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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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    No o

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

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

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

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

(This page has been left blank intentionally)

OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2016

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three and Nine Months ended September 30, 2016 and 2015	3
	Unaudited Consolidated Statements of Comprehensive Margin For the Three and Nine Months ended September 30, 2016 and 2015	4
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin For the Nine Months ended September 30, 2016 and 2015	5
	Unaudited Consolidated Statements of Cash Flows For the Nine Months ended September 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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	33
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	35
Item 6.	Exhibits	35
SIGNATURES		36

i

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 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;

ii

•

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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

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

		(dollars in thousands)
	2016			2015
Assets
Electric plant:
In service	$	8,752,591		$	8,596,148
Less: Accumulated provision for depreciation		(4,069,257	)		(3,925,838	)
		4,683,334			4,670,310
Nuclear fuel, at amortized cost		366,698			373,145
Construction work in progress		3,126,508			2,868,669
		8,176,540			7,912,124
Investments and funds:
Nuclear decommissioning trust fund		386,205			363,829
Investment in associated companies		72,163			72,010
Long-term investments		99,701			86,771
Restricted cash and investments		201,511			134,690
Other		20,002			19,097
		779,582			676,397
Current assets:
Cash and cash equivalents		362,708			213,038
Restricted short-term investments		249,685			253,204
Receivables		173,782			130,464
Inventories, at average cost		253,526			299,252
Prepayments and other current assets		18,852			16,913
		1,058,553			912,871
Deferred charges:
Regulatory assets		542,057			530,254
Other		25,031			28,137
		567,088			558,391
	$	10,581,763		$	10,059,783

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

1

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

		(dollars in thousands)
	2016		2015
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	871,970	$	809,465
Accumulated other comprehensive margin		416		58
		872,386		809,523
Long-term debt		7,885,428		7,291,154
Obligation under capital lease		94,358		96,501
Other		18,459		17,561
		8,870,631		8,214,739
Current liabilities:
Long-term debt and capital lease due within one year		153,274		189,840
Short-term borrowings		156,253		261,478
Accounts payable		69,613		157,432
Accrued interest		57,864		58,830
Member power bill prepayments, current		168,705		174,743
Other current liabilities		58,613		86,746
		664,322		929,069
Deferred credits and other liabilities:
Asset retirement obligations		698,240		602,230
Member power bill prepayments, non-current		83,052		44,205
Contract retainage		39,551		66,515
Regulatory liabilities		193,156		166,967
Other		32,811		36,058
		1,046,810		915,975
	$	10,581,763	$	10,059,783

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

2

Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three and Nine Months Ended September 30, 2016 and 2015

		(dollars in thousands)
	Three Months						Nine Months
	2016			2015			2016			2015
Operating revenues:
Sales to Members	$	430,883		$	318,123		$	1,158,134		$	938,047
Sales to non-Members		130			50,541			383			114,136
Total operating revenues		431,013			368,664			1,158,517			1,052,183
Operating expenses:
Fuel		178,516			142,142			404,056			365,762
Production		105,681			94,504			312,332			337,632
Depreciation and amortization		54,719			42,484			162,606			128,088
Purchased power		13,109			13,737			39,254			41,980
Accretion		8,059			6,676			24,099			19,535
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		—			(166	)		—			(41,855	)
Total operating expenses		360,084			299,377			942,347			851,142
Operating margin		70,929			69,287			216,170			201,041
Other income:
Investment income		12,578			9,816			37,628			29,850
Other		1,531			2,227			6,259			7,527
Total other income		14,109			12,043			43,887			37,377
Interest charges:
Interest expense		93,544			89,322			273,066			265,161
Allowance for debt funds used during construction		(30,135	)		(27,739	)		(84,460	)		(80,691	)
Amortization of debt discount and expense		2,999			3,839			8,946			11,819
Net interest charges		66,408			65,422			197,552			196,289
Net margin	$	18,630		$	15,908		$	62,505		$	42,129

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

3

Oglethorpe Power Corporation
Consolidated Statements of Comprehensive Margin (Unaudited)
For the Three and Nine Months Ended September 30, 2016 and 2015

		(dollars in thousands)
	Three Months						Nine Months
	2016			2015			2016		2015
Net margin	$	18,630		$	15,908		$	62,505	$	42,129
Other comprehensive margin:
Unrealized (loss) gain on available-for-sale securities		(19	)		(95	)		358		(267	)
Total comprehensive margin	$	18,611		$	15,813		$	62,863	$	41,862

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

4

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

		(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin			Total
Balance at December 31, 2014	$	761,124	$	468		$	761,592
Components of comprehensive margin:
Net margin		42,129		—			42,129
Unrealized loss on available-for-sale securities		—		(267	)		(267	)
Balance at September 30, 2015	$	803,253	$	201		$	803,454
Balance at December 31, 2015	$	809,465	$	58		$	809,523
Components of comprehensive margin:
Net margin		62,505		—			62,505
Unrealized gain on available-for-sale securities		—		358			358
Balance at September 30, 2016	$	871,970	$	416		$	872,386

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

5

Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30, 2016 and 2015

		(dollars in thousands)
	2016			2015
Cash flows from operating activities:
Net margin	$	62,505		$	42,129
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		268,674			234,362
Accretion cost		24,099			19,535
Amortization of deferred gains		(1,341	)		(1,341	)
Allowance for equity funds used during construction		(567	)		(506	)
Deferred outage costs		(29,464	)		(25,060	)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin		—			(41,855	)
Gain on sale of investments		(653	)		(34,121	)
Regulatory deferral of costs associated with nuclear decommissioning		(14,522	)		24,339
Other		(4,424	)		(5,076	)
Change in operating assets and liabilities:
Receivables		(41,015	)		(4,786	)
Inventories		30,251			(19,942	)
Prepayments and other current assets		(1,305	)		(4,650	)
Accounts payable		(87,056	)		(45,068	)
Accrued interest		(966	)		(5,774	)
Accrued taxes		5,348			10,099
Other current liabilities		(20,604	)		(9,006	)
Member power bill prepayments		32,809			27,672
Total adjustments		159,264			118,822
Net cash provided by operating activities		221,769			160,951
Cash flows from investing activities:
Property additions		(421,384	)		(335,217	)
Activity in nuclear decommissioning trust fund—Purchases		(307,222	)		(463,544	)
—Proceeds		302,308			460,171
Increase in restricted cash and investments		(66,821	)		(23,230	)
Decrease (increase) in restricted short-term investments		3,519			(5,893	)
Activity in other long-term investments—Purchases		(44,457	)		(48,461	)
—Proceeds		35,278			49,075
Other		2,401			(6,239	)
Net cash used in investing activities		(496,378	)		(373,338	)
Cash flows from financing activities:
Long-term debt proceeds		634,279			289,910
Long-term debt payments		(113,328	)		(124,138	)
(Decrease) increase in short-term borrowings, net		(105,225	)		90,132
Other		8,553			2,628
Net cash provided by financing activities		424,279			258,532
Net increase in cash and cash equivalents		149,670			46,145
Cash and cash equivalents at beginning of period		213,038			237,391
Cash and cash equivalents at end of period	$	362,708		$	283,536
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	185,484		$	186,651
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	72,097		$	17,390
Change in accrued property additions	$	(24,451	)	$	8,984
Interest paid-in-kind	$	34,587		$	26,116

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

6

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 nine-month periods ended September 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 nine-month period ended September 30, 2015, we made an adjustment of $26,116,000 to the Consolidated Statement of Cash Flows decreasing other adjustments to reconcile net margin to net cash provided by operating activities and decreasing 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 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 and nine-month periods ended September 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 to Consolidated Financial 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.

7

•

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 September 30, 2016 and December 31, 2015.

	Fair Value Measurements at Reporting Date Using
		September 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)
Nuclear decommissioning trust funds:
Domestic equity	$	163,202	$	163,202	$	—	$	—
International equity trust		70,475		—		70,475		—
Corporate bonds		48,943		—		48,943		—
US Treasury and government agency securities		72,798		72,798		—		—
Agency mortgage and asset backed securities		22,395		—		22,395		—
Municipal bonds		404		—		404		—
Other		7,988		7,988		—		—
Long-term investments:
International equity trust		15,573		—		15,573		—
Corporate bonds		11,395		—		11,395		—
US Treasury and government agency securities		13,037		13,037		—		—
Agency mortgage and asset backed securities		1,825		—		1,825		—
Mutual funds		57,462		57,462		—		—
Other		409		409		—		—
Interest rate options		—		—		—		—
Natural gas swaps		2,823		—		2,823		—

8

	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.

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

		Three Months Ended September 30, 2016
		Interest rate options
		(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2016	$	5
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(5	)
Balance at September 30, 2016	$	—

9

		Three Months Ended September 30, 2015
		Interest rate options
		(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2015	$	4,715
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(3,213	)
Balance at September 30, 2015	$	1,502

		Nine Months Ended September 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)		(1,010	)
Balance at September 30, 2016	$	—

		Nine Months Ended September 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)		(2,869	)
Balance at September 30, 2015	$	1,502

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

10

information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note C.

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

		2016				2015
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	8,136,564	$	9,752,299	$	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 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 September 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.

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 September 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.

11

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge and interest rate option counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

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

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

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

At September 30, 2016 and December 31, 2015, the estimated fair value of our natural gas contracts was a net liability of approximately $2,823,000 and $22,848,000, respectively.

As of September 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 September 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 $3,204,000 with our counterparties.

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

Year	Natural Gas Swaps (MMBTUs) (in millions)
2016	3.8
2017	20.2
2018	16.6
2019	11.4
2020	9.0
2021	2.5
Total	63.5

12

Interest rate options.    We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased seventeen LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, fifteen swaptions having a notional amount of approximately $2,019,368,000 have expired and, as of September 30, 2016, the notional amount of our remaining two outstanding swaptions was approximately $159,835,000.

The LIBOR swaptions are 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 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 cash settlement value would be zero if the swaption is out-of-the-money (that is, if the specified fixed rate is at or above then-current swap rates) on the expiration date. One of our two swaptions expires on December 30, 2016, and has a fixed rate of 3.845%, and the second swaption expires on March 31, 2017, and has a fixed rate of 3.8775%. The swaptions are both significantly out-of-the-money with fixed rates of 219 and 223 basis points, respectively, above the corresponding LIBOR swap rates that were in effect as of September 30, 2016. Swaptions having notional amounts totaling $230,867,000 expired without value during the nine months ended September 30, 2016.

We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At September 30, 2016 and December 31, 2015, the fair value of these swaptions was approximately $500 and $1,010,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of September 30, 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.

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The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of September 30, 2016.

Year		LIBOR Swaption Notional Dollar Amount (in thousands)
2016	$	79,666
2017		80,169
Total	$	159,835

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

	Balance Sheet Location		Fair Value
			2016		2015
			(dollars in thousands)
Not designated as hedge:
Assets:
Interest rate options	Other deferred charges	$	—	$	1,010
Natural gas swaps	Other current assets	$	633	$	—
Natural gas swaps	Other deferred charges	$	1,142	$	—
Liabilities:
Natural gas swaps	Other current liabilities	$	909	$	22,848
Natural gas swaps	Other deferred credits	$	3,689	$	—

The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and nine months ended September 30, 2016 and 2015.

	Statement of Revenues and Expenses		Three months ended September 30,						Nine months ended September 30,
	Location		2016			2015			2016			2015
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	2,039		$	24		$	2,057		$	205
Natural Gas Swaps	Fuel		(5,923	)		(5,970	)		(18,262	)		(14,744	)
		$	(3,884	)	$	(5,946	)	$	(16,205	)	$	(14,539	)

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

	Balance Sheet Location		2016			2015
			(dollars in thousands)
Not designated as hedge:
Natural gas swaps	Regulatory liability	$	381		$	—
Natural gas swaps	Regulatory asset		(3,204	)		(22,848	)
Interest rate options	Regulatory asset		(11,433	)		(25,915	)
Total not designated as hedge		$	(14,256	)	$	(48,763	)

The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements. There were no obligations to return cash collateral as of September 30, 2016 or December 31, 2015.

		Gross Amounts of Recognized Assets (Liabilities)			Gross Amounts offset on the Balance Sheet			Net Amounts of Assets Presented on the Balance Sheet
		(dollars in thousands)
September 30, 2016
Assets:
Natural gas swaps	$	(2,823	)	$	—		$	(2,823	)
Interest rate options	$	11,433		$	(11,433	)	$	—
December 31, 2015
Assets:
Natural gas swaps	$	(22,848	)	$	—		$	(22,848	)
Interest rate options	$	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 September 30, 2016, approximately 88% of these gross unrealized losses had been unrealized for a duration of less than one year.

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The following tables summarize the activities for available-for-sale securities as of September 30, 2016 and December 31, 2015.

		Gross Unrealized
		(dollars in thousands)
September 30, 2016		Cost		Gains		Losses			Fair Value
Equity	$	235,579	$	48,658	$	(6,159	)	$	278,078
Debt		195,849		4,529		(947	)		199,431
Other		8,398		—		(1	)		8,397
Total	$	439,826	$	53,187	$	(7,107	)	$	485,906

		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.

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In July 2015, the FASB issued "Inventory (Topic 330): Simplifying the Measurement of 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. As permitted, on April 1, 2016, we early adopted these amendments and applied their provisions prospectively. The adoption of 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." 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 evaluating the future impact of 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

17

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.

In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. 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 September 30, 2015
		(dollars in thousands)
		Available-for-sale Securities
Balance at June 30, 2015	$	107
Unrealized gain		125
(Gain) reclassified to net margin		(31	)
Balance at September 30, 2015	$	201

		Three Months Ended September 30, 2016
		(dollars in thousands)
		Available-for-sale Securities
Balance at June 30, 2016	$	435
Unrealized gain		50
(Gain) reclassified to net margin		(69	)
Balance at September 30, 2016	$	416

		Nine Months Ended September 30, 2015
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2014	$	468
Unrealized loss		(83	)
(Gain) reclassified to net margin		(184	)
Balance at September 30, 2015	$	201

		Nine Months Ended September 30, 2016
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2015	$	58
Unrealized gain		486
(Gain) reclassified to net margin		(128	)
Balance at September 30, 2016	$	416

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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.    Vogtle Units No. 3 and No. 4 Construction Litigation

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 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."

b.    Patronage Capital Litigation

There have been no material changes to this litigation from the disclosure included under Note G of Notes to Unaudited Consolidated Financial Statements in our Form 10-Q for the quarterly period ended June 30, 2016. For additional information regarding this litigation, see Note G of Notes to Unaudited Consolidated Financial Statements in our Form 10-Q for the quarterly period ended March 31, 2016.

c.    Environmental Matters

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

In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain

20

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 September 30, 2016 and December 31, 2015, we had restricted cash and investments totaling $451,247,000 and $387,961,000, respectively, of which $201,511,000 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 September 30, 2016 and December 31, 2015.

		2016		2015
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	56,772	$	61,916
Amortization on capital leases(b)		31,769		30,253
Outage costs(c)		39,589		42,027
Interest rate swap termination fees(d)		4,017		5,355
Depreciation expense(e)		44,447		45,514
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		41,871		37,646
Interest rate options cost(g)		106,220		102,554
Deferral of effects on net margin—Smith Energy Facility(h)		173,885		178,343
Other regulatory assets(m)		43,487		26,646
Total Regulatory Assets	$	542,057	$	530,254
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	12,925	$	8,910
Deferral of effects on net margin—Hawk Road Energy Facility(h)		20,316		20,775
Major maintenance reserve(j)		29,450		22,422
Amortization on capital leases(b)		23,939		26,502
Deferred debt service adder(k)		83,644		76,334
Asset retirement obligations(l)		19,106		8,316
Other regulatory liabilities(m)		3,776		3,708
Total Regulatory Liabilities	$	193,156	$	166,967
Net Regulatory Assets	$	348,901	$	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 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 the end of 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 change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project.

^(h)

Effects on net margin for Smith and Hawk Road Energy Facilities were deferred until 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 costs; revenues are recognized as major maintenance costs are incurred.

^(k)

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

^(l)

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

^(m)

The amortization period for other regulatory assets range up to 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 2017.

(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 and are secured under our first mortgage indenture. On June 8, 2016, we received a $300,000,000 advance under the Facility. At September 30, 2016, aggregate borrowings totaled $1,515,215,000, including capitalized interest.

b)

Rural Utilities Service Guaranteed Loans:

For the nine-month period ended September 30, 2016, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $88,354,000 for general and environmental improvements at existing plants.

On October 27, 2016, we received an additional $6,105,000 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.

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d)

Credit Facilities:

On October 6, 2016, we extended our $150,000,000 unsecured JPMorgan Chase Line of Credit through October 2018. At September 30, 2016, there was approximately $34,000,000 available for borrowings under the arrangement, as letters of credit of approximately $114,000,000 and $2,000,000 had been issued to support certain variable rate demand bonds and to post collateral to third parties, respectively. In connection with this extension, $37,352,000 of the variable rate demand bonds supported by this facility, which was previously classified as a current obligation, has been classified as long-term debt as of September 30, 2016 in accordance with the applicable accounting guidance.

(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 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 Nine Months Ended September 30, 2016 and 2015

Net Margin

Our net margins for the three-month and nine-month periods ended September 30, 2016 were $18.6 million and $62.5 million compared to $15.9 million and $42.1 million for the same periods of 2015. Through September 30, 2016, we collected approximately 124% of our targeted net margin of $50.5 million for the year ending December 31, 2016. These collections are typical as our capacity revenues are generally 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" in 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 nine-month periods ended September 30, 2016 and 2015 were as follows:

		Three Months Ended September 30,			2016 vs. 2015 % Change		Nine Months Ended September 30,			2016 vs. 2015 % Change
		(dollars in thousands)					(dollars in thousands)
		2016		2015			2016		2015
Capacity revenues	$	228,011	$	187,259	21.8%	$	681,384	$	577,411	18.0%
Energy revenues		202,872		130,864	55.0%		476,750		360,636	32.2%
Total	$	430,883	$	318,123	35.4%	$	1,158,134	$	938,047	23.5%
MWh Sales to members		7,956,412		5,168,226	53.9%		19,886,944		14,488,210	37.3%
Cents/kWh		5.42		6.16	(12.0%)		5.82		6.47	(10.1%)

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 of the costs and revenues of these plants on net margin were deferred.

The increase in energy revenues from members for the three-month and nine-month periods ended September 30, 2016 compared to the same 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. Our members' ability to schedule these additional natural-gas fired facilities, which currently provide an economical source of energy due to low natural gas prices, significantly increased our megawatt-hour sales to our members and allowed us to provide a larger percentage of our members' load requirements to date in 2016. The average energy revenue per kilowatt-hour from sales to members were relatively unchanged for the three-month period and decreased 3.7% for the nine-month period ended September 30, 2016, respectively, as compared to the same 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 100% for both the three-month and nine-month periods ended September 30, 2016 compared to the same 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
		(dollars in thousands)				(MWh)
		Three Months Ended September 30,			2016 vs.	Three Months Ended September 30,		2016 vs.	Three Months Ended September 30,		2016 vs.
Fuel Source		2016		2015	2015 % Change	2016	2015	2015 % Change	2016	2015	2015 % Change
Coal	$	49,478	$	40,144	23.3%	1,704,203	1,518,856	12.2%	2.90	2.64	9.8%
Nuclear(1)		21,950		21,992	(0.2%)	2,691,129	2,585,844	4.1%	0.82	0.85	(4.1%)
Gas:
Combined Cycle		73,223		62,348	17.4%	2,976,562	2,432,151	22.4%	2.46	2.56	(4.0%)
Combustion Turbine		33,865		17,658	91.8%	846,699	396,581	113.5%	4.00	4.45	(10.2%)
	$	178,516	$	142,142	25.6%	8,218,593	6,933,432	18.5%	2.17	2.05	6.0%

		Cost				Generation			Cents per kWh
		(dollars in thousands)				(MWh)
		Nine Months Ended September 30,			2016 vs.	Nine Months Ended September 30,		2016 vs.	Nine Months Ended September 30,		2016 vs.
Fuel Source		2016		2015	2015 % Change	2016	2015	2015 % Change	2016	2015	2015 % Change
Coal	$	114,961	$	121,946	(5.7%)	3,945,663	4,327,741	(8.8%)	2.91	2.82	3.4%
Nuclear(1)		61,786		57,469	7.5%	7,605,266	7,631,162	(0.3%)	0.81	0.75	7.9%
Gas:
Combined Cycle		165,272		151,959	8.8%	7,338,407	5,598,978	31.1%	2.25	2.71	(17.0%)
Combustion Turbine		62,037		34,388	80.4%	1,644,184	687,372	139.2%	3.77	5.00	(24.6%)
	$	404,056	$	365,762	10.5%	20,533,520	18,245,253	12.5%	1.97	2.00	(1.8%)

⁽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 spent nuclear fuel disposal costs. The exclusion of the credit would have resulted in total nuclear fuel costs of $64.5 million in 2015, and the 2016 versus 2015% change would have been a decrease of 4.3%. Nuclear cost per kWh would have been 0.85 cents per kWh and the 2016 versus 2015% change would have been a decrease of 3.9%.

Total fuel costs increased for the three-month and nine-month periods ended September 30, 2016 as compared to the same periods of 2015 primarily due to increased generation at our natural gas-fired facilities. See "—Operating Revenues." The increase for the three-month period ended September 30, 2016 compared to the same period of 2015 was also partially due to increased generation at our relatively more expensive coal-fired facilities, which resulted in a 6.0% increase in the average cost per kilowatt-hour of generation. An increase in nuclear fuel burn expense for the nine-month period ended September 30, 2016 compared to the same period of 2015 also contributed to the increase in total fuel costs for the period. 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 nine-month total fuel costs was a decrease in the average cost per kilowatt-hour of generation largely as 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 increased 11.8% for the three-month period ended September 30, 2016 from the same period of 2015, primarily as a result of major maintenance work at certain of our natural gas-fired plants. For the nine-month period ended September 30, 2016, production costs decreased 7.5% from the same period of 2015 due to somewhat higher planned major maintenance work at Smith and Hawk Road in the first half of 2015.

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Depreciation and amortization expense increased 28.8% and 26.9% for the three-month and nine-month periods ended September 30, 2016 compared to the same 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 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 as well as an increase in depreciation associated with certain asset retirement obligations.

Financial Condition

Balance Sheet Analysis as of September 30, 2016

Assets

Cash used for property additions for the nine-month period ended September 30, 2016 totaled $421.4 million. Of this amount, approximately $246.6 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $46.2 million for nuclear fuel purchases and the remaining expenditures were for normal additions and replacements to our existing generation facilities.

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.

Receivables increased $43.3 million for the nine-month period ended September 30, 2016 primarily as a result of amounts billed or billable to the members due to higher energy costs during the period, which were a result of increased generation.

Inventories decreased $45.7 million for the nine-month period ended September 30, 2016 primarily due to a decline in inventory purchases at our coal-fired plants.

Equity and Liabilities

Long-term debt increased $594.3 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 nine-month period ended September 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.

Long-term debt and capital leases due within one year decreased $37.3 million due to the reclassification of certain variable rate demand bond debt to long-term debt as a result of the extension of the underlying credit facility that supports the bonds. For additional information regarding the credit facility, see Note K of Notes to Unaudited Consolidated Financial Statements.

Short-term borrowings, which provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, decreased $105.2 million during the nine-month period ended September 30, 2016. Total borrowings and repayments during the period were $324.5 million and $429.7 million, respectively. The repayments were refinanced with long-term debt through a portion of the first mortgage bonds issued in April 2016 and under the Department of Energy guaranteed-loan. See Note K of Notes to Unaudited Consolidated Financial Statements for information regarding the debt issuances.

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Accounts payable decreased $87.8 million for the nine-month period ended September 30, 2016 primarily as a result of a $93.1 million decrease in the payable to Georgia Power Company 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. Offsetting the decrease was an increase in payables related to natural gas purchases.

Asset retirement obligations increased $96.0 million during the nine-month period ended September 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 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.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4.

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 and "Item 2—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" in our June 30, 2016 Form 10-Q.

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%.

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., a subsidiary of Fluor Corporation, as a new construction subcontractor.

Our project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, is $5.0 billion. As of September 30, 2016, our total investment in the additional Vogtle units was $3.2 billion. For information regarding the financing of Vogtle Units No. 3 and No. 4,

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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.

Although the Contractor's performance has improved, certain near-term milestones have recently been missed, particularly in regard to Unit No. 3. Due to the Contractor's inability to meet these milestones, the risk of Unit No. 3 not being operational by the current estimated in-service date of June 2019 has increased and a several month delay is likely. The Contractor's progress on Unit No. 4 indicates that the current estimated in-service date of June 2020 for Unit No. 4 remains achievable, but risks remain. We expect the Contractor to employ mitigation efforts to maintain the current project schedule, if possible, and believe the Contractor is responsible for any related costs for not achieving the schedule and performance guarantees in the EPC Agreement. Although many factors could ultimately impact our project budget, we anticipate that our current budget contains an adequate contingency to cover up to a one-year delay in the estimated in-service date for Unit No. 3 and a several month delay in the estimated in-service date for Unit No. 4, if necessary.

As construction continues, the risk remains that continued challenges with the Contractor's performance, including labor productivity, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the project schedule and cost. Further, 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. As discussed under "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Vogtle Units No. 3 and No. 4" and "Item 1A—RISK FACTORS" in our 2015 Form 10-K, other issues could arise and may further impact the project schedule and cost. The ultimate outcome of 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 June 30, 2016 Form 10-Q that may impact the operation of our facilities.

In 2015, the U.S. Environmental Protection Agency (EPA) published in the Federal Register its final Clean Power Plan, which establishes guidelines for the states to follow when developing any final New Source Performance Standards (NSPS) for existing fossil fuel-fired electric generating units. Subsequently, these final rules were challenged in the U.S. Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court granted numerous applications to stay the Clean Power Plan, pending resolution of these cases before the D.C. Circuit. The stay would continue if the case proceeds for resolution to the U.S. Supreme Court. On Sept. 27, 2016, the consolidated cases challenging the issuance of the Clean Power Plan were argued before the full D.C. Circuit. We are now awaiting a decision from this Court, which may not be issued until sometime in 2017. Regardless of the outcome of that decision, the case will then likely be appealed to the U.S. Supreme Court. We cannot determine the outcome of: (i) these EPA rules; (ii) any rules the State of Georgia may issue in response to the Clean Power Plan; or (iii) any litigation challenging EPA's or Georgia's rules. Nor can we predict how any of these outcomes may affect our operations. We anticipate that some of the policy approaches set forth in the Clean Power Plan could have significant negative consequences for the economy and electric system in Georgia and the nation, if the guidelines are implemented as finalized by EPA.

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On September 7, 2016, EPA issued its final Cross State Air Pollution Rule (CSAPR) Update for the 2008 ozone national ambient air quality standards (NAAQS). In the final rule, EPA issued Federal Implementation Plans (FIPs) for 22 eastern states (not including Georgia), which generally provide updated CSAPR NOx ozone season emissions budgets for the electric generating units within such states, beginning with the 2017 ozone season, May 1, 2017-September 30, 2017. In the rule, EPA determined that emissions from Georgia (and 13 other states) do not significantly contribute to nonattainment or interfere with maintenance of the 2008 ozone NAAQS in downwind states, so that further emission reductions from sources in these states to meet the 2008 ozone NAAQS are not required. Georgia is now the only state determined not to contribute to nonattainment with maintenance of the 2008 ozone NAAQS but which still has an ongoing requirement with respect to the 1997 ozone NAAQS, which will continue unchanged. Ultimately, the final CSAPR update proposes two trading programs for NOx ozone season: (i) a Group 1 program, to which only Georgia belongs, and (ii) a Group 2 program that contains the 22 states mentioned previously. EPA will issue distinct allowances for both trading groups. The rule allows Georgia to maintain its allowances but precludes out-of-state trading, unless existing allowances are first devalued by a factor of 3.5. The rule provides an option for Georgia to voluntarily opt into the Group 2 trading program by voluntarily adopting an updated rule emission budget. We continue to evaluate these trading programs and cannot predict the ultimate outcome of this rulemaking or any ensuing litigation that may occur.

On April 17, 2015, the final coal combustion residuals (CCR) rule was published by EPA. The rule classified CCR as non-hazardous and outlined the requirements for disposing and storing ash from electric utilities. The method of enforcement of the federal rule is through citizen suits. Each state may adopt the federal rules into its own program and may add to the federal requirements. The State of Georgia Environmental Protection Division (EPD) developed a proposed CCR rule that was approved by the Department of Natural Resources Board on October 26, 2016. The EPD rule adopts the federal rule by reference and develops a permitting process for all CCR disposal facilities. The Georgia rule also includes "inactive" facilities that are exempt in the federal rule. As a result of the rule, EPD permits will be required for the CCR disposal facilities and the co-owned plants Scherer and Wansley. Through the permitting process, the public will be allowed to comment and final permits issued by EPD can be appealed and eventually litigated. The rule is expected to be effective in late 2016 and is not expected to have a material impact on compliance with the CCR regulations.

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.

Liquidity

At September 30, 2016, we had $1.6 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $363 million in cash and cash equivalents and $1.2 billion of unused and available committed credit arrangements.

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At September 30, 2016, we had $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 September 30, 2016		Expiration Date
		(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by CFC	$	1,210	(1)	$	918	(2)	March 2020
CFC Line of Credit(3)		110			110		December 2018
JPMorgan Chase Line of Credit		150			34	(4)	October 2018
Secured Facilities:
CFC Term Loan(3)		250			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 September 30, 2016, $156 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 September 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.

In October, we renewed for another two years our $150 million line of credit with JPMorgan Chase Bank that was set to expire in November 2016.

Currently, we are primarily using our commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of long-term funding under the Department of Energy-guaranteed Federal Financing Bank loan, which can be requested no more frequently than 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 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 September 30, 2016. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2016, the required minimum level was $675 million and our actual patronage capital was $872 million. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0 billion and $4.0 billion, respectively. At September 30, 2016, we had $8.1 billion of secured indebtedness and $156 million of unsecured indebtedness outstanding.

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At September 30, 2016, we had $451 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of September 30, 2016—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At September 30, 2016, we had $8.1 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 September 30, 2016, we had two approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank that are in various stages of being drawn down. These two loans totaled $678 million with $506 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 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 September 30, 2016, our total investment in Vogtle Units No. 3 and No. 4 was $3.2 billion and we have incurred $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 and $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 September 30, 2016, we have the capacity to fund an additional $555 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.

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.

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 September 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

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evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 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

Other than as disclosed in "Part II—Item 1. Legal Proceedings" in our Form 10-Q for the quarterly period ended June 30, 2016 and Form 10-Q for the quarterly period ended March 31, 2016, there have been no material changes to the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 2015 Form 10-K.

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	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).
	101	XBRL Interactive Data File.

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SIGNATURES

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

		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: November 10, 2016	By:	/s/ Michael L. Smith
		Michael L. Smith President and Chief Executive Officer
Date: November 10, 2016		/s/ Elizabeth B. Higgins
		Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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