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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, 2017
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. 333-192954

(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 o    No ý

        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    Emerging Growth 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, 2017

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three and Nine Months ended September 30, 2017 and 2016	3
	Unaudited Consolidated Statements of Comprehensive Margin For the Three and Nine Months ended September 30, 2017 and 2016	4
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin For the Nine Months ended September 30, 2017 and 2016	5
	Unaudited Consolidated Statements of Cash Flows For the Nine Months ended September 30, 2017 and 2016	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	37
Item 4.	Controls and Procedures	37
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	38
Item 1A.	Risk Factors	38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
SIGNATURES		42

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, 2016 and under "Risk Factors" in our Form 10-Q for the quarterly period ended June 30, 2017 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 results of Westinghouse Electric Company LLC and WECTEC Global Project Services Inc.'s bankruptcy filing and any inability or failure by Toshiba Corporation to perform its obligations pursuant to its settlement agreement related to its guarantee of certain of Westinghouse's obligations related to the additional units at Plant Vogtle;

•

decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;

•

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;

•

our current inability to receive advances under the U.S. Department of Energy loan guarantee agreement for construction of two additional nuclear units at Plant Vogtle;

•

the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five year period and the Department of Energy's decision to require such repayment;

•

the continued availability of funding from the Rural Utilities Service;

•

the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;

ii

•

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;

•

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

•

actions by credit rating agencies;

•

commercial banking and financial market conditions;

•

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

•

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;

•

the inability of counterparties to meet their obligations to us, including failure to perform under agreements;

•

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, including from the development and deployment of distributed generation and energy storage technologies;

•

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

•

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;

•

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, 2017 and December 31, 2016

		(dollars in thousands)
	2017			2016
Assets
Electric plant:
In service	$	8,857,293		$	8,786,839
Less: Accumulated provision for depreciation		(4,260,047	)		(4,115,339	)
		4,597,246			4,671,500
Nuclear fuel, at amortized cost		360,529			377,653
Construction work in progress		3,824,068			3,228,214
Total electric plant		8,781,843			8,277,367
Investments and funds:
Nuclear decommissioning trust fund		427,786			386,029
Investment in associated companies		74,187			72,783
Long-term investments		125,518			99,874
Restricted investments		265,180			221,122
Other		21,689			20,730
Total investments and funds		914,360			800,538
Current assets:
Cash and cash equivalents		342,064			366,290
Restricted short-term investments		246,432			247,006
Receivables		180,250			155,042
Inventories, at average cost		263,226			259,831
Prepayments and other current assets		20,438			32,919
Total current assets		1,052,410			1,061,088
Deferred charges:
Regulatory assets		572,237			545,387
Other		28,639			16,733
Total deferred charges		600,876			562,120
Total assets	$	11,349,489		$	10,701,113

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

1

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, 2017 and December 31, 2016

		(dollars in thousands)
	2017			2016
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	923,495		$	859,810
Accumulated other comprehensive margin		(352	)		(370	)
		923,143			859,440
Long-term debt		7,991,307			7,892,836
Obligation under capital lease		89,710			92,096
Other		19,725			18,765
Total capitalization		9,023,885			8,863,137
Current liabilities:
Long-term debt and capital lease due within one year		154,817			316,861
Short-term borrowings		631,949			102,168
Accounts payable		161,168			73,801
Accrued interest		84,287			93,634
Member power bill prepayments, current		43,836			176,988
Other current liabilities		54,621			59,979
Total current liabilities		1,130,678			823,431
Deferred credits and other liabilities:
Asset retirement obligations		726,074			698,051
Member power bill prepayments, non-current		202,202			48,115
Contract retainage		0			40,008
Regulatory liabilities		236,445			197,748
Other		30,205			30,623
Total deferred credits and other liabilities		1,194,926			1,014,545
Total equity and liabilities	$	11,349,489		$	10,701,113

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, 2017 and 2016

		(dollars in thousands)
	Three Months						Nine Months
	2017			2016			2017			2016
Operating revenues:
Sales to Members	$	385,758		$	430,883		$	1,106,975		$	1,158,134
Sales to non-Members		148			130			220			383
Total operating revenues		385,906			431,013			1,107,195			1,158,517
Operating expenses:
Fuel		143,767			178,516			366,405			404,056
Production		93,657			105,681			293,930			312,332
Depreciation and amortization		56,143			54,719			167,983			162,606
Purchased power		14,345			13,109			44,222			39,254
Accretion		9,224			8,059			27,333			24,099
Total operating expenses		317,136			360,084			899,873			942,347
Operating margin		68,770			70,929			207,322			216,170
Other income:
Investment income		14,850			12,578			44,509			37,628
Other		627			1,531			1,908			6,259
Total other income		15,477			14,109			46,417			43,887
Interest charges:
Interest expense		93,809			93,544			280,621			273,066
Allowance for debt funds used during construction		(33,517	)		(30,135	)		(99,953	)		(84,460	)
Amortization of debt discount and expense		3,150			2,999			9,386			8,946
Net interest charges		63,442			66,408			190,054			197,552
Net margin	$	20,805		$	18,630		$	63,685		$	62,505

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, 2017 and 2016

		(dollars in thousands)
	Three Months					Nine Months
	2017		2016			2017		2016
Net margin	$	20,805	$	18,630		$	63,685	$	62,505
Other comprehensive margin:
Unrealized gain (loss) on available-for-sale securities		56		(19	)		18		358
Total comprehensive margin	$	20,861	$	18,611		$	63,703	$	62,863

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 (Deficit) Margin (Unaudited)
For the Nine Months Ended September 30, 2017 and 2016

		(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive (Deficit) Margin			Total
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
Balance at December 31, 2016	$	859,810	$	(370	)	$	859,440
Components of comprehensive margin:
Net margin		63,685		—			63,685
Unrealized gain on available-for-sale securities		—		18			18
Balance at September 30, 2017	$	923,495	$	(352	)	$	923,143

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, 2017 and 2016

		(dollars in thousands)
	2017			2016
Cash flows from operating activities:
Net margin	$	63,685		$	62,505
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		279,898			268,674
Accretion cost		27,333			24,099
Amortization of deferred gains		(1,341	)		(1,341	)
Allowance for equity funds used during construction		(567	)		(567	)
Deferred outage costs		(32,777	)		(29,464	)
Gain on sale of investments		(16,478	)		(653	)
Regulatory deferral of costs associated with nuclear decommissioning		631			(14,522	)
Other		(6,610	)		(4,424	)
Change in operating assets and liabilities:
Receivables		(24,650	)		(41,015	)
Inventories		(3,395	)		30,251
Prepayments and other current assets		1,949			(1,305	)
Accounts payable		68,585			(87,056	)
Accrued interest		(9,347	)		(966	)
Accrued taxes		7,249			5,348
Other current liabilities		(13,354	)		(20,604	)
Member power bill prepayments		20,935			32,809
Total adjustments		298,061			159,264
Net cash provided by operating activities		361,746			221,769
Cash flows from investing activities:
Property additions		(737,146	)		(421,384	)
Activity in nuclear decommissioning trust fund—Purchases		(329,248	)		(307,222	)
—Proceeds		323,840			302,308
Increase in restricted investments		(44,058	)		(66,821	)
Decrease in restricted short-term investments		574			3,519
Activity in other long-term investments—Purchases		(45,246	)		(44,457	)
—Proceeds		27,196			35,278
Other		(12,780	)		2,401
Net cash used in investing activities		(816,868	)		(496,378	)
Cash flows from financing activities:
Long-term debt proceeds		4,517			634,279
Long-term debt payments		(240,417	)		(113,328	)
Increase (decrease) in short-term borrowings, net		652,401			(105,225	)
Other		14,395			8,553
Net cash provided by financing activities		430,896			424,279
Net (decrease) increase in cash and cash equivalents		(24,226	)		149,670
Cash and cash equivalents at beginning of period		366,290			213,038
Cash and cash equivalents at end of period	$	342,064		$	362,708
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	187,798		$	185,484
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	2,189		$	72,097
Change in accrued property additions	$	(21,904	)	$	(24,451	)
Interest paid-in-kind	$	42,555		$	34,587

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, 2017 and 2016. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading.

These 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, 2016, as filed with the SEC. The results of operations for the three-month and nine-month periods ended September 30, 2017 are not necessarily indicative of results to be expected for the full year. As noted in our 2016 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 2016 Form 10-K.

(B)

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

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

•

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

•

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

•

Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. None of our financial assets or liabilities had unobservable inputs classifying them as level 3.

7

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

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

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

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

The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 2017 and December 31, 2016.

	Fair Value Measurements at Reporting Date Using
		September 30, 2017		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	138,008	$	138,008	$	—
International equity trust		81,260		—		81,260
Corporate bonds		68,909		—		68,909
US Treasury and government agency securities		51,144		51,144		—
Agency mortgage and asset backed securities		35,153		—		35,153
Mutual funds		47,604		47,604		—
Municipal bonds		301		—		301
Other		5,407		5,407		—
Long-term investments:
International equity trust		20,712		—		20,712
Corporate bonds		15,173		—		15,173
US Treasury and government agency securities		11,608		11,608		—
Agency mortgage and asset backed securities		1,348		—		1,348
Mutual funds		75,479		75,479		—
Other		1,198		1,199		—
Natural gas swaps		807		—		807

8

	Fair Value Measurements at Reporting Date Using
		December 31, 2016			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
		(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	170,408		$	170,408	$	—
International equity trust		66,861			—		66,861
Corporate bonds		60,019			—		60,019
US Treasury and government agency securities		65,725			65,725		—
Agency mortgage and asset backed securities		17,410			—		17,410
Municipal bonds		943			—		943
Other		4,663			4,663		—
Long-term investments:
Corporate bonds		11,853			—		11,853
US Treasury and government agency securities		12,187			12,187		—
Agency mortgage and asset backed securities		1,651			—		1,651
International equity trust		15,946			—		15,946
Mutual funds		57,932			57,932		—
Other		305			305		—
Natural gas swaps		(15,090	)		—		(15,090	)

None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at September 30, 2017 or December 31, 2016.

The estimated fair values of our long-term debt, including current maturities at September 30, 2017 and December 31, 2016 were as follows (in thousands):

		2017				2016
		Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	8,237,972	$	9,119,700	$	8,304,523	$	9,043,029

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, 2017 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.

9

For cash and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value.

(C)

Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps 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 could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 2017 all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge 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.

10

At September 30, 2017 and December 31, 2016, the estimated fair value of our natural gas contracts was a net liability of approximately $807,000 and a net asset of $15,090,000, respectively.

As of September 30, 2017 and December 31, 2016, 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, 2017 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $2,788,000 with our counterparties.

The following table reflects the volume activity of our natural gas derivatives as of September 30, 2017 that is expected to settle or mature each year:

Year	Natural Gas Swaps (MMBTUs) (in millions)
2017	3.8
2018	24.6
2019	18.7
2020	15.9
2021	12.9
2022	5.8
Total	81.7

Interest rate options.     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. The last of these options, having a notional value of $80,169,000, expired without value at March 31, 2017.

We are deferring the premiums paid to purchase these LIBOR swaptions, related carrying and other incidental costs in accordance with our rate-making treatment. The deferral will continue and costs will be amortized and collected in rates over the life of the associated debt that we hedged with the swaptions.

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2017 and December 31, 2016.

	Balance Sheet Location		Fair Value
			2017		2016
			(dollars in thousands)
Not designated as hedges:
Assets:
Natural gas swaps	Other current assets	$	3,302	$	13,833
Natural gas swaps	Other deferred charges	$	—	$	3,289
Liabilities:
Natural gas swaps	Other current liabilities	$	—	$	54
Natural gas swaps	Other deferred credits	$	4,109	$	1,977

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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, 2017 and 2016.

	Statement of Revenues and Expenses Location		Three months ended September 30,						Nine months ended September 30,
			2017			2016			2017			2016
			(dollars in thousands)
Not Designated as hedges:
Natural Gas Swaps	Fuel	$	778		$	2,039		$	3,514		$	2,057
Natural Gas Swaps	Fuel		(678	)		(5,923	)		(1,495	)		(18,262	)
		$	100		$	(3,884	)	$	2,019		$	(16,205	)

The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at September 30, 2017 and December 31, 2016.

	Balance Sheet Location		2017			2016
			(dollars in thousands)
Not designated as hedges:
Natural gas swaps	Regulatory asset	$	(2,788	)	$	(62	)
Natural gas swaps	Regulatory liability		1,981			15,152
Interest rate options	Regulatory asset		—			(5,788	)
Total not designated as hedges		$	(807	)	$	9,302

(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, 2017 approximately 79% of these gross unrealized losses had been unrealized for a duration of less than one year.

The following tables summarize available-for-sale securities as of September 30, 2017 and December 31, 2016.

		Gross Unrealized
		(dollars in thousands)
September 30, 2017		Cost		Gains		Losses			Fair Value
Equity	$	251,021	$	75,181	$	(4,386	)	$	321,816
Debt		224,458		2,194		(1,769	)		224,883
Other		6,604		1		—			6,605
Total	$	482,083	$	77,376	$	(6,155	)	$	553,304

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		Gross Unrealized
		(dollars in thousands)
December 31, 2016		Cost		Gains		Losses			Fair Value
Equity	$	237,317	$	51,054	$	(5,041	)	$	283,330
Debt		201,492		1,167		(3,423	)		199,236
Other		3,339		—		(2	)		3,337
Total	$	442,148	$	52,221	$	(8,466	)	$	485,903

(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 was 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 was not permitted.

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.


While we expect that the majority of our revenues will be included in the scope of Topic 606, we have not fully completed our evaluation of the new revenue standard. Our evaluation process includes, but is not limited to, identifying contracts within the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. A large majority of our revenues is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchanged on an annual basis under the new revenue standard. However, we continue to evaluate the effects, if any, of Topic 606 on our interim period revenues as it relates to budget adjustments, which have historically been made during the fourth quarter but may also be made during the year that affect our annual revenue requirement and therefore amounts billed to our members. We also continue to evaluate other revenue streams and the related contracts, as well as monitor issues specific to the power and utilities industry. While we have not fully completed our evaluation of the impact of the new revenue recognition guidance, we currently anticipate utilizing a full retrospective transition upon the adoption of Topic 606 as of January 1, 2018.


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

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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 retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements.


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


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


In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. Our restricted cash balances are nominal and accordingly we do not expect the adoption of this standard to have a material impact 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 (Deficit) 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 2016

14

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.

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

		Accumulated Other Comprehensive (Deficit) Margin
		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

		Three Months Ended September 30, 2017
		(dollars in thousands)
		Available-for-sale Securities
Balance at June 30, 2017	$	(408	)
Unrealized gain		33
Loss reclassified to net margin		23
Balance at September 30, 2017	$	(352	)

15

		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

		Nine Months Ended September 30, 2017
		(dollars in thousands)
		Available-for-sale Securities
Balance at December 31, 2016	$	(370	)
Unrealized loss		(57	)
Loss reclassified to net margin		75
Balance at September 30, 2017	$	(352	)

(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.    Patronage Capital Litigation

On June 9, 2017, the Georgia Court of Appeals upheld the Superior Court of DeKalb County's decision to dismiss on all counts both of the cases described under Note 12—Patronage Capital Litigation in our 2016 Form 10-K. The plaintiffs did not further appeal these dismissals to the Georgia Supreme Court and the appeal period has since expired, ending this litigation.

b.    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 have become increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future

16

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 Investments.    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At September 30, 2017 and December 31, 2016, we had restricted investments totaling $511,612,000 and $468,179,000, respectively, of which $265,180,000 and $221,122,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.

(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.

17

The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, 2017 and December 31, 2016.

		2017		2016
		(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	51,546	$	55,084
Amortization on capital leases(b)		33,454		32,274
Outage costs(c)		42,060		39,986
Interest rate swap termination fees(d)		2,231		3,570
Asset retirement obligations—Ashpond and other(l)		59,540		33,747
Depreciation expense(e)		43,023		44,091
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)		47,322		43,444
Interest rate options cost(g)		110,915		107,394
Deferral of effects on net margin—Smith Energy Facility(h)		167,941		172,399
Other regulatory assets(m)		14,205		13,398
Total Regulatory Assets	$	572,237	$	545,387
Regulatory Liabilities:
Accumulated retirement costs for other obligations(i)	$	14,235	$	9,829
Deferral of effects on net margin—Hawk Road Energy Facility(h)		19,705		20,163
Major maintenance reserve(j)		43,269		28,379
Amortization on capital leases(b)		20,780		23,084
Deferred debt service adder(k)		93,296		86,082
Asset retirement obligations(l)		40,199		11,766
Other regulatory liabilities(m)		4,961		18,445
Total Regulatory Liabilities	$	236,445	$	197,748
Net Regulatory Assets	$	335,792	$	347,639

^(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 27 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 costs associated with interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction that will be amortized over the life of the associated debt.

^(h)

Effects on net margin for Smith and Hawk Road Energy Facilities 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 33 years and the amortization period of other regulatory liabilities range up to 10 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 January 2022, with the majority of the balance scheduled to be credited by the end of 2019.

(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 (as amended, the Loan Guarantee Agreement) 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 FFB 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 long-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. Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of eligible project costs or (ii) $3,057,069,461, of which $335,471,604 is designated for capitalized interest.

Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will begin on February 20, 2020. Under both FFB Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.

At September 30, 2017, aggregate Department of Energy-guaranteed borrowings totaled $1,720,997,000, including capitalized interest.

On July 27, 2017, we and the Department of Energy entered into Amendment No. 3 to the Loan Guarantee Agreement. Under the amended terms of the Loan Guarantee Agreement, no advances under the Facility will be permitted unless and until such time as Georgia Power, on behalf of the Co-owners (as defined in Note L), has (i) completed comprehensive schedule, cost-to-complete, and cancellation cost assessments (the Cost Assessments) and made a determination to continue construction of Vogtle Units No. 3 and No. 4; (ii) delivered to the Department of Energy an updated project schedule, construction budget, and other information; (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Vogtle Units No. 3 and No. 4 and such agreements have been approved by the Department of Energy (together with the Services Agreement (as defined in Note L) and certain

19

related intellectual property licenses (the IP Licenses), the Replacement EPC Arrangements); and (iv) entered into a further amendment to the Loan Guarantee Agreement with the Department of Energy to reflect the Replacement EPC Arrangements.

When the conditions in the preceding paragraph are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. The timing of satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs.

Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default.

Under the Loan Guarantee Agreement, upon the occurrence of an "Alternate Amortization Event," the Department of Energy may require us to prepay the outstanding principal amount of all guaranteed borrowings over a period of five years, with level principal amortization. These events include (i) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to intellectual property rights under the IP Licenses, (iii) a decision by us not to continue construction of Vogtle Units No. 3 and No. 4, (iv) Georgia Power, on behalf of the Co-owners, fails to complete the Cost Assessments or enter into the Replacement EPC Arrangements by December 31, 2017, (v) loss of or failure to receive necessary regulatory approvals under certain circumstances, (vi) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vii) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (viii) change of control of Oglethorpe and (ix) certain events of loss or condemnation.

Under certain circumstances we may be required to make prepayments in connection with our receipt of payments under the settlement agreement with Toshiba regarding the Toshiba Guarantee or from the EPC Contractor under the EPC Agreement (as defined in Note L). In addition, if we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility.

We may also voluntarily prepay outstanding borrowings under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable.

On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1,620,000,000 in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.

b)

Rural Utilities Service Guaranteed Loans:

For the nine-month period ended September 30, 2017 we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $4,517,000 for general and

20

environmental improvements at existing plants.These advances are secured under our first mortgage indenture.

On October 30, 2017, we received an additional $17,582,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for general and environmental improvements at existing plants.

c)

Pollution Control Revenue Bonds:

On October 12, 2017, the Development Authority of Burke County (Georgia), the Development Authority of Heard County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $122,620,000 in aggregate principal amount of tax-exempt pollution control revenue bonds for the purpose of refinancing costs associated with certain of our air or water pollution control and sewage or solid waste disposal facilities. The bonds were directly purchased by a bank and the proceeds were used to repay outstanding commercial paper issued to redeem certain auction rate pollution control revenue bonds in January 2017. Each series of bonds bear interest at an indexed variable rate until October 3, 2022, the initial mandatory tender date. The pollution control revenue bonds are scheduled to mature in 2040 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.

(L)

Vogtle Units No. 3 and No. 4 Construction Project.    We, Georgia Power, 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) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our binding ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the EPC Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the EPC Contractor agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

Under the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments. The EPC Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million.

Toshiba Corporation guaranteed certain payment obligations of the EPC Contractor under the EPC Agreement (the Toshiba Guarantee), including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Co-owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the EPC Agreement, the EPC Contractor did not have the right to terminate the EPC Agreement for convenience. In the event of an abandonment of work by the EPC

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Contractor, the maximum liability of the EPC Contractor under the EPC Agreement was 40% of the contract price, or $3.68 billion, of which our proportionate share is approximately $1.1 billion.

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. To provide for a continuation of work at Vogtle Units No. 3 and No. 4, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the EPC Contractor and WECTEC Staffing Services LLC, which the bankruptcy court approved on March 30, 2017. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Co-owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor's bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Co-owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which our proportionate share totals approximately $115 million. As of September 30, 2017, $340 million of this aggregate liability had been paid or accrued by Georgia Power, on behalf of the Co-owners.

On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (the Guarantee Obligations), of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Execution of any such transaction cannot be assured and would require certain consents from and cooperation by the Department of Energy.

On November 9, 2017, Toshiba released its financial results for the second quarter of fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of

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September 30, 2017. Toshiba also reiterated the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and the EPC Contractor entered into a services agreement, which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractor to transition construction management of Vogtle Units No. 3 and No. 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 and will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

On August 31, 2017, Georgia Power filed its 17^th Vogtle Construction Monitoring report (VCM 17 Report) with the Georgia Public Service Commission. In the VCM 17 Report, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission will render a decision on these matters by February 6, 2018.

The revised project schedule Georgia Power submitted to the Georgia Public Service Commission for approval included commercial operation dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Based on comprehensive cost-to complete assessments and the revised commercial operation dates, our revised project budget is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget assumes 100% recovery of our $1.1 billion share of the Guarantee Obligations from Toshiba. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion without taking into account any amounts recoverable from Toshiba. Amounts recovered in connection with the Guarantee Settlement Agreement will be recorded as a reduction to the construction work in progress balance as payments are received.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement (the Bechtel Agreement) with Bechtel Power Corporation, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain

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circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.

On November 2, 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba or, except in the case in which each of the Co-owners has assigned its rights under the Guarantee Settlement Agreement to a third party, a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.

The effectiveness of the amendments to the Joint Ownership Agreements related to the Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of April 21, 2006, as amended, is subject to the condition that we obtain the approval of the Rural Utilities Service as required under our loan contract with the Rural Utilities Service.

In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.

There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the Nuclear Regulatory Commission, may arise if 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.

As construction continues, the risk remains that challenges with management of contractors, subcontractors and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

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

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

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Results of Operations

For the Three and Nine Months Ended September 30, 2017 and 2016

Net Margin

Our net margins for the three-month and nine-month periods ended September 30, 2017 were $20.8 million and $63.7 million compared to $18.6 million and $62.5 million for the same periods of 2016. Through September 30, 2017, we collected approximately 123% of our targeted net margin of $51.7 million for the year ending December 31, 2017. These collections are typical as our capacity revenues are generally recorded evenly throughout the year and our management budgets conservatively. In September 2017, our board of directors approved a budget adjustment that reduced revenue requirements by $5.0 million in order to provide our members with a measure of relief for costs they incurred as a result of significant system damage from Hurricane Irma. We anticipate our board of directors will approve an additional budget adjustment by the end of the year so margins will achieve, but not exceed, our 2017 targeted margins for interest ratio of 1.14. 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 2016 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, 2017 and 2016 were as follows:

		Three Months Ended September 30,					2017 vs. 2016 % Change		Nine Months Ended September 30,					2017 vs. 2016 % Change
		(dollars in thousands)							(dollars in thousands)
		2017			2016				2017			2016
Capacity revenues	$	217,918		$	228,011		(4.4%)	$	666,226		$	681,384		(2.2%)
Energy revenues		167,840			202,872		(17.3%)		440,749			476,750		(7.6%)
Total	$	385,758		$	430,883		(10.5%)	$	1,106,975		$	1,158,134		(4.4%)
MWh Sales to members		6,962,978			7,956,412		(12.5%)		18,213,379			19,886,944		(8.4%)
Cents/kWh		5.54			5.42		2.3%		6.08			5.82		4.4%
Member energy requirements supplied		62	%		64	%	(3.9%)		63	%		64	%	(1.3%)

Capacity revenues for the three-month and nine-month periods ended September 30, 2017 reflect a $5.0 million reduction in revenue requirements for the September 2017 budget adjustment approved by the board of directors discussed above.

Energy revenues from members decreased for the three-month and nine-month periods ended September 30, 2017 compared to the same periods in 2016 primarily due to a decrease in fuel costs which was largely a result of a decrease in generation for member sales in 2017. For a discussion of fuel costs, which are the primary components of energy revenues, see "—Operating Expenses."

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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,			2017 vs.	Three Months Ended September 30,		2017 vs.	Three Months Ended September 30,		2017 vs.
Fuel Source		2017		2016	2016 % Change	2017	2016	2016 % Change	2017	2016	2016 % Change
Coal	$	30,924	$	49,478	(37.5%)	1,157,960	1,704,203	(32.1%)	2.67	2.90	(8.0%)
Nuclear		23,249		21,950	5.9%	2,585,668	2,691,129	(3.9%)	0.90	0.82	10.2%
Gas:
Combined Cycle		67,058		73,223	(8.4%)	2,888,612	2,976,562	(3.0%)	2.32	2.46	(5.6%)
Combustion Turbine		22,536		33,865	(33.5%)	544,294	846,699	(35.7%)	4.14	4.00	3.5%
	$	143,767	$	178,516	(19.5%)	7,176,534	8,218,593	(12.7%)	2.00	2.17	(7.8%)

		Cost				Generation			Cents per kWh
		(dollars in thousands)				(MWh)
		Nine Months Ended September 30,			2017 vs.	Nine Months Ended September 30,		2017 vs.	Nine Months Ended September 30,		2017 vs.
Fuel Source		2017		2016	2016 % Change	2017	2016	2016 % Change	2017	2016	2016 % Change
Coal	$	81,867	$	114,961	(28.8%)	2,913,161	3,945,663	(26.2%)	2.81	2.91	(3.5%)
Nuclear		66,538		61,786	7.7%	7,399,354	7,605,266	(2.7%)	0.90	0.81	10.7%
Gas:
Combined Cycle		181,254		165,272	9.7%	7,546,775	7,338,407	2.8%	2.40	2.25	6.6%
Combustion Turbine		36,746		62,037	(40.8%)	881,514	1,644,184	(46.4%)	4.17	3.77	10.5%
	$	366,405	$	404,056	(9.3%)	18,740,804	20,533,520	(8.7%)	1.96	1.97	(0.6%)

Total fuel costs decreased for the three-month and nine-month periods ended September 30, 2017 compared to the same periods of 2016 primarily due to a decrease in generation as a result of moderate temperatures. In addition, generation for the nine-month period ended September 30, 2017 compared to the same period of 2016 was somewhat affected by increased natural gas prices and planned maintenance outages during 2017.

Financial Condition

Balance Sheet Analysis as of September 30, 2017

Assets

Cash used for property additions for the nine-month period ended September 30, 2017 totaled $737.1 million. Of this amount, approximately $518.5 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $47.7 million for nuclear fuel purchases and expenditures for normal additions and replacements to our existing generation facilities.

Restricted investments consist 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 our 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.

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Equity and Liabilities

Long-term debt increased $98.5 million during the nine-month period ended September 30, 2017 primarily due to the classification of $122.6 million of commercial paper as long-term debt. In October 2017, $122.6 million of tax-exempt bonds was issued to refund the commercial paper on a long-term basis. For information regarding the refunding of commercial paper and the issuance of tax-exempt bonds, see Note K.

Long-term debt and capital leases due within one year decreased $162.0 million during the nine-month period ended September 30, 2017. The decrease was primarily due to the redemption of $122.6 million of variable rate pollution control revenue bonds through the issuance of commercial paper in January 2017. In addition, the decrease was due to certain quarterly Federal Financing Bank note payments we made, when due, in early January 2017.

Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $529.8 million during the nine-month period ended September 30, 2017.

Accounts payable increased $87.4 million for the nine-month period ended September 30, 2017 primarily as a result of a $104.7 million increase 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. Offsetting the increase was $17.2 million in credits applied to our members' bills in the first quarter of 2017, for a board approved reduction in 2016 revenue requirements as a result of margins in excess of our 2016 target.

The current portion of member power bill prepayments decreased $133.2 million for the nine-month period ended September 30, 2017 due to the application of credits against the power bills of members that participate in the power bill prepayment program. The long-term portion of member power bill prepayments increased $154.1 million for the nine-month period ended September 30, 2017 due to member contributions to the program made during the third quarter of 2017. For additional information on the member power bill prepayment program, see Note J of Notes to Unaudited Consolidated Financial Statements.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power, 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) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our binding ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the EPC Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the EPC Contractor agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.

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Under the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments. The EPC Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million.

Toshiba Corporation guaranteed certain payment obligations of the EPC Contractor under the EPC Agreement (the Toshiba Guarantee), including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Co-owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed.

Under the terms of the EPC Agreement, the EPC Contractor did not have the right to terminate the EPC Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the EPC Agreement was 40% of the contract price, or $3.68 billion, of which our proportionate share is approximately $1.1 billion.

On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. To provide for a continuation of work at Vogtle Units No. 3 and No. 4, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the EPC Contractor and WECTEC Staffing Services LLC, which the bankruptcy court approved on March 30, 2017. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Co-owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

Subsequent to the EPC Contractor's bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Co-owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which our proportionate share totals approximately $115 million. As of September 30, 2017, $340 million of this aggregate liability had been paid or accrued by Georgia Power, on behalf of the Co-owners.

On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (the Guarantee Obligations), of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the

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balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Execution of any such transaction cannot be assured and would require certain consents from and cooperation by the Department of Energy.

On November 9, 2017, Toshiba released its financial results for the second quarter of the fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also reiterated the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.

Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and the EPC Contractor entered into a services agreement, which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractor to transition construction management of Vogtle Units No. 3 and No. 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 and will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

On August 31, 2017, Georgia Power filed its 17^th Vogtle Construction Monitoring report (VCM 17 Report) with the Georgia Public Service Commission. In the VCM 17 Report, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to render a decision on these matters by February 6, 2018.

The revised project schedule Georgia Power submitted to the Georgia Public Service Commission for approval included commercial operation dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Based on comprehensive cost-to complete assessments and the revised commercial operation dates, our revised project budget is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget assumes 100% recovery of our $1.1 billion share of the Guarantee Obligations from Toshiba. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion without taking into account any amounts recoverable from Toshiba. Amounts recovered in connection with the Guarantee Settlement Agreement will be recorded as a reduction to the construction work in progress balance as payments are received.

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Based on the revised project schedule and budget, the following table provides an updated estimate of our forecasted capital expenditures related to Vogtle Units No. 3 and No. 4 for 2017 through 2019 (dollars in millions).

		2017		2018		2019		Total
Future Generation	$	645	$	677	$	504	$	1,826

In addition to the amounts reflected in the table above, we have budgeted approximately $1.9 billion to complete construction of Vogtle Units No. 3 and No. 4 beyond the years shown in the table. These projected capital expenditures assume that Toshiba fully performs its obligations under the Guarantee Settlement Agreement and the failure of Toshiba to perform those obligations could have a material impact on our costs for Vogtle Units No. 3 and No. 4. For additional information regarding our capital expenditures, see "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements—Capital Expenditures" in our 2016 Form 10-K.

Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement (the Bechtel Agreement) with Bechtel Power Corporation, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.

On November 2, 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba or, except in the case in which each of the Co-owners has assigned its rights under the Guarantee Settlement Agreement to a third party, a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.

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The effectiveness of the amendments to the Joint Ownership Agreements related to the Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of April 21, 2006, as amended, is subject to the condition that we obtain the approval of the Rural Utilities Service as required under our loan contract with the Rural Utilities Service.

In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.

We have a $3.06 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.72 billion as of September 30, 2017. Pursuant to the terms of the Loan Guarantee Agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the Loan Guarantee Agreement. The timing of satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1.62 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the Loan Guarantee Agreement with the Department of Energy, see Note K of Notes to Unaudited Consolidated Financial Statements and for additional information regarding the financing of Vogtle Units No. 3 and No. 4, see "Financing Activities—Department of Energy-Guaranteed Loan." We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances.

There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise as construction proceeds. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of Inspections, Tests, Analyses, and Acceptance Criteria and the related approvals by the Nuclear Regulatory Commission, may arise if 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.

As construction continues, the risk remains that challenges with management of contractors, subcontractors and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

The ultimate outcome of these matters cannot be determined at this time. See "Risk Factors" in this Form 10-Q for risks related to Vogtle Units No. 3 and No. 4 and the Guarantee Settlement Agreement and "Item 1A—RISK FACTORS" in our 2016 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

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Environmental Regulations

Federal and state laws and regulations regarding environmental matters affect operations at our facilities. Following are some substantial developments relating to environmental regulations and litigation that have occurred since we filed our Form 10-Q for the quarterly period ended June 30, 2017.

On October 10, 2017, the U.S. Environmental Protection Agency (EPA) proposed a rule to repeal the Clean Power Plan in its entirety on the basis that the Clean Power Plan exceeds the EPA's authority under the Clean Air Act. Even though some portions of the rule may be in accord with the Clean Air Act, EPA proposes to find that those portions are not severable from the objectionable portions and that the entire Clean Power Plan be repealed. EPA will decide what action, if any, to take in the future with regard to any replacement Clean Power Plan and has stated that it intends to issue an advanced notice of proposed rulemaking in the near future to solicit information on alternate systems to reduce greenhouse gas emissions consistent with its authority under the Clean Air Act. We cannot predict the outcome of this current proposal or any litigation that might be brought challenging any resulting final rule, nor can we predict the outcome of the litigation currently pending on the existing Clean Power Plan.

In September 2017, EPA postponed certain compliance dates for its November 2015 rule for the effluent limitations guidelines and standards for the steam electric power generating (ELG Rule) for two years. Plants Scherer and Wansley are regulated under this rule. EPA has stated that it intends to conduct a rulemaking to potentially revise the more stringent best available technology economically achievable effluent limitations and pretreatment standards for existing sources for flue gas desulfurization wastewater and bottom ash transport water established in the ELG Rule; however, it does not intend to revise the ELG Rule for fly ash transport, flue gas mercury control wastewater or other requirements. We cannot predict the outcome of any actions EPA may take to revise the ELG Rule, or any litigation that might be brought challenging any final rule.

We continue to evaluate all EPA actions regarding reviews and reconsiderations of final rules and processing of proposed rules and cannot predict the outcome of these rulemakings, any related state rulemakings or any related litigation, including litigation that might be brought to challenge the issuance of replacement or new final rules. It is unknown what impact potential rule changes will have on our and our members' operations. Continued uncertainty related to the status of current and future environmental regulations may make long-term planning decisions more difficult.

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 2016 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—Environmental Regulations" in our quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017.

Liquidity

At September 30, 2017, we had $1.07 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $342 million in cash and cash equivalents and $726 million of unused and available committed credit arrangements.

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At September 30, 2017, 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 October 13, 2017		Expiration Date
		(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by CFC	$	1,210	$	442	(1)	March 2020
CFC Line of Credit(2)		110		110		December 2018
JPMorgan Chase Line of Credit		150		34	(3)	October 2018
Secured Facilities:
CFC Term Loan(2)		250		140	(2)	December 2018
Total	$	1,610	$	726

⁽¹⁾

Of the portion of this facility that was unavailable at October 13, 2017, $632 million was dedicated to support outstanding commercial paper and $136 million was related to letters of credit issued to support variable rate demand bonds.

⁽²⁾

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. Therefore, we reflect $140 million as the amount available under the term loan even though no amounts have been borrowed under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.

⁽³⁾

Of the portion of this facility that was unavailable at October 13, 2017, $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.

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. See Note K of Notes to Unaudited Consolidated Financial Statements and "—Department of Energy-Guaranteed Loan" for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restricts our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guarantee Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this loan is uncertain but likely in 2018. The inability to advance funds under our Department of Energy loan has reduced our available liquidity in 2017. We expect this constraint to be mitigated in the coming months through one or more of several potential options including resumption of advances under the Department of Energy loan, monetization of the Toshiba Guarantee Settlement Agreement, or issuance of taxable bonds.

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, 2017. 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.

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Two of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2017, the required minimum level was $675 million and our actual patronage capital was $923 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, 2017, we had $8.1 billion of secured indebtedness and $756 million of unsecured indebtedness outstanding.

At September 30, 2017, we had $512 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, 2017—Assets" for more information regarding this account.

Financing Activities

First Mortgage Indenture.    At September 30, 2017, 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 2016 Form 10-K for further discussion of our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    At September 30, 2017, 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 $501 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, 2017, we had $2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loan.    In 2014, we closed on a loan with the Department of Energy that will fund up to the lesser of $3.06 billion or 70% of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy.

As of September 30, 2017, we had advanced $1.72 billion under this loan and had $1.34 billion remaining to be advanced. All of the debt under this loan will be secured ratably with all other debt under our first mortgage indenture. Access to the committed funds under this loan requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third-parties related to the Vogtle project to comply with certain laws. See Note K of Notes to Unaudited Consolidated Financial Statements for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restrict our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guaranty Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this facility is uncertain. Under certain circumstances, including a decision not to continue construction of the Vogtle units, the Department of Energy has discretion to require that we repay all amounts outstanding under the loan over a five-year period.

On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.62 billion in additional guaranteed funding under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.

In addition to the Department of Energy loan funding, we have issued $1.4 billion of first mortgage bonds to finance a substantial portion of the Vogtle expansion that will not be funded by the

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Department of Energy. As of September 30, 2017, we had $3.1 billion of long-term funding in place for the $3.9 billion invested in the Vogtle project to-date. We anticipate utilizing capital markets financing for any Vogtle related costs that we are not able to advance under the Department of Energy-guaranteed loans.

Bond Financings

On October 12, 2017, we closed on a $122.6 million direct bank purchase of tax-exempt bonds and used the proceeds to retire commercial paper that was issued in January 2017 in connection with the redemption of our remaining auction rate securities. See Note K of Notes to Unaudited Consolidated Financial Statements for more information regarding this refinancing.

In late 2017 or early 2018, we plan to issue approximately $400 million of tax-exempt pollution control revenue bonds, the proceeds of which will be used to refinance $400 million of existing pollution control bonds that are callable on January 1, 2018 and that have higher interest rates than our other tax-exempt debt. When issued, out payment obligations related to these bonds will be secured ratably with all other debt under our first mortgage indenture.

As of September 30, 2017, we had $980.8 million of outstanding obligations related to tax-exempt private activity bonds related to certain of our pollution control facilities. The Tax Cut and Jobs Act, as proposed by members of the House of Representatives on November 2, 2017, could take away our ability to utilize tax-exempt private activity bonds to finance or refinance qualifying pollution control facilities if issued on or after January 1, 2018 and impact the interest rates on our private activity bonds outstanding prior to January 1, 2018.

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 2016 Form 10-K.

Credit Rating Risk

The table below sets forth our current ratings from S&P Global Ratings, Moody's Investors Service and Fitch Ratings.

Our Ratings	S&P	Moody's	Fitch
Long-term ratings:
Senior secured rating	A-	Baa1	A-
Issuer/unsecured rating(1)	A-	Baa2	N/R(2)
Rating outlook	Negative	Negative	Rating Watch Negative
Short-term rating:
Commercial paper rating	A-2	P-2	F2

⁽¹⁾

We currently have no long-term debt that is unsecured.

⁽²⁾

N/R indicates no rating assigned for this category.

We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB–/Baa3 or below. As of September 30, 2017, our maximum potential collateral requirements were as follows:

At senior secured rating levels:

•

a total of approximately $52 million at a senior secured level of BBB–/Baa3,

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•

a total of approximately $81 million at a senior secured level of BB+/Ba1 or below, and

At senior unsecured or issuer rating levels:

•

a total of approximately $0.3 million at a senior unsecured or issuer level of BBB–/Baa3,

•

a total of approximately $58 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.

The Rural Utilities Service Loan Contract contains covenants that, upon a credit rating downgrade below investment grade by two rating agencies, could result in restrictions on issuing debt. Certain of our pollution control bond agreements contain provisions based on the ratings assigned to the bonds (which could be related to either our rating or a bond insurer's rating if the bonds are insured) that, upon a credit rating downgrade below specified levels, could result in increased interest rates. Also, borrowing rates and commitment fees in two of our line of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.

Given our current level of ratings, our management does not have any reason to expect a downgrade that would result in any material impacts to our business. However, our ratings reflect only the views of the rating agencies and we cannot give any assurance that our ratings will be maintained at current levels for any period of time.

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 2016 Form 10-K.

Item 4.    Controls and Procedures

As of September 30, 2017, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 2017 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

Except as disclosed under "Item 1—Legal Proceedings" in our quarterly report on Form 10-Q for the quarterly period ended June 30, 2017, there have been no material changes from the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 2016 Form 10-K.

Item 1A.    Risk Factors

Except as discussed below, there have been no material changes from the risk factors disclosed in "Item 1A—RISK FACTORS" in our 2016 Form 10-K.

Our participation in the development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.

We are contractually committed to participating in the construction of two additional nuclear units at Plant Vogtle and have committed significant capital expenditures to this endeavor. The construction of large, complex generating plants involves significant financial risk. Further, no nuclear plants have been constructed in the United States using advanced designs, such as the Westinghouse AP1000 design, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process.

Our current project budget for the Vogtle Units, which includes capital costs, allowance for funds used during construction and a contingency amount, is $7.0 billion and the scheduled commercial operation dates are November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Certain events have materially delayed the original commercial operation dates and increased the original project budget. The most significant of these relate to the EPC Contractor's filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code and its subsequent rejection of the fixed price EPC Agreement.

We continue to be subject to construction risks and no longer have the benefit of the "fixed" price EPC Agreement, which means that any cost overruns will be allocated to the Co-owners based on their ownership interest percentage. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:

•

performance by the EPC Contractor under the Services Agreement;

•

performance by Toshiba under the Guarantee Settlement Agreement;

•

performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;

•

changes in labor costs and productivity;

•

liens on the project;

•

contract disputes;

•

loss of access to intellectual property rights necessary to construct or operate the project;

•

shortages and/or inconsistent quality of equipment, materials and labor;

•

increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;

•

unforeseen engineering or design problems;

•

permits, approvals and other regulatory matters;

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•

unanticipated increases in the costs of materials;

•

changes in project design or scope;

•

impacts of new and existing laws and regulations, including environmental laws and regulations;

•

erosion of public and policymaker support;

•

adverse weather conditions; and

•

work stoppages.

Additionally, we do not control the determination as to whether the Vogtle project continues to move forward as continued construction of Vogtle Units No. 3 and No. 4 is subject to approval by the Georgia Public Service Commission. On August 31, 2017, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager in its VCM 17 Report filed with the Georgia Public Service Commission. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to make a decision on these matters by February 6, 2018.

Further, on November 2, 2017, the Co-owners amended the Joint Ownership Agreements to provide that holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction upon the occurrence of any of those adverse events. As we are a 30% owner in the Vogtle project, we, along with Georgia Power and the Municipal Electricity Authority of Georgia, will need to each determine to move forward with the Vogtle project upon the occurrence of certain adverse events. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.

Following the bankruptcy of the EPC Contractor, the rejection of the EPC Agreement and our comprehensive cost-to-complete assessment, we increased our project budget to $7.0 billion from $5.0 billion. This increase is expected to increase our capital expenditures through 2022 and lead to a corresponding increase in our long-term debt outstanding at completion of the Vogtle units to $11.5 billion from the previously disclosed amount of $10 billion. These increases in capital expenditures and in our long-term debt will continue to constrain our equity ratio and will affect certain of our other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would increase our borrowing costs and decrease our access to the credit and capital markets.

The long-term project cost will also be impacted by our ability to finance the capital costs at competitive interest rates. We are currently unable to make advances from the remaining $1.4 billion of committed funds under our Loan Guarantee Agreement with the Department of Energy and will not be able to make additional advances until we enter into an amendment to the Loan Guarantee Agreement with the Department of Energy. The timing of further advances under the Loan Guarantee Agreement is uncertain but is likely to occur in 2018. Prolonged inability to access funding pursuant to the Department of Energy Loan Guarantee Agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate. We have received a conditional commitment from the Department of Energy for approximately $1.6 billion of additional loan guarantees; however final approval of these additional amounts cannot be assured. See Note K of Notes to Unaudited Consolidated Financial Statements for additional information about the Loan Guarantee Agreement and related conditions.

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

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Any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and therefore on our financial condition and results of operations.

On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the $3.68 billion amount of its Guarantee Obligations, of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them over as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising remedies in respect of the Toshiba Guarantee, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.

On November 9, 2017, Toshiba released its financial results for the second quarter of fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.

In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to Department of Energy consents and related approvals under the Loan Guarantee Agreement and related agreements.

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

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.

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Item 6.    Exhibits

Number		Description
	4.1	Seventy-Fourth Supplemental Indenture, dated as of October 1, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2017A (Burke) Note, the Series 2017B (Burke) Note, the Series 2017A (Heard) Note and the Series 2017A (Monroe) Note.
	4.2	Seventy-Fifth Supplemental Indenture, dated as of October 18, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Amendment of the Original Indenture.
	4.3	Amendment, dated October 18, 2017, to Ninth Amended and Restated Loan Contract, dated as of September 2, 2014, between Oglethorpe and the United States of America.
	10.1	Agreement regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement and Amendment No. 4 to Plant Vogtle Owners Agreement Authorizing Development, Construction, Licensing and Operation of Additional Generating Units, dated as of November 2, 2017, by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton.
	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 13, 2017	By:	/s/ Michael L. Smith
		Michael L. Smith President and Chief Executive Officer
Date: November 13, 2017		/s/ Elizabeth B. Higgins
		Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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