁾

110

December 2018

110

December 2018

JPMorgan Chase Line of Credit

150

⁽⁴⁾

November 2016

150

⁽⁴⁾

November 2016

Secured Facilities:

CFC Term Loan⁽³⁾

250

December 2018

250

December 2018

⁽¹⁾: The amount of this facility that can be used to support commercial paper is limited to $1.0 billion.
⁽²⁾: Of the portion of this facility that was unavailable at ~~March 31,~~June 30, 2016, ~~$433~~$76 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,~~June 30, 2016, $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, 2016, we were~~We are currently 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~~long-term 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.~~quarterly. Between our credit arrangements and projected cash on hand, we believe we have sufficient liquidity to cover our normal operations and to provide interim financing for the ~~interim financings described above.~~Vogtle units under construction.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. Our commercial paper program is currently sized at $1.0 billion.

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $509 million remained available at ~~March 31,~~June 30, 2016. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw

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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,~~June 30, 2016, the required minimum level was $675 million and our actual patronage capital was ~~$830~~$853 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~~

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$12.0 billion and $4.0 billion, respectively. At ~~March 31,~~June 30, 2016, we had ~~$7.8~~$8.2 billion of secured indebtedness and ~~$433~~$76 million of unsecured indebtedness outstanding.

We plan to renew the $150 million line of credit with JPMorgan Chase Bank, N.A. before it expires on November 15, 2016.

At ~~March 31,~~June 30, 2016, we had ~~$395~~$355 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,~~June 30, 2016—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture. At ~~March 31,~~June 30, 2016, we had ~~$7.7~~$8.2 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 2015 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans. At ~~March 31,~~June 30, 2016 we had ~~three~~two approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These ~~three~~two loans totaled ~~$561~~$358 million with ~~$178~~$95 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of ~~March 31,~~June 30, 2016, we had $2.6 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 $3.057 billion 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,~~June 30, 2016, our total investment in Vogtle Units No. 3 and No. 4 was ~~$3.0~~$3.1 billion and we have incurred ~~$2.6~~$2.9 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 ~~$1.2~~$1.5 billion, 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 eligible project costs after they are incurred. As of ~~March 31,~~June 30, 2016, we have the capacity to fund an additional ~~$758~~$509 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 of Notes to Unaudited Consolidated Financial Statements.

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 2015 Form 10-K.

Bond Financing. On April 21, 2016, we issued $250 million of Series 2016A first mortgage bonds to provide long-term financing for expenditures related to the Vogtle construction project and the Smith

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Energy Facility. The bonds are secured under our first mortgage indenture. See Note K of Notes to Unaudited Consolidated Financial Statements for additional information regarding ~~the~~this bond issuance.

Newly Adopted or Issued Accounting Standards

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

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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 2015 Form 10-K.

Item 4. Controls and Procedures

As of ~~March 31,~~June 30, 2016, 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,~~June 30, 2016 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Patronage Capital Litigation

On May 31, 2016, plaintiffs for both of the cases described under "Part II—Item 1. Legal Proceedings—Patronage Capital Litigation" in our Form 10-Q for the quarterly period ended March ~~13, 2014, a lawsuit was filed in~~31, 2016 appealed the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2015 Form 10-K. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

~~Table~~counts to the Georgia Court of ~~Contents~~

On May 2, 2016, the Superior Court judge adopted the special master's proposed orders and granted our and the other defendants' motions to dismiss both of these lawsuits on all counts. The Court's decision remains subject to appeal.Appeals.

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

Item 1A. Risk Factors

There have been no material changes from the risks disclosed in "Item 1A—RISK FACTORS" of our 2015 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~~10.1⁽¹⁾		Amendment No. 8, dated as of April 20, 2016, to the Engineering, Procurement and Construction Agreement, dated as of April 8, 2008, between Georgia Power, for itself and as agent for Oglethorpe, Municipal Electric Authority of Georgia, and Dalton Utilities, as owners, and a consortium consisting of Westinghouse and Stone & Webster, as contractor, for Units 3 & 4 at the Vogtle Electric Generating Plant Site. (Incorporated by reference to Exhibit 10(c)(3) of Georgia Power Company's Form 10-Q for the quarterly period ended June 30, 2016, filed with the SEC on August 8, 2016)
	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 2013-2015).~~
	101		XBRL Interactive Data File.

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

Table of Contents

SIGNATURES

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


		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: ~~May 12,~~August 15, 2016	By:	/s/ Michael L. Smith
		Michael L. Smith President and Chief Executive Officer
Date: ~~May 12,~~August 15, 2016		/s/ Elizabeth B. Higgins
		Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)