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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~~2019
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 oý No ýo

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, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," ~~and~~ "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. ~~(Check one):~~
Large Accelerated Filero o Accelerated Filer o Non-Accelerated Filer ý ~~(Do not check if a smaller reporting company)~~ Smaller Reporting Company o Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class:		Trading Symbol(s)		Name of each exchange on which registered:

None		N/A		N/A

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

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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, ~~2017~~2019

		Page No.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of September 30, ~~2017~~2019 and December 31, ~~2016~~2018	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three and Nine Months ended September 30, ~~2017~~2019 and ~~2016~~2018	3
	Unaudited Consolidated Statements of ~~Comprehensive Margin~~Patronage Capital and Membership Fees For the Three and Nine Months ended September 30, ~~2017~~2019 and ~~2016~~2018	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~~2019 and ~~2016~~2018	65
	Notes to Unaudited Consolidated Financial Statements	76
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2528
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	3736
Item 4.	Controls and Procedures	3736
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	3837
Item 1A.	Risk Factors	3837
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4037
Item 3.	Defaults Upon Senior Securities	4037
Item 4.	Mine Safety Disclosures	4037
Item 5.	Other Information	4037
Item 6.	Exhibits	4138
SIGNATURES		4239

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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as ~~the timing of various regulatory and other actions,~~ future capital expenditures, business strategy, regulatory actions, 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~~2018 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;
•: a decision by Georgia Power Company to cancel the ~~results~~additional Vogtle units or a decision by more than 10% of ~~Westinghouse Electric Company LLC and WECTEC Global Project Services Inc.'s bankruptcy filing and any inability or failure by Toshiba Corporation~~the co-owners of the additional Vogtle units not to ~~perform its obligations pursuant to its settlement agreement related to its guarantee~~proceed with the construction of the additional Vogtle units upon the occurrence of certain ~~of Westinghouse's obligations related to the additional units at Plant Vogtle;~~material adverse events;
•: 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~~continued ability 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~~five-year period and the Department of Energy's decision to require such repayment;
•: the continued availability of funding from the Rural Utilities Service;
•: increasing debt caused by significant capital expenditures;
•: unanticipated changes in capital expenditures, operating expenses and liquidity needs;

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•: actions by credit rating agencies;
•: commercial banking and financial market conditions;
•: the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;

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•: 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;
•: the inability of counterparties to meet their obligations to us, including failure to perform under agreements;
•: litigation or legal and administrative proceedings and settlements;
•: our members' ability to perform their obligations to us;
•: our members' ability to offer their residential, commercial and industrial customers competitive rates;
•: changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;
•: 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.~~hazards; and
•: other factors discussed elsewhere in this quarterly report and in other reports we file with the SEC.

iii

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, ~~2017~~2019 and December 31, ~~2016~~2018


		(dollars in thousands)						(dollars in thousands)
	2017			2016			2019			2018
Assets
Electric plant:
In service	$	8,857,293		$	8,786,839		$	9,184,450		$	8,981,238
Right-of-use assets—finance leases								302,732			302,732
Less: Accumulated provision for depreciation		(4,260,047	)		(4,115,339	)		(4,805,514	)		(4,544,405	)

		4,597,246			4,671,500			4,681,668			4,739,565
Nuclear fuel, at amortized cost		360,529			377,653			351,874			358,358
Construction work in progress		3,824,068			3,228,214			4,515,150			3,866,042

Total electric plant		8,781,843			8,277,367			9,548,692			8,963,965

Investments and funds:
Nuclear decommissioning trust fund		427,786			386,029			483,235			420,818
Investment in associated companies		74,187			72,783			73,533			77,037
Long-term investments		125,518			99,874			208,024			164,125
Restricted investments		265,180			221,122			513,193			503,158
Other		21,689			20,730			24,996			24,259

Total investments and funds		914,360			800,538			1,302,981			1,189,397

Current assets:
Cash and cash equivalents		342,064			366,290			427,039			752,618
Restricted short-term investments		246,432			247,006			50,790			150,000
Receivables		180,250			155,042			158,451			153,647
Inventories, at average cost		263,226			259,831			272,353			259,087
Prepayments and other current assets		20,438			32,919			10,126			8,098

Total current assets		1,052,410			1,061,088			918,759			1,323,450

Deferred charges:
Regulatory assets		572,237			545,387			773,780			655,063
Prepayments to Georgia Power								40,346			29,459
Other		28,639			16,733			23,520			21,934

Total deferred charges		600,876			562,120			837,646			706,456

Total assets	$	11,349,489		$	10,701,113		$	12,608,078		$	12,183,268

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

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Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, ~~2017~~2019 and December 31, ~~2016~~2018


		(dollars in thousands)						(dollars in thousands)
	2017			2016			2019		2018
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	923,495		$	859,810		$	1,013,551	$	962,286
Accumulated other comprehensive margin		(352	)		(370	)

		923,143			859,440
Long-term debt		7,991,307			7,892,836			8,871,910		8,727,148
Obligation under capital lease		89,710			92,096
Obligation under finance leases								78,771		81,730
Other		19,725			18,765			24,977		21,428

Total capitalization		9,023,885			8,863,137			9,989,209		9,792,592

Current liabilities:
Long-term debt and capital lease due within one year		154,817			316,861
Long-term debt and finance leases due within one year								196,489		522,289
Short-term borrowings		631,949			102,168			560,671		—
Accounts payable		161,168			73,801			141,185		206,577
Accrued interest		84,287			93,634			67,118		60,971
Member power bill prepayments, current		43,836			176,988			107,695		224,957
Other current liabilities		54,621			59,979			72,960		49,465

Total current liabilities		1,130,678			823,431			1,146,118		1,064,259

Deferred credits and other liabilities:
Asset retirement obligations		726,074			698,051			1,057,560		1,017,563
Member power bill prepayments, non-current		202,202			48,115			77,614		54,750
Contract retainage		0			40,008
Regulatory liabilities		236,445			197,748			299,527		218,998
Other		30,205			30,623			38,050		35,106

Total deferred credits and other liabilities		1,194,926			1,014,545			1,472,751		1,326,417

Total equity and liabilities	$	11,349,489		$	10,701,113		$	12,608,078	$	12,183,268

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

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Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three and Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018

(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.~~

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~~Oglethorpe Power Corporation~~
~~Consolidated Statements of Comprehensive Margin (Unaudited)~~
~~For the Three and Nine Months Ended September 30, 2017 and 2016~~


		(dollars in thousands)									(dollars in thousands)
	Three Months					Nine Months				Three Months						Nine Months
	2017		2016			2017		2016		2019			2018			2019			2018
Operating revenues:
Sales to Members										$	382,548		$	384,529		$	1,097,754		$	1,123,741
Sales to non-Members											75			115			329			470

Total operating revenues											382,623			384,644			1,098,083			1,124,211

Operating expenses:
Fuel											138,704			151,903			349,146			394,494
Production											93,092			95,971			301,996			299,134
Depreciation and amortization											60,574			56,936			183,212			170,565
Purchased power											17,716			15,381			50,415			46,030
Accretion											13,328			9,608			36,361			28,364

Total operating expenses											323,414			329,799			921,130			938,587

Operating margin											59,209			54,845			176,953			185,624

Other income:
Investment income											14,144			15,242			45,129			43,925
Other											623			1,765			1,565			5,383

Total other income											14,767			17,007			46,694			49,308

Interest charges:
Interest expense											100,687			95,958			301,864			280,385
Allowance for debt funds used during construction											(47,909	)		(38,589	)		(138,246	)		(110,670	)
Amortization of debt discount and expense											2,912			3,149			8,764			9,198

Net interest charges											55,690			60,518			172,382			178,913

Net margin	$	20,805	$	18,630		$	63,685	$	62,505	$	18,286		$	11,334		$	51,265		$	56,019

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.

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Oglethorpe Power Corporation
Consolidated Statements of Patronage Capital and Membership Fees
~~and Accumulated Other Comprehensive (Deficit) Margin~~ (Unaudited)
For the Three and Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018


		(dollars in thousands)							(dollars in thousands)
	Patronage Capital and Membership Fees		Accumulated Other Comprehensive (Deficit) Margin			Total
Balance at December 31, 2015	$	809,465	$	58		$	809,523
Balance at December 31, 2017								$	911,087
Net margin									27,399

Components of comprehensive margin:
Balance at March 31, 2018								$	938,486
Net margin		62,505		—			62,505		17,285
Unrealized gain on available-for-sale securities		—		358			358

Balance at September 30, 2016	$	871,970	$	416		$	872,386
Balance at June 30, 2018								$	955,771
Net margin									11,335

Balance at September 30, 2018								$	967,106



Balance at December 31, 2016	$	859,810	$	(370	)	$	859,440
Balance at December 31, 2018								$	962,286
Net margin									23,596

Components of comprehensive margin:
Balance at March 31, 2019								$	985,882
Net margin		63,685		—			63,685		9,383
Unrealized gain on available-for-sale securities		—		18			18

Balance at September 30, 2017	$	923,495	$	(352	)	$	923,143
Balance at June 30, 2019								$	995,265
Net margin									18,286

Balance at September 30, 2019								$	1,013,551

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

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Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018


		(dollars in thousands)						(dollars in thousands)
	2017			2016			2019			2018
Cash flows from operating activities:
Net margin	$	63,685		$	62,505		$	51,265		$	56,019
							��
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel		279,898			268,674			281,049			277,209
Accretion cost		27,333			24,099			36,361			28,364
Amortization of deferred gains		(1,341	)		(1,341	)		(1,341	)		(1,341	)
Allowance for equity funds used during construction		(567	)		(567	)		(569	)		(708	)
Deferred outage costs		(32,777	)		(29,464	)		(26,925	)		(23,761	)
Gain on sale of investments		(16,478	)		(653	)
(Gain) loss on sale of investments								(4,611	)		3,886
Regulatory deferral of costs associated with nuclear decommissioning		631			(14,522	)		(17,686	)		(20,019	)
Other		(6,610	)		(4,424	)		(549	)		(4,564	)
Change in operating assets and liabilities:
Receivables		(24,650	)		(41,015	)		(1,706	)		(14,580	)
Inventories		(3,395	)		30,251			(13,238	)		16,209
Prepayments and other current assets		1,949			(1,305	)		(2,256	)		2,535
Accounts payable		68,585			(87,056	)		(60,068	)		(6,098	)
Accrued interest		(9,347	)		(966	)		6,147			1,298
Accrued taxes		7,249			5,348			34,435			12,312
Other current liabilities		(13,354	)		(20,604	)		(26,761	)		(11,743	)
Member power bill prepayments		20,935			32,809			(94,398	)		67,461
Other								37,982			10,866

Total adjustments		298,061			159,264			145,866			337,326

Net cash provided by operating activities		361,746			221,769			197,131			393,345

Cash flows from investing activities:
Property additions		(737,146	)		(421,384	)		(887,160	)		(852,225	)
Activity in nuclear decommissioning trust fund—Purchases		(329,248	)		(307,222	)		(281,821	)		(360,801	)
—Proceeds		323,840			302,308			275,545			354,897
Increase in restricted investments		(44,058	)		(66,821	)
Decrease in restricted short-term investments		574			3,519
Decrease in restricted investments								89,175			127,662
Activity in other long-term investments—Purchases		(45,246	)		(44,457	)		(165,743	)		(160,813	)
—Proceeds		27,196			35,278			134,907			135,673
Other		(12,780	)		2,401			(9,674	)		8,331

Net cash used in investing activities		(816,868	)		(496,378	)		(844,771	)		(747,276	)

Cash flows from financing activities:
Long-term debt proceeds		4,517			634,279			683,008			280,257
Long-term debt payments		(240,417	)		(113,328	)		(477,360	)		(117,684	)
Increase (decrease) in short-term borrowings, net		652,401			(105,225	)
Increase in short-term borrowings, net								124,044			505,397
Other		14,395			8,553			(7,631	)		6,180

Net cash provided by financing activities		430,896			424,279			322,061			674,150

Net (decrease) increase in cash and cash equivalents		(24,226	)		149,670			(325,579	)		320,219
Cash and cash equivalents at beginning of period		366,290			213,038			752,618			397,695

Cash and cash equivalents at end of period	$	342,064		$	362,708		$	427,039		$	717,914



Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	187,798		$	185,484		$	156,370		$	166,134
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	2,189		$	72,097		$	5,053		$	2,404
Change in accrued property additions	$	(21,904	)	$	(24,451	)
Accrued property additions at end of period							$	103,390		$	144,372
Interest paid-in-kind	$	42,555		$	34,587		$	55,767		$	44,040

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

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Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements

(A): General. The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three-month and nine-month periods ended September 30, ~~2017~~2019 and ~~2016.~~2018. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. Certain prior year amounts have been reclassified to conform with current year presentation.

These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016,~~2018, as filed with the SEC. The results of operations for the ~~three-month~~three- and nine-month periods ended September 30, ~~2017~~2019 are not necessarily indicative of results to be expected for the full year. As noted in our ~~2016~~2018 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~~2018 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

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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.~~

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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~~2019 and December 31, ~~2016.~~2018.

Fair Value Measurements at Reporting Date Using

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)

September 30,
2019

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

Significant Other
Observable
Inputs

(Level 2)

Significant
Unobservable
Inputs

(Level 3)

(dollars in thousands) (dollars in thousands)
Nuclear decommissioning trust funds:

Domestic equity
$ 138,008 $ 138,008 $ — $ 164,319 $ 164,319 $ — $ —
International equity trust
81,260 — 81,260 88,037 — 88,037 —
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 —
Corporate bonds and debt
62,039 — 62,039 —
US Treasury securities
53,744 53,744 — —
Mortgage backed securities
54,803 — 54,803 —
Domestic mutual funds
50,990 50,990 — —
Municipal bonds
301 — 301 1,237 — 1,237 —
Federal agency securities
2,197 — 2,197 —
Non-US Gov't bonds & private placements
272 — 272 —
Other
5,407 5,407 — 5,597 5,597 — —
Long-term investments:

International equity trust
20,712 — 20,712 21,190 — 21,190 —
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 —
Corporate bonds and debt
18,340 — 18,340 —
US Treasury securities
9,772 9,772 — —
Mortgage backed securities
13,246 — 13,246 —
Domestic mutual funds
94,772 94,772 — —
Federal agency securities
46 — 46 —
Treasury STRIPS
48,058 — 48,058 —
Other
1,198 1,199 — 2,600 2,600 — —
Natural gas swaps
807 — 807 26,379 — 26,379 —

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Fair Value Measurements at Reporting Date Using

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)

December 31,
2018

Quoted Prices in
Active Markets for
Identical Assets

(Level 1)

Significant Other
Observable
Inputs

(Level 2)

Significant
Unobservable
Inputs

(Level 3)

(dollars in thousands) (dollars in thousands)
Nuclear decommissioning trust funds:

Domestic equity
$ 170,408 $ 170,408 $ — $ 136,196 $ 136,196 $ — $ —
International equity trust
66,861 — 66,861 76,852 — 76,852 —
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
Corporate bonds and debt
51,356 — 48,853 2,503
US Treasury securities
47,712 47,712 — —
Mortgage backed securities
56,004 — 56,004 —
Domestic mutual funds
43,359 43,359 — —
Municipal bonds
943 — 943 278 — 278 —
Federal agency securities
6,066 — 6,066 —
Non-US Gov't bonds & private placements
964 — 964 —
Other
4,663 4,663 — 2,031 2,031 — —
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 17,382 — 17,382 —
Mutual funds
57,932 57,932 —
Corporate bonds and debt
12,571 — 11,366 1,205
US Treasury securities
12,062 12,062 — —
Mortgage backed securities
11,517 — 11,517 —
Domestic mutual funds
94,494 94,494 — —
Federal agency securities
941 — 941 —
Treasury STRIPS
14,113 — 14,113 —
Other
305 305 — 1,045 1,045 — —
Natural gas swaps
(15,090 ) — (15,090 ) 13,154 — 13,154 —

~~None~~The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of ~~our~~observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period.
The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchanged traded. Although these securities may be liquid and priced daily, their inputs are not observable.

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The following table presents the changes in Level 3 assets ~~or liabilities~~ measured at fair value on a recurring basis ~~were categorized as Level 3 at~~during the three and nine months ended September 30, ~~2017 or December 31, 2016.~~2019 and 2018.

Three Months Ended
September 30, 2019
Corporate bonds and debt

(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2019
$ —
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)
—
Liquidations
—

Balance at September 30, 2019
$ —

Nine Months Ended
September 30, 2019

Corporate bonds and debt

(dollars in thousands)
Assets (Liabilities):

Balance at December 31, 2018
$ 3,708
Total gains or losses (realized/unrealized):

Included in earnings (or changes in net assets)
94
Liquidations
(3,802 )

Balance at September 30, 2019
$ —

Three Months Ended
September 30, 2018

Corporate bonds and debt

(dollars in thousands)
Assets (Liabilities):

Balance at June 30, 2018
$ 4,997
Total gains or losses (realized/unrealized):

Included in earnings (or changes in net assets)
(656 )

Balance at September 30, 2018
$ 4,341

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Nine Months Ended
September 30, 2018

Corporate bonds and debt

(dollars in thousands)
Assets (Liabilities):

Balance at December 31, 2017
$ —
Transfers to Level 3
4,997
Total gains or losses (realized/unrealized):

Included in earnings (or changes in net assets)
(656 )

Balance at September 30, 2018
$ 4,341

The estimated fair values of our long-term debt, including current maturities at September 30, ~~2017~~2019 and December 31, ~~2016~~2018 were as follows (in thousands):

2017

2016

2019

2018

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

Long-term debt
$ 8,237,972 $ 9,119,700 $ 8,304,523 $ 9,043,029 $ 9,174,752 $ 10,976,451 $ 9,347,307 $ 9,837,254

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~~2019 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. ~~We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for similar loans.~~

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For cash and cash equivalents, 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.~~value because of the liquid nature of the deposits with the U.S. Treasury.
(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. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting ~~for any of these derivatives,~~to derivative transactions, but instead apply ~~regulatory~~regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows.

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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~~2019, 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.

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At September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, the estimated fair ~~value~~values of our natural gas contracts ~~was a~~were net ~~liability~~liabilities of approximately ~~$807,000~~$26,379,000 and ~~a net asset of $15,090,000,~~$13,154,000, respectively.
As of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, 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~~2019 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~~$26,379,000 with our counterparties.

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The following table reflects the notional volume ~~activity~~ of our natural gas derivatives as of September 30, ~~2017~~2019 that is expected to settle or mature each year:

Year

Natural Gas Swaps
(MMBTUs)
(in millions)

Natural Gas Swaps
(MMBTUs)
(in millions)

2017
3.8
2018
24.6
2019
18.7 3.5
2020
15.9 24.9
2021
12.9 22.0
2022
5.8 15.3
2023
10.2
2024
7.2

Total
81.7 83.1

~~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~~2019 and December 31, ~~2016.~~2018.

Balance Sheet
Location

Fair Value

Balance Sheet
Location

Fair Value

2017 2016 2019 2018

(dollars in thousands)

(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 Other current assets $ — $ 226
Liabilities:

Natural gas swaps
Other current liabilities $ — $ 54 Other current liabilities $ 10,435 $ 2,066
Natural gas swaps
Other deferred credits $ 4,109 $ 1,977 Other deferred credits $ 15,944 $ 11,314

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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~~2019 and ~~2016.~~2018.

Statement of
Revenues and
Expenses
Location Three months
ended
September 30, Nine months
ended
September 30,
Statement of
Revenues and
Expenses
Location

Three months
ended
September 30,

Nine months
ended
September 30,

2017

2016

2017

2016

2019

2018

2019

2018

(dollars in thousands) (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 )
Natural Gas Swaps gains
Fuel $ — $ 863 $ 224 $ 2,614
Natural Gas Swaps losses
Fuel (6,294 ) (97 ) (8,093 ) (956 )

$ 100 $ (3,884 ) $ 2,019 $ (16,205 )
Total
$ (6,294 ) $ 766 $ (7,869 ) $ 1,658

The following table presents the unrealized ~~gains and (losses)~~losses on derivative instruments deferred on the balance sheet at September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

Balance Sheet
Location

2017

2016

Balance Sheet Location

2019

2018

(dollars in thousands) (dollars in thousands)
Not designated as hedges:

Natural gas swaps
Regulatory asset $ (2,788 ) $ (62 ) Regulatory asset $ 26,379 $ 13,154
Natural gas swaps
Regulatory liability 1,981 15,152
Interest rate options
Regulatory asset — (5,788 )

Total not designated as hedges
$ (807 ) $ 9,302
Total
$ 26,379 $ 13,154

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(D)
Investments in Debt and Equity Securities.    Investment securities we hold are ~~classified as available-for-sale. Available-for-sale securities are carried~~recorded at ~~market~~fair value ~~with~~in the accompanying consolidated balance sheets. We apply regulated operations accounting to the 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~~all 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.securities. All realized and unrealized gains and losses are determined using the specific identification method. ~~As of~~At September 30, ~~2017~~2019, investments with a fair value of $22,298,000 were in an unrealized loss position for greater than one year and represented approximately ~~79%~~78% of ~~these~~our gross unrealized losses, ~~had been~~while investments with a fair value of $35,640,000 were in an unrealized loss position for less than one year. At December 31, 2018, investments with a ~~duration~~fair value of $49,975,000 were in an unrealized loss position for greater than one year and represented approximately 59% of our gross unrealized losses, while investments with a fair value of $148,638,000 were in an unrealized loss position for less than one year.
The following tables summarize ~~available-for-sale~~debt and equity securities as of September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

Gross Unrealized

Gross Unrealized

(dollars in thousands) (dollars in thousands)
September 30, 2017
Cost Gains Losses Fair
Value
September 30, 2019
Cost Gains Losses Fair
Value

Equity
$ 251,021 $ 75,181 $ (4,386 ) $ 321,816 $ 256,835 $ 114,881 $ (7,298 ) $ 364,418
Debt
224,458 2,194 (1,769 ) 224,883 309,021 10,185 (563 ) 318,643
Other
6,604 1 — 6,605 8,198 — — 8,198

Total
$ 482,083 $ 77,376 $ (6,155 ) $ 553,304 $ 574,054 $ 125,066 $ (7,861 ) $ 691,259

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Gross Unrealized

Gross Unrealized

(dollars in thousands) (dollars in thousands)
December 31, 2016
Cost Gains Losses Fair
Value
December 31, 2018
Cost Gains Losses Fair
Value

Equity
$ 237,317 $ 51,054 $ (5,041 ) $ 283,330 $ 251,226 $ 64,954 $ (9,105 ) $ 307,075
Debt
201,492 1,167 (3,423 ) 199,236 278,030 1,718 (4,955 ) 274,793
Other
3,339 — (2 ) 3,337 3,075 — — 3,075

Total
$ 442,148 $ 52,221 $ (8,466 ) $ 485,903 $ 532,331 $ 66,672 $ (14,060 ) $ 584,943

(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~~accounts for leases as finance leases or operating leases. ~~Both~~Accounting for both finance leases and operating leases ~~will result~~results in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee ~~would recognize~~recognizes interest expense and amortization of the ROU asset and for operating leases the lessee ~~would recognize~~recognizes a straight-line total lease expense. Quantitative and qualitative disclosures are required for significant judgments made by management. The new lease standard does not substantially change lessor accounting. ~~The~~We adopted 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.
January 1, 2019. For additional information, see Note G.
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. Early adoption is permitted. We ~~are currently evaluating~~continue to evaluate the future impact of this standard on our consolidated financial ~~statements.~~statements, however, we do not expect the impact to be material.

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In August ~~2016,~~2018, the FASB issued ~~"Statement~~"Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement." This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of ~~Cash Flows (Topic 230): Classification~~the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of ~~Certain Cash Receipts~~ and ~~Cash Payments."~~reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this ~~standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments~~update 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 usall entities for ~~annual reporting~~fiscal years, and interim periods within those fiscal years, beginning after December 15, ~~2017, and interim periods therein. Early adoption~~2019. An entity is permitted ~~including~~to early adopt any removed or modified disclosures upon issuance of this update and delay 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~~additional disclosures until their effective date.
As 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 methodstandard relates only 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 accordinglydisclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard.
(F)
~~Accumulated Comprehensive Margin.~~Revenue Recognition.    As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.
Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The ~~table below~~obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party.
Each of our members is obligated to pay us for capacity and energy we furnish under the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides ~~detail~~for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members.
The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the ~~beginning~~formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and ~~ending balance for each classification of~~income from other ~~comprehensive margin along with~~sources. Capacity revenues, therefore, vary to the ~~amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Consolidated Statements of Patronage Capital~~extent these components vary. Fixed costs include items such as fixed operation and ~~Membership Fees~~maintenance expenses, administrative 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 2016general expenses, depreciation and

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~~Form 10-K. Amounts reclassified~~interest. Year to ~~net margin~~year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the ~~table below~~associated revenue deferral plan as the expenses are ~~reflected~~recognized. For information regarding regulatory accounting, see Note J.
Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in ~~"Other income"~~a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract.
We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our ~~unaudited Consolidated Statements~~avoided cost of ~~Revenues~~borrowing. For additional information regarding our member prepayment program, see Note K.
We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and ~~Expenses.~~other seasonal factors, load requirements in our members' service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We provide approximately 60% of our members' energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon.
~~Our effective tax rate~~We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2019, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is ~~zero; therefore, all amounts below~~refunded to the members. Given that our capacity revenues are ~~presented net~~based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of ~~tax.~~the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of September 30, 2019 and September 30, 2018, we recognized refund liabilities totaling $7,700,000 and $20,000,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

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Sales to members for the three and nine months ended September 30, 2019 and 2018 were as follows:

Accumulated Other
Comprehensive
(Deficit) Margin Three Months Ended
September 30, Nine Months Ended
September 30,

Three Months Ended
September 30, 2016
(dollars in thousands)

(dollars in thousands)

Available-for-sale
Securities

2019

2018

2019

2018

Balance at June 30, 2016
$ 435
Unrealized gain

50
(Gain) reclassified to net margin

(69
)
Capacity revenues
$ 231,270 $ 219,597 $ 712,305 $ 691,649
Energy revenues
151,278 164,932 385,449 432,092

Balance at September 30, 2016
$ 416
Total
$ 382,548 $ 384,529 $ 1,097,754 $ 1,123,741

Member energy requirements supplied
57 % 57 % 56 % 58 %

Sales to non-members during the three and nine months ended September 30, 2019 and 2018 were insignificant.
Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members.
We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the nine months ended September 30, 2019 and September 30, 2018 were $12,368,000 and $7,897,000, respectively. The cumulative amount billed since inception of the program totaled $78,685,000.
In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the nine months ended September 30, 2019 and September 30, 2018 were $35,069,000 and $10,805,000, respectively. Funds collected through this program are invested and held until applied to members' bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills. The cumulative amount billed since inception of the program totaled $50,505,000.
(G)
Leases.    As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value.
On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. In addition, we elected the package of practical expedients permitted under the transition guidance, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. Adoption of the new leases

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standard resulted in recognition of right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000 for certain operating leases. The adoption of this standard did not materially impact our consolidated financial statements.
We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the nine months ended September 30, 2019 and September 30, 2018 was insignificant.
Finance Leases
Three of our finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to:
•
Renew the leases for a period of not less than one year and not more than five years at fair market value,

•
Purchase the undivided interest at fair market value, or

•
Redeliver the undivided interest to the lessors.
For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Amortization of the finance lease right-of-use assets is recorded to depreciation and amortization expense.
Operating Leases
Our operating leases have terms that extend through October 31, 2023. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through December 31, 2019 with renewal options for two additional twenty-year terms. We intend to exercise the option for one additional twenty-year term.
The exercise of renewal options for our finance and operating leases is at our sole discretion.
As all of our operating leases do not provide an implicit rate, we used our incremental borrowing rate based on the information available on January 1, 2019, the date of adoption of the new leases standard, in determining the present value of lease payments.

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For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components.

Classification

September 30,
2019

December 31,
2018

(dollars in thousands)
Right-of-Use Assets—Finance leases

Right-of-use assets
$ 302,732 $ 302,732
Less: Accumulated provision for depreciation
(256,186 ) (252,233 )

Total finance lease assets
$ 46,546 $ 50,499

Lease liabilities—Finance leases

Obligations under finance leases
$ 78,771 $ 81,730
Long-term debt and finance leases due within one year
5,763 5,462

Total finance lease liabilities
$ 84,534 $ 87,192

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 )
Classification

September 30,
2019

December 31,
2018

(dollars in thousands)
Right-of-Use Assets—Operating leases

Electric plant in service
$ 4,068 $ —

Total operating lease assets
$ 4,068 $ —

Lease liabilities—Operating leases

Capitalization—Other
$ 2,448 $ —
Other current liabilities
2,115 —

Total operating lease liabilities
$ 4,563 $ —

Three months ended

Nine months ended

Lease Cost

Classification

September 30,
2019

September 30,
2018

September 30,
2019

September 30,
2018

(dollars in thousands)

Finance lease cost:

Amortization of leased assets
Depreciation and amortization $ 1,189 $ 1,050 $ 3,567 $ 3,149
Interest on lease liabilities
Interest expense 2,372 2,512 7,116 7,534
Operating lease cost:
Inventory⁽¹⁾ & production expense 542 1,229 2,308 3,689

Total leased cost
$ 4,103 $ 4,791 $ 12,991 $ 14,372

⁽¹⁾
The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil inventories and are recognized in fuel expense as the inventories are consumed.

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Nine Months Ended
September 30, 2016
September 30,
2019

December 31,
2018

(dollars in thousands)

Available-for-sale
Securities

Lease Term and Discount Rate:

Weighted-average remaining lease term (in years)

Finance leases
9.08 9.82
Operating leases
5.72 N/A
Weighted-average discount rate

Finance leases
11.05 % 11.05 %
Operating leases
4.94 % N/A

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)

Nine months ended

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 )

September 30,
2019

September 30,
2018

(dollars in thousands)

Other Information:

Cash paid for amounts included in the measurement of lease liabilities

Operating cash flows from finance leases
$ 4,817 $ 10,302
Operating cash flows from operating leases
$ 2,602 $ —
Financing cash flows from finance leases
$ 2,658 $ 4,647
Right-of-use assets obtained in exchange for new operating lease liabilities

$
6,983
$
—

Maturity analysis of our finance and operating lease liabilities as of September 30, 2019 is a follows:

(dollars in thousands)

Year Ending December 31,

Finance Leases

Operating Leases

Total

2019
$ 7,475 $ 1,109 $ 8,584
2020
14,949 1,402 16,351
2021
14,949 798 15,747
2022
14,949 608 15,557
2023
14,949 386 15,335
Thereafter
70,481 1,157 71,638

Total lease payments
$ 137,752 $ 5,460 $ 143,212
Less: imputed interest
(53,218 ) (897 ) (54,115 )

Present value of lease liabilities
$ 84,534 $ 4,563 $ 89,097

As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases.

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Lease income recognized during the three and nine months ended September 30, 2019 and September 30, 2018 was as follows:

Three months ended
September 30,

Nine months ended
September 30,

2019

2018

2019

2018

(dollars in thousands)

Lease income
$ 1,514 $ 1,461 $ 4,554 $ 4,406

~~(G)~~(H)
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~~Environmental Matters.    ~~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~~may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon ~~dioxide, for certain new and modified facilities.~~dioxide.
~~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

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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 potential 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)~~(I)
Restricted Investments.    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit ~~Account.~~Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit currently earn interest at a rate of 5% per annum. Beginning October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At September 30, ~~2017~~

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2019 and December 31, ~~2016,~~2018, we had restricted investments totaling ~~$511,612,000~~$563,983,000 and ~~$468,179,000,~~$653,158,000, respectively, of which ~~$265,180,000~~$513,193,000 and ~~$221,122,000,~~$503,158,000, 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)~~(J)
Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our ~~members extending~~members. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, ~~2017~~2019 and December 31, ~~2016.~~2018.

2017

2016

2019

2018

(dollars in thousands)

(dollars in thousands)

Regulatory Assets:

Premium and loss on reacquired debt^(a)
$ 51,546 $ 55,084 $ 41,580 $ 46,315
Amortization on capital leases^(b)
33,454 32,274
Amortization of financing leases^(b)
35,304 34,918
Outage costs^(c)
42,060 39,986 36,272 36,352
Interest rate swap termination fees^(d)
2,231 3,570
Asset retirement obligations—Ashpond and other^(l)
59,540 33,747
Asset retirement obligations—Ashpond and other^(k)
258,227 137,835
Asset retirement obligations—Nuclear^(k)
— 7,031
Depreciation expense^(e)(d)
43,023 44,091 40,176 41,244
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs^(f)(e)
47,322 43,444 52,802 51,549
Interest rate options cost^(g)(f)
110,915 107,394 120,685 116,960
Deferral of effects on net margin—Smith Energy Facility^(h)(g)
167,941 172,399 156,051 160,509
Other regulatory assets^(m)
14,205 13,398 32,683 22,350

Total Regulatory Assets
$ 572,237 $ 545,387 $ 773,780 $ 655,063
Regulatory Liabilities:

Accumulated retirement costs for other obligations^(i)(h)
$ 14,235 $ 9,829 $ 14,092 $ 13,873
Deferral of effects on net margin—Hawk Road Energy Facility^(h)(g)
19,705 20,163 18,639 19,101
Major maintenance reserve^(j)(i)
43,269 28,379 46,907 45,547
Amortization on capital leases^(b)
20,780 23,084
Amortization of financing leases^(b)
14,981 17,156
Deferred debt service adder^(k)(j)
93,296 86,082 112,144 105,192
Asset retirement obligations^(l)
40,199 11,766
Asset retirement obligations—Nuclear^(k)
37,879 —
Revenue deferral plan^(l)
52,003 15,670
Other regulatory liabilities^(m)
4,961 18,445 2,882 2,459

Total Regulatory Liabilities
$ 236,445 $ 197,748 $ 299,527 $ 218,998

Net Regulatory Assets
$ 335,792 $ 347,639 $ 474,253 $ 436,065

^(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 2725 years.

^(b)
Represents the difference between expense recognized for rate-making purposes ~~and~~versus financial statement purposes related to ~~capital~~finance 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.~~periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 toor 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 Units No. 1 and No. 2, we deferred the difference between ~~Plant Vogtle~~the units' 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)(e)
Deferred charges consist of training related ~~to Vogtle Units No. 3~~costs, including interest 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)(f)
Deferral of ~~costs associated with~~premiums paid to purchase interest rate options ~~purchased~~used to hedge interest rates on certain borrowings, related tocarrying costs and other incidentals associated with construction of Vogtle Units ~~No.3~~No. 3 and ~~No.4 construction that~~No. 4. Amortization will ~~be amortized over~~commence in February 2020 and continue through February 2044, the life of the ~~associated debt.~~DOE-guaranteed loan which is financing a portion of the construction project.

^(h)(g)
Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.

^(i)(h)
Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.

^(j)(i)
Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.

^(k)(j)
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)(k)
Represents the difference in the timing of recognition of ~~the~~decommissioning costs ~~of decommissioning~~ for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for ~~ratemaking purposes.~~decommissioning.

^(l)
Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period.

^(m)
The amortization ~~period~~periods for other regulatory assets range up to 3331 years and the amortization ~~period~~periods of other regulatory liabilities range up to 108 years.

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~~(J)~~(K)
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,~~September 2024, with the majority of the balance scheduled to be credited by the end of 2019.
~~(K)~~(L)
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~~a Note Purchase Agreement, dated as of February 20, 2014 (the Original 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 in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB ~~Credit Facility~~ Documents). ~~The~~Following the bankruptcy of Westinghouse in 2017 (as described in Note M), we and the Department of Energy amended the loan guarantee agreement to restrict further advances pending the satisfaction of certain conditions, including an amendment to the loan guarantee agreement.
In September 2017, the Department of Energy issued a conditional commitment to us to guarantee an additional $1,619,679,706 of funding from the Federal Financing Bank. On March 7, 2019, we entered into an amendment and waiver of the loan guarantee agreement under which we received an advance of $585,000,000. On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167 and permits us to draw the remaining amount under the Original FFB ~~Credit Facility~~Notes. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents).
Together, the Original FFB Documents and Additional FFB 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~~are 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~~loan guarantee program (Eligible Project Costs). Borrowings under the ~~Facility~~Original FFB Notes 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. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in December 2017. Total borrowings under the Facility will not exceed $4,676,749,167.
At September 30, 2019, aggregate Department of Energy-guaranteed borrowings, including capitalized interest totaled $2,435,490,000. We have no amounts outstanding under the Additional FFB Note.

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Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event ~~the Department of Energy~~it is required to make any payments to the Federal Financing Bank under ~~the~~its 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 on all advances under the FFB Notes will begin on February 20, 2020. ~~Under both FFB Notes, the interest~~Interest rates on advances 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~~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

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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~~Original FFB Notes may be requested ~~under the Facility~~ on a quarterly basis through December 31, 2020. ~~The timing~~Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023, one year beyond the current anticipated commercial operation date of ~~satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. In addition to~~Vogtle Unit No. 4.
Future advances under the ~~conditions described above, future advances~~Facility are subject to satisfaction of customary conditions, ~~including~~as well as (i) certification of compliance with the requirements of the Title XVII ~~Loan Guarantee Program,~~loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, ~~our continued~~(iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of ~~our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under~~Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the ~~Loan Guarantee Agreement,~~Cargo Preference Act, as amended, (vi) evidence of compliance with the ~~prevailing~~applicable wage requirements of the Davis-Bacon Act, as amended, ~~and~~(vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse ~~eligible project costs.~~Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement.
We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed.
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~~If certain events occur, referred to as an "Alternate Amortization Event," at the Department of ~~Energy may require us~~Energy's option the Federal Financing Bank's commitment to ~~prepay~~make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all ~~guaranteed~~ borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, ~~(ii)~~(iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, ~~under~~(iv) termination of the ~~IP Licenses, (iii) a decision~~Services Agreement by ~~us not~~Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to ~~continue~~the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 ~~(iv) Georgia Power, on behalf~~coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners ~~fails~~ to ~~complete the Cost Assessments or~~ enter into a replacement

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contract with respect to the ~~Replacement EPC Arrangements by December 31, 2017, (v)~~Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, ~~(vi)~~(x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, ~~(vii)~~(xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, ~~(viii)~~(xii) change of control of Oglethorpe and ~~(ix)~~(xiii) 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 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~~2019, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling ~~$4,517,000~~$98,008,000 for long-term financing of general and

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environmental improvements at existing ~~plants.These advances are secured under our first mortgage indenture.~~plants.
OnIn October ~~30, 2017,~~2019, we received an additional ~~$17,582,000~~$17,344,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of 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)~~(M)
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 under construction 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. As of September 30, 2019, our total investment in the additional Vogtle units was approximately $4,621,837,000.
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~~, which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. ~~(WECTEC)~~(collectively, Westinghouse). Pursuant to the EPC Agreement, ~~the EPC Contractor~~Westinghouse 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~~Until March 2017, construction on Units No. 3 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~~No. 4 continued 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 thesubstantially fixed price EPC Agreement. ~~The~~In March 2017, 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 onEffective in 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~~Westinghouse entered into a services agreement ~~which was amended and restated on July 20, 2017~~ (the Services Agreement), ~~for the EPC Contractor~~pursuant to ~~transition construction management of Vogtle Units No. 3~~which Westinghouse is providing facility design and ~~No. 4 to Southern Nuclear~~engineering services, procurement and ~~to provide ongoing design, engineering,~~technical support 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~~staff augmentation on a time 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.~~materials cost basis. The Services Agreement ~~became effective upon approval by the Department of Energy on July 27, 2017 and~~provides that it 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.~~ Table of Contents
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~~pursuant to which Bechtel ~~will serve~~serves 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.~~4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel ~~will be~~is 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)~~and 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 applicable portion of 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,~~In April 2019, Georgia Power and Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the ~~Co-owners entered into an amendment to their joint ownership agreements~~total estimated project capital cost forecast for Vogtle Units No. 3 and No. ~~4 (as amended,~~4. Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance for funds used during construction, our allocation of the ~~Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant~~project-level contingency and a separate Oglethorpe-level contingency. There was also no change to the ~~Joint Ownership Agreements, the holders~~in-service dates of ~~at least 90% of the ownership interests in Vogtle Units~~November 2021 for Unit No. 3 and November 2022 for Unit 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 breachpreviously approved 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 following the validation process.
The current project-level budget includes an $800 million construction contingency estimate, of which our 30% interest is $240 million. As of September 30, 2019, approximately $67 million of this project-level contingency, or $20 million for our 30% interest, was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program and start-up; and procurement. Georgia Power ~~determines~~has stated that it anticipates allocating the remainder of this project-level contingency. The project-level contingency is separate and in addition to our Oglethorpe-level contingency.
As construction continues and testing and system turnover activities increase, risks remain that challenges with management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, particularly in the installation of electric and mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components or regional transmission upgrades, any of ~~Georgia Power's costs relating~~which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the approved in-service dates. To support that strategy, monthly production and activity targets will continue to increase significantly throughout the remainder of 2019 and into 2020. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers, particularly electrical and pipefitter craft labor, as well as additional supervision and other field support resources, must be retained and deployed.

Table 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.Contents
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.~~arise. 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~~submittal by Southern Nuclear of ~~Inspections, Tests, Analyses,~~the inspections, tests, analyses, and ~~Acceptance Criteria~~acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, 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.~~costs to the Co-owners.
AsThe Co-owners' joint ownership agreements, as amended, provide that the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, ~~continues,~~or can vote to suspend construction, if certain adverse events occur, including: (i) the ~~risk remains~~bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that ~~challenges with management~~any of ~~contractors, subcontractors~~Georgia Power's costs relating to the construction of Vogtle Units No. 3 and ~~vendors, labor productivity, fabrication, delivery, assembly,~~No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Joint Ownership Agreement provisions described above and ~~installation~~the first 6% of ~~plant systems, structures, and components,~~costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or ~~other issues could arise and may further impact project~~for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule ~~and cost.~~(each, a Project Adverse Event).
The ultimate outcome of these matters cannot be determined at this time. See Note 8 in Item 8—Notes to Audited Consolidated Financial Statements in our 2018 Form 10-K for additional information about Vogtle Units No. 3 and No. 4.

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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~~2019 and ~~2016~~2018
Net Margin
Our net margins for the three-month and nine-month periods ended September 30, ~~2017~~2019 were ~~$20.8~~$18.3 million and ~~$63.7~~$51.3 million, respectively, compared to ~~$18.6~~$11.3 million and ~~$62.5~~$56.0 million for the same periods of ~~2016. Through~~2018. For the nine-months ended September 30, ~~2017, we collected~~2019, our net margin was approximately ~~123%~~94% of our targeted net margin of ~~$51.7~~$54.8 million for the year ending December 31, ~~2017. These collections are typical~~2019. The targeted net margin for 2019 is based upon achieving a margins for interest ratio of 1.14 as ~~our capacity revenues are generally recorded evenly throughout the year and our management budgets conservatively. In September 2017,~~approved by our board of ~~directors approved a budget adjustment that reduced revenue requirements by $5.0 million in order to provide~~directors. To the extent our ~~members with a measure of relief for costs they incurred as a result of significant system damage from Hurricane Irma. We~~net margin exceeds the targeted net margin, we anticipate our board of directors will approve ~~an additional~~a budget adjustment by ~~the~~year end ~~of the year~~to reduce revenue requirements so ~~margins~~that net margin will achieve, but not exceed, the 2019 targeted net margin. Pursuant to Accounting Standards Codification 606, "Revenue from Contracts with Customers," we assessed our ~~2017~~projected net margin and annual revenue requirement to meet the targeted margins for interest ratio and recognized cumulative refund liabilities of ~~1.14.~~$7.7 million and $20.0 million as of September 30, 2019 and 2018, respectively. 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~~2018 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~~recognize for providing 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~~recognized when we deliver 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~~2019 and ~~2016~~2018 were as follows:

Three Months Ended
September 30, 2017 vs.
2016
% Change Nine Months Ended
September 30, 2017 vs.
2016
% Change
Three Months Ended
September 30, 2019 vs.
2018
% Change Nine Months Ended
September 30, 2019 vs.
2018
% Change

(dollars in thousands) (dollars in thousands) (dollars in thousands) (dollars in thousands)

2017

2016

2017

2016

2019

2018

2019

2018

Capacity revenues
$ 217,918 $ 228,011 (4.4%) $ 666,226 $ 681,384 (2.2%) $ 231,270 $ 219,597 5.3% $ 712,305 $ 691,649 3.0%
Energy revenues
167,840 202,872 (17.3%) 440,749 476,750 (7.6%) 151,278 164,932 (8.3%) 385,449 432,092 (10.8%)

Total
$ 385,758 $ 430,883 (10.5%) $ 1,106,975 $ 1,158,134 (4.4%) $ 382,548 $ 384,529 (0.5%) $ 1,097,754 $ 1,123,741 (2.3%)

MWh Sales to members
6,962,978 7,956,412 (12.5%) 18,213,379 19,886,944 (8.4%) 7,137,087 6,757,386 5.6% 17,672,935 17,784,450 (0.6%)
Cents/kWh
5.54 5.42 2.3% 6.08 5.82 4.4% 5.36 5.69 (5.8%) 6.21 6.32 (1.7%)
Member energy requirements supplied

62
%
64
%
(3.9%)

63
%
64
%
(1.3%)

57
%
57
%
0.0%

56
%
58
%
(3.4%)

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~~2019 compared to the same periods in ~~2016~~2018 primarily due to ~~a decrease in~~the recovery of fuel ~~costs which was largely a result of a decrease in generation for member sales in 2017.~~costs. For a discussion of fuel costs, which are the primary ~~components of~~costs recovered by 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
Cost Generation Cents per kWh

(dollars in thousands) (MWh) (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.

Three Months Ended
September 30,

2019 vs.

Three Months Ended
September 30,

2019 vs.

Three Months Ended
September 30,

2019 vs.

Fuel Source
2017 2016 2016
% Change 2017 2016 2016
% Change 2017 2016 2016
% Change
2019 2018 2018
%
Change 2019 2018 2018
%
Change 2019 2018 2018
%
Change

Coal
$ 30,924 $ 49,478 (37.5%) 1,157,960 1,704,203 (32.1%) 2.67 2.90 (8.0%) $ 24,095 $ 39,001 (38.2%) 821,069 1,360,086 (39.6%) 2.93 2.87 2.3%
Nuclear
23,249 21,950 5.9% 2,585,668 2,691,129 (3.9%) 0.90 0.82 10.2% 20,777 21,525 (3.5%) 2,591,374 2,558,186 1.3% 0.80 0.84 (4.7%)
Gas:

Combined Cycle
67,058 73,223 (8.4%) 2,888,612 2,976,562 (3.0%) 2.32 2.46 (5.6%) 60,549 60,411 0.2% 2,898,164 2,249,233 28.9% 2.09 2.69 (22.2%)
Combustion Turbine
22,536 33,865 (33.5%) 544,294 846,699 (35.7%) 4.14 4.00 3.5% 33,283 30,966 7.5% 987,319 787,768 25.3% 3.37 3.93 (14.2%)

$ 143,767 $ 178,516 (19.5%) 7,176,534 8,218,593 (12.7%) 2.00 2.17 (7.8%) $ 138,704 $ 151,903 (8.7%) 7,297,926 6,955,273 4.9% 1.90 2.18 (13.0%)

Cost Generation Cents per kWh
Cost Generation Cents per kWh

(dollars in thousands) (MWh) (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.

Nine Months Ended
September 30,

2019 vs.

Nine Months Ended
September 30,

2019 vs.

Nine Months Ended
September 30,

2019 vs.

Fuel Source
2017 2016 2016
% Change 2017 2016 2016
% Change 2017 2016 2016
% Change
2019 2018 2018
%
Change 2019 2018 2018
%
Change 2019 2018 2018
%
Change

Coal
$ 81,867 $ 114,961 (28.8%) 2,913,161 3,945,663 (26.2%) 2.81 2.91 (3.5%) $ 71,209 $ 88,563 (19.6%) 2,310,310 2,999,117 (23.0%) 3.08 2.95 4.4%
Nuclear
66,538 61,786 7.7% 7,399,354 7,605,266 (2.7%) 0.90 0.81 10.7% 58,666 64,007 (8.3%) 7,355,621 7,640,520 (3.7%) 0.80 0.84 (4.8%)
Gas:

Combined Cycle
181,254 165,272 9.7% 7,546,775 7,338,407 2.8% 2.40 2.25 6.6% 168,847 189,741 (11.0%) 7,013,337 6,538,930 7.3% 2.41 2.90 (17.0%)
Combustion Turbine
36,746 62,037 (40.8%) 881,514 1,644,184 (46.4%) 4.17 3.77 10.5% 50,424 52,183 (3.4%) 1,452,213 1,142,252 27.3% 3.47 4.57 (24.0%)

$ 366,405 $ 404,056 (9.3%) 18,740,804 20,533,520 (8.7%) 1.96 1.97 (0.6%) $ 349,146 $ 394,494 (11.5%) 18,131,481 18,320,819 (1.0%) 1.93 2.15 (10.6%)

Total fuel costs decreased for the three-month and nine-month periods ended September 30, ~~2017~~2019 compared to the same periods in 2018 as a result of lower natural gas prices, a shift in generation to relatively more economical natural gas-fired units, as well as scheduled plant outages. Partially offsetting the decreases for the comparable periods, were realized losses incurred for natural gas financial hedging contracts utilized for managing our exposure to fluctuations in market prices of natural gas. Generation increased approximately 5.0% for the three-month period ended September 30, 2019 compared to the same period in 2018 primarily due to warmer temperatures. For the nine-month period ended September 30, 2019 scheduled and unscheduled plant outages as well as milder weather in the first quarter of 2019 contributed to the decrease in generation.
Interest charges
Interest expense increased for the three-month and nine-month periods ended September 30, 2019 as compared to the same periods of ~~2016~~2018 primarily due to ~~a decrease~~increased long-term debt to finance construction of Vogtle Units No. 3 and No. 4.
Allowance for debt funds used during construction increased in ~~generation as a result of moderate temperatures. In addition, generation for~~ the three-month and nine-month ~~period~~periods ended September 30, ~~2017~~2019 as compared to the same ~~period~~periods of ~~2016 was somewhat affected by increased natural gas prices~~2018 primarily due to construction expenditures for Vogtle Units No. 3 and ~~planned maintenance outages during 2017.~~No. 4.

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Financial Condition
Balance Sheet Analysis as of September 30, ~~2017~~2019
Assets
Cash and cash equivalents decreased $325.6 million, primarily due to $350 million of first mortgage bonds which matured and were paid during the nine-month period ended September 30, 2019.
Cash used for property additions for the ~~nine-month~~ period ~~ended September 30, 2017~~ totaled ~~$737.1~~$887.2 million. Of this amount, ~~approximately $518.5~~$753.1 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 ~~$47.7~~and $44.2 million was for nuclear fuel ~~purchases and~~purchases. The remainder was for expenditures ~~for~~related to normal additions and replacements to our existing generation facilities.
The $62.4 million increase in the nuclear decommissioning trust fund was primarily due to an increase in unrealized investment gains.
Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. ~~The funds, including interest earned thereon,~~We can only ~~be applied to debt service on our~~utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank ~~notes. Decisions~~debt service payments. The program no longer allows additional funds to be deposited into the account. For the nine-month period ended September 30, 2019, we made $99.2 million of Federal Financing Bank debt service payments utilizing the Cushion of Credit Account. For additional information regarding ~~when~~restricted investments, see Note I of Notes to ~~apply~~Unaudited Consolidated Financial Statements.
Regulatory assets increased $118.7 million primarily as a result of the ~~funds are guided by the interest rate environment~~deferral of costs associated with asset retirement obligations for closure and post-closure of existing ash ponds at our ~~anticipated liquidity needs.~~

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Equity and Liabilities
Long-term debt increased ~~$98.5~~$144.8 million ~~during~~primarily as a result of $585 million advanced under the ~~nine-month period ended September 30, 2017 primarily due~~Department of Energy-guaranteed loan on March 15, 2019, which was utilized to repay a like amount of outstanding commercial paper. At December 31, 2018, the ~~classification of $122.6 million of~~outstanding commercial paper balance of $436.6 million was classified 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~~finance leases due within one year decreased ~~$162.0~~$325.8 million ~~during the nine-month period ended September 30, 2017. The decrease was~~ primarily due to ~~the redemption~~debt payments of ~~$122.6~~$350 million ~~of variable rate pollution control revenue~~for first mortgage bonds ~~through the issuance of commercial paper~~which matured 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.~~March 2019.
Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased ~~$529.8~~$560.7 million during the nine-month period ended September 30, ~~2017.~~2019. At December 31, 2018, all short-term borrowings were classified as long-term debt.
Accounts payable ~~increased $87.4~~decreased $65.4 million ~~for~~during the nine-month period ended September 30, ~~2017 primarily as a result~~2019. The decrease was largely due to the application 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$30.9 million in credits ~~applied~~ to our members' bills in the first quarter of ~~2017,~~2019 for a ~~board approved~~board-approved reduction in ~~2016~~2018 revenue ~~requirements as a result of margins~~ in excess of that required to meet the 2018 targeted net margin. In addition, a $25.5 million reduction in GPC payables and $24.6 million of property tax payments resulted in a decrease in the related payables. Slightly offsetting these decreases was an increase in payables for purchases of natural gas and related transportation.
Member power bill prepayments represent funds received from our ~~2016 target.~~
~~The current portion~~members for the prepayment of their monthly power bills. At September 30, 2019, $107.7 million of the member power bill prepayments ~~decreased $133.2~~were classified as a current liability and $77.6 million ~~for~~was classified as a long-term liability. During the ~~nine-month period~~nine-months ended September 30, ~~2017 due~~2019, we received $64.7 million of prepayments from members and we applied $159.1 million to ~~the application of credits against the~~our members' monthly power ~~bills of members that participate in~~bills. For information regarding 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 JK of Notes to Unaudited Consolidated Financial Statements.

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During the nine-months ended September 30, 2019, regulatory liabilities increased $80.5 million. Deferred asset retirement obligation liabilities increased $37.9 million due to an increase in unrealized gains on nuclear decommissioning funds. Also contributing to the increase, was $36.3 million in collections from our members that are being deferred under one of our rate management programs. The program is designed primarily as a mechanism to assist our members in managing rate impacts associated with the commercial operation of the new Vogtle units.
Capital Requirements and Liquidity and Sources of Capital
Vogtle Units No. 3 and No. 4
We, Georgia Power Company, 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 under construction 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. As of September 30, 2019, our total investment in the additional Vogtle units was $4.6 billion.
In ~~2008,~~April 2019, Georgia Power ~~acting for itself~~ and ~~as agent for the Co-owners, entered into an Engineering, Procurement~~Southern Nuclear completed a cost and ~~Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC~~schedule validation process to verify and ~~Stone & Webster, Inc. (collectively, the EPC Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name~~update quantities of commodities remaining to ~~WECTEC Global Project Services Inc. (WECTEC). Pursuant~~install, labor hours 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~~install remaining quantities and related ~~facilities at Plant Vogtle.~~

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~~Under~~productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the ~~EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments. The EPC Agreement also provided~~total estimated project capital cost forecast 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~~Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance 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,funds used during construction, our allocation of the ~~Co-owners for the removal of subcontractor liens~~project-level contingency 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~~separate Oglethorpe-level contingency. There was also no change 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~~in-service 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 Agreementpreviously approved 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 following the validation process.
The current project-level budget includes an $800 million construction contingency estimate, of which our 30% interest is $240 million. As of September 30, 2019, approximately $67 million of this project-level contingency, or $20 million for our 30% interest, was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program and start-up; and procurement. Georgia Power ~~determines~~has stated that it anticipates allocating the remainder of this project-level contingency. The project-level contingency is separate and in addition to our Oglethorpe-level contingency.
As construction continues and testing and system turnover activities increase, risks remain that challenges with management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, particularly in the installation of electrical and mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components or regional transmission upgrades, any of ~~Georgia Power's costs relating~~which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost.
The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the approved in-service dates. To support that strategy, monthly production and activity targets will continue to increase significantly throughout the remainder of 2019 and into 2020. To meet these increasing monthly targets, existing craft construction ~~of Vogtle Units No. 3~~productivity must improve 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.additional craft laborers,

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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~~particularly electrical and pipefitter craft labor, as ~~of April 21, 2006,~~well 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~~additional supervision and other field support resources, must 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,retained 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.~~deployed.
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.~~arise. 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~~submittal by Southern Nuclear of ~~Inspections, Tests, Analyses,~~the inspections, tests, analyses, and ~~Acceptance Criteria~~acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, 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.~~costs to the Co-owners.
~~As construction continues,~~In late 2018, the ~~risk remains~~first four nuclear units to utilize Westinghouse's AP1000 technology began commercial operation in China. One of the nuclear units experienced a failure of one of its reactor coolant pumps and is not operating pending replacement of the pump. There are four reactor coolant pumps at each unit. The other three nuclear units remain operational and we are not aware of any issues with the other fifteen pumps. The component manufacturer has completed a root-cause analysis of the reactor coolant pump failure and stated its conclusion that ~~challenges~~the failure was an isolated problem with ~~management of contractors, subcontractors~~a single part. Southern Nuclear and ~~vendors, labor productivity, fabrication, delivery, assembly,~~the Co-owners do not expect the issue in China related to the reactor coolant pump will impact the current November 2021 and ~~installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.~~November 2022 in service dates.
The ultimate outcome of these matters cannot be determined at this time. ~~See "Risk Factors" in this Form 10-Q for risks related to~~
For additional information regarding Vogtle Units No. 3 and No. 4, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" in our 2018 Form 10-K. For information regarding our financing of the ~~Guarantee Settlement Agreement~~additional Vogtle units, see "Financing Activities—Department of Energy-Guaranteed Loans" and Note L of Notes to Unaudited Consolidated Financial Statements. See "Item 1A—RISK FACTORS" in our ~~2016~~2018 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,~~July 8, 2019, the ~~U.S.~~ Environmental Protection Agency (EPA) ~~proposed~~published the final Affordable Clean Energy (ACE) rule. At the same time, in a ~~rule to~~separate and distinct action, EPA finalized its repeal of the Clean Power Plan ~~in its entirety on the basis~~(CPP), determining that the ~~Clean Power Plan exceeds~~CPP significantly exceeded the EPA's authority under the Clean Air Act. ~~Even though some portions~~The final ACE rule requires states to develop unit-specific standards of performance based on six candidate technologies for heat rate improvements, plus best operation and maintenance practices. The ACE rule addresses carbon dioxide emissions from coal plants and does not include natural gas-fired combustion turbines, including combined cycle units, as affected sources. We have ownership interests in two power plants with affected units and are currently analyzing the final rule to determine its potential impact on operations. The ultimate impact of the ACE 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~~depend on standards of performance set by Georgia, as well as 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~~associated legal challenges, and cannot ~~predict the outcome~~be determined at this time.

Table 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.Contents
For ~~further~~a discussion regarding potential effects on our business from other 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~~2018 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.~~10-K.
Liquidity
At September 30, ~~2017,~~2019, we had ~~$1.07~~$1.2 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included ~~$342~~$427 million in cash and cash equivalents and ~~$726~~$797 million ~~of unused and~~ available ~~committed credit arrangements.~~

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~~At September 30, 2017, we had $1.61~~under our $1.6 billion of committed credit arrangements, ~~in place,~~ the details of which are reflected in the table below:

Committed Credit Facilities
Committed Credit Facilities
Committed Credit Facilities

Authorized
Amount

Available
October 13, 2017

Expiration Date

Authorized
Amount

Available
September 30, 2019

Expiration
Date

(dollars in millions) (dollars in millions)
Unsecured Facilities:

Syndicated Line of Credit led by CFC
$ 1,210 $ 442 ⁽¹⁾ March 2020 $ 1,210 $ 513 ⁽¹⁾ March 2020⁽²⁾
CFC Line of Credit⁽²⁾⁽³⁾
110 110 December 2018 110 110 December 2023
JPMorgan Chase Line of Credit
150 34 ⁽³⁾ October 2018 150 34 ⁽⁴⁾ October 2021
Secured Facilities:

CFC Term Loan⁽²⁾⁽³⁾
250 140 ⁽²⁾ December 2018 140 140 ⁽³⁾ December 2023

Total
$ 1,610 $ 726

⁽¹⁾
Of the portion of this facility that was unavailable at ~~October 13, 2017, $632~~September 30, 2019, $561 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~~We anticipate renewing this facility in the fourth quarter of 2019.

⁽³⁾
Under the secured term loan with CFC, we can borrow up to $250 million. However, 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 authorized and 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⁾⁽⁴⁾
Of the portion of this facility that was unavailable at ~~October 13, 2017,~~September 30, 2019, $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~~We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, to support up to $1.0 billion of commercial paper ~~program~~and to issue letters of credit to third parties. We generally issue commercial paper to provide interim ~~funding for payments~~financing of our expenses related to the construction of Vogtle Units No. 3 and No. 4 ~~prior to receiving advances of~~which we repay with the proceeds from long-term funding ~~under~~sources. Our loan guaranteed by the Department of ~~Energy-guaranteed Federal Financing Bank loan.~~Energy is our preferred source of long-term financing of eligible costs for Vogtle Units No. 3 and No. 4. See Note KL 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~~additional information regarding 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.Energy-guaranteed loan.
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.~~2019. However, amounts related to issued letters of credit reduce the amount that would otherwise be

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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~~Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, ~~2017,~~2019, the required minimum level was ~~$675~~$750 million and our actual patronage capital was ~~$923 million.~~$1.0 billion. 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,~~2019, we had ~~$8.1~~$9.2 billion of secured indebtedness and ~~$756~~$560.7 million of unsecured indebtedness outstanding.
At September 30, ~~2017,~~2019, we had ~~$512~~$564.0 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~~Note I of ~~September 30, 2017—~~~~Assets~~"Notes to Unaudited Consolidated Financial Statements for ~~more~~additional information regarding this account.
Financing Activities
First Mortgage Indenture.    At September 30, ~~2017,~~2019, we had ~~$8.1~~$9.2 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our ~~2016~~2018 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans.    At September 30, ~~2017,~~2019, we had two approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bank totaling $1.1 billion that ~~are in various stages of being drawn down. These two loans totaled $678 million with $501~~have $676.3 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, ~~2017,~~2019, we had ~~$2.5~~$2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.
Department of Energy-Guaranteed ~~Loan.~~Loans.    In 2014, we ~~closed on~~entered into a loan guarantee agreement with the Department of Energy ~~that will~~to fund up to ~~the lesser~~$3.1 billion 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~~On March 22, 2019, we and the Department of Energy executed an amended and restated loan isguarantee agreement which increased the aggregate amount of the loan guarantee to $4.7 billion. These loans are being funded by the Federal Financing Bank and isare backed by a federal loan guarantee provided by the Department of Energy.
AsOn March 15, 2019, we received an advance of $585 million under the original loan. In conjunction with this advance, we repaid a like amount of outstanding commercial paper. At September 30, ~~2017,~~2019, aggregate Department of Energy-guaranteed borrowings under the original loan totaled $2.4 billion, including capitalized interest. In December 2019, we ~~had advanced $1.72~~expect to receive the final advance under the original loan in the amount of $567 million. We have no amounts outstanding under the additional loan.
With the additional loan, Department of Energy guaranteed-loans are expected to fund nearly $4.7 billion ~~under~~of the cost to construct the new Vogtle units. Combined, this ~~loan~~$4.7 billion and ~~had $1.34~~the $1.9 billion ~~remaining to be advanced.~~of debt we have raised in the capital markets represent long-term financing for more than 85% of our $7.5 billion project budget. 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 outstandingadvanced 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 beguarantee agreement is secured ratably with all other debt under our first mortgage indenture.
AsFor more information regarding the loan guarantee agreement, see Note L of ~~September 30, 2017, we had $980.8 million of outstanding obligations related~~Notes 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.
Unaudited Consolidated Financial Statements. For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our ~~2016~~2018 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" ofin our ~~2016~~2018 Form 10-K.
Item 4.    Controls and Procedures
As of September 30, ~~2017,~~2019, 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~~2019 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~~There have been no material changes ~~from~~to the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our ~~2016~~2018 Form 10-K.
Item 1A.    Risk Factors
~~Except as discussed below, there~~There have been no material changes from the risk factors disclosed in "Item 1A—RISK FACTORS" in our ~~2016~~2018 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~~31.1 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~~2019

By:

/s/ Michael L. Smith

Michael L. Smith
President and Chief Executive Officer

Date: November 13, ~~2017~~2019

/s/ Elizabeth B. Higgins

Elizabeth B. Higgins
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)



	Fair Value Measurements at Reporting Date Using						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)		September 30, 2019		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

		(dollars in thousands)						(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	138,008	$	138,008	$	—	$	164,319	$	164,319	$	—	$	—
International equity trust		81,260		—		81,260		88,037		—		88,037		—
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		—
Corporate bonds and debt								62,039		—		62,039		—
US Treasury securities								53,744		53,744		—		—
Mortgage backed securities								54,803		—		54,803		—
Domestic mutual funds								50,990		50,990		—		—
Municipal bonds		301		—		301		1,237		—		1,237		—
Federal agency securities								2,197		—		2,197		—
Non-US Gov't bonds & private placements								272		—		272		—
Other		5,407		5,407		—		5,597		5,597		—		—
Long-term investments:
International equity trust		20,712		—		20,712		21,190		—		21,190		—
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		—
Corporate bonds and debt								18,340		—		18,340		—
US Treasury securities								9,772		9,772		—		—
Mortgage backed securities								13,246		—		13,246		—
Domestic mutual funds								94,772		94,772		—		—
Federal agency securities								46		—		46		—
Treasury STRIPS								48,058		—		48,058		—
Other		1,198		1,199		—		2,600		2,600		—		—
Natural gas swaps		807		—		807		26,379		—		26,379		—



	Fair Value Measurements at Reporting Date Using								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)			December 31, 2018		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)

		(dollars in thousands)								(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	170,408		$	170,408	$	—		$	136,196	$	136,196	$	—	$	—
International equity trust		66,861			—		66,861			76,852		—		76,852		—
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
Corporate bonds and debt										51,356		—		48,853		2,503
US Treasury securities										47,712		47,712		—		—
Mortgage backed securities										56,004		—		56,004		—
Domestic mutual funds										43,359		43,359		—		—
Municipal bonds		943			—		943			278		—		278		—
Federal agency securities										6,066		—		6,066		—
Non-US Gov't bonds & private placements										964		—		964		—
Other		4,663			4,663		—			2,031		2,031		—		—
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			17,382		—		17,382		—
Mutual funds		57,932			57,932		—
Corporate bonds and debt										12,571		—		11,366		1,205
US Treasury securities										12,062		12,062		—		—
Mortgage backed securities										11,517		—		11,517		—
Domestic mutual funds										94,494		94,494		—		—
Federal agency securities										941		—		941		—
Treasury STRIPS										14,113		—		14,113		—
Other		305			305		—			1,045		1,045		—		—
Natural gas swaps		(15,090	)		—		(15,090	)		13,154		—		13,154		—



	Three Months Ended September 30, 2019
		Corporate bonds and debt

		(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2019	$	—
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		—
Liquidations		—

Balance at September 30, 2019	$	—



	Nine Months Ended September 30, 2019
		Corporate bonds and debt

		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2018	$	3,708
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		94
Liquidations		(3,802	)

Balance at September 30, 2019	$	—



	Three Months Ended September 30, 2018
		Corporate bonds and debt

		(dollars in thousands)
Assets (Liabilities):
Balance at June 30, 2018	$	4,997
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(656	)

Balance at September 30, 2018	$	4,341



	Nine Months Ended September 30, 2018
		Corporate bonds and debt

		(dollars in thousands)
Assets (Liabilities):
Balance at December 31, 2017	$	—
Transfers to Level 3		4,997
Total gains or losses (realized/unrealized):
Included in earnings (or changes in net assets)		(656	)

Balance at September 30, 2018	$	4,341



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

2017	3.8
2018	24.6
2019	18.7	3.5
2020	15.9	24.9
2021	12.9	22.0
2022	5.8	15.3
2023		10.2
2024		7.2

Total	81.7	83.1



	Balance Sheet Location		Fair Value			Balance Sheet Location		Fair Value

			2017		2016			2019		2018
			(dollars in thousands)					(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	Other current assets	$	—	$	226
Liabilities:
Natural gas swaps	Other current liabilities	$	—	$	54	Other current liabilities	$	10,435	$	2,066
Natural gas swaps	Other deferred credits	$	4,109	$	1,977	Other deferred credits	$	15,944	$	11,314



	Statement of Revenues and Expenses Location		Three months ended September 30,						Nine months ended September 30,					Statement of Revenues and Expenses Location		Three months ended September 30,						Nine months ended September 30,
			2017			2016			2017			2016				2019			2018			2019			2018

			(dollars in thousands)													(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	)
Natural Gas Swaps gains														Fuel	$	—		$	863		$	224		$	2,614
Natural Gas Swaps losses														Fuel		(6,294	)		(97	)		(8,093	)		(956	)

		$	100		$	(3,884	)	$	2,019		$	(16,205	)
Total															$	(6,294	)	$	766		$	(7,869	)	$	1,658



		Gross Unrealized									Gross Unrealized

		(dollars in thousands)									(dollars in thousands)
September 30, 2017		Cost		Gains		Losses			Fair Value
September 30, 2019											Cost		Gains		Losses			Fair Value

Equity	$	251,021	$	75,181	$	(4,386	)	$	321,816	$	256,835	$	114,881	$	(7,298	)	$	364,418
Debt		224,458		2,194		(1,769	)		224,883		309,021		10,185		(563	)		318,643
Other		6,604		1		—			6,605		8,198		—		—			8,198

Total	$	482,083	$	77,376	$	(6,155	)	$	553,304	$	574,054	$	125,066	$	(7,861	)	$	691,259



		Accumulated Other Comprehensive (Deficit) Margin		Three Months Ended September 30,						Nine Months Ended September 30,
		Three Months Ended September 30, 2016			(dollars in thousands)

		(dollars in thousands)
		Available-for-sale Securities			2019			2018			2019			2018

Balance at June 30, 2016	$	435
Unrealized gain		50
(Gain) reclassified to net margin		(69	)
Capacity revenues				$	231,270		$	219,597		$	712,305		$	691,649
Energy revenues					151,278			164,932			385,449			432,092

Balance at September 30, 2016	$	416
Total				$	382,548		$	384,529		$	1,097,754		$	1,123,741



Member energy requirements supplied					57	%		57	%		56	%		58	%



Classification		September 30, 2019			December 31, 2018

		(dollars in thousands)
Right-of-Use Assets—Finance leases
Right-of-use assets	$	302,732		$	302,732
Less: Accumulated provision for depreciation		(256,186	)		(252,233	)

Total finance lease assets	$	46,546		$	50,499

Lease liabilities—Finance leases
Obligations under finance leases	$	78,771		$	81,730
Long-term debt and finance leases due within one year		5,763			5,462

Total finance lease liabilities	$	84,534		$	87,192


		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	)
Classification					September 30, 2019		December 31, 2018

					(dollars in thousands)
Right-of-Use Assets—Operating leases
Electric plant in service				$	4,068	$	—

Total operating lease assets				$	4,068	$	—

Lease liabilities—Operating leases
Capitalization—Other				$	2,448	$	—
Other current liabilities					2,115		—

Total operating lease liabilities				$	4,563	$	—



			Three months ended				Nine months ended

Lease Cost	Classification		September 30, 2019		September 30, 2018		September 30, 2019		September 30, 2018

			(dollars in thousands)
Finance lease cost:
Amortization of leased assets	Depreciation and amortization	$	1,189	$	1,050	$	3,567	$	3,149
Interest on lease liabilities	Interest expense		2,372		2,512		7,116		7,534
Operating lease cost:	Inventory⁽¹⁾ & production expense		542		1,229		2,308		3,689

Total leased cost		$	4,103	$	4,791	$	12,991	$	14,372



		Nine Months Ended September 30, 2016		September 30, 2019		December 31, 2018

		(dollars in thousands)
		Available-for-sale Securities
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Finance leases				9.08		9.82
Operating leases				5.72		N/A
Weighted-average discount rate
Finance leases				11.05	%	11.05	%
Operating leases				4.94	%	N/A

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)			Nine months ended
		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	)

					September 30, 2019		September 30, 2018

					(dollars in thousands)
Other Information:
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from finance leases				$	4,817	$	10,302
Operating cash flows from operating leases				$	2,602	$	—
Financing cash flows from finance leases				$	2,658	$	4,647
Right-of-use assets obtained in exchange for new operating lease liabilities				$	6,983	$	—



		(dollars in thousands)

Year Ending December 31,		Finance Leases			Operating Leases			Total

2019	$	7,475		$	1,109		$	8,584
2020		14,949			1,402			16,351
2021		14,949			798			15,747
2022		14,949			608			15,557
2023		14,949			386			15,335
Thereafter		70,481			1,157			71,638

Total lease payments	$	137,752		$	5,460		$	143,212
Less: imputed interest		(53,218	)		(897	)		(54,115	)

Present value of lease liabilities	$	84,534		$	4,563		$	89,097




		Three Months Ended September 30,					2017 vs. 2016 % Change		Nine Months Ended September 30,					2017 vs. 2016 % Change		Three Months Ended September 30,					2019 vs. 2018 % Change		Nine Months Ended September 30,					2019 vs. 2018 % Change

		(dollars in thousands)							(dollars in thousands)							(dollars in thousands)							(dollars in thousands)
		2017			2016				2017			2016				2019			2018				2019			2018

Capacity revenues	$	217,918		$	228,011		(4.4%)	$	666,226		$	681,384		(2.2%)	$	231,270		$	219,597		5.3%	$	712,305		$	691,649		3.0%
Energy revenues		167,840			202,872		(17.3%)		440,749			476,750		(7.6%)		151,278			164,932		(8.3%)		385,449			432,092		(10.8%)

Total	$	385,758		$	430,883		(10.5%)	$	1,106,975		$	1,158,134		(4.4%)	$	382,548		$	384,529		(0.5%)	$	1,097,754		$	1,123,741		(2.3%)



MWh Sales to members		6,962,978			7,956,412		(12.5%)		18,213,379			19,886,944		(8.4%)		7,137,087			6,757,386		5.6%		17,672,935			17,784,450		(0.6%)
Cents/kWh		5.54			5.42		2.3%		6.08			5.82		4.4%		5.36			5.69		(5.8%)		6.21			6.32		(1.7%)
Member energy requirements supplied		62	%		64	%	(3.9%)		63	%		64	%	(1.3%)		57	%		57	%	0.0%		56	%		58	%	(3.4%)




		Cost				Generation			Cents per kWh				Cost				Generation			Cents per kWh

		(dollars in thousands)				(MWh)							(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.		Three Months Ended September 30,			2019 vs.	Three Months Ended September 30,		2019 vs.	Three Months Ended September 30,		2019 vs.

Fuel Source		2017		2016	2016 % Change	2017	2016	2016 % Change	2017	2016	2016 % Change		2019		2018	2018 % Change	2019	2018	2018 % Change	2019	2018	2018 % Change

Coal	$	30,924	$	49,478	(37.5%)	1,157,960	1,704,203	(32.1%)	2.67	2.90	(8.0%)	$	24,095	$	39,001	(38.2%)	821,069	1,360,086	(39.6%)	2.93	2.87	2.3%
Nuclear		23,249		21,950	5.9%	2,585,668	2,691,129	(3.9%)	0.90	0.82	10.2%		20,777		21,525	(3.5%)	2,591,374	2,558,186	1.3%	0.80	0.84	(4.7%)
Gas:
Combined Cycle		67,058		73,223	(8.4%)	2,888,612	2,976,562	(3.0%)	2.32	2.46	(5.6%)		60,549		60,411	0.2%	2,898,164	2,249,233	28.9%	2.09	2.69	(22.2%)
Combustion Turbine		22,536		33,865	(33.5%)	544,294	846,699	(35.7%)	4.14	4.00	3.5%		33,283		30,966	7.5%	987,319	787,768	25.3%	3.37	3.93	(14.2%)

	$	143,767	$	178,516	(19.5%)	7,176,534	8,218,593	(12.7%)	2.00	2.17	(7.8%)	$	138,704	$	151,903	(8.7%)	7,297,926	6,955,273	4.9%	1.90	2.18	(13.0%)



Committed Credit Facilities	Committed Credit Facilities							Committed Credit Facilities

			Authorized Amount		Available October 13, 2017		Expiration Date			Authorized Amount		Available September 30, 2019		Expiration Date

			(dollars in millions)							(dollars in millions)
*Unsecured Facilities:*
Syndicated Line of Credit led by CFC		$	1,210	$	442	⁽¹⁾	March 2020		$	1,210	$	513	⁽¹⁾	March 2020⁽²⁾
CFC Line of Credit⁽²⁾⁽³⁾			110		110		December 2018			110		110		December 2023
JPMorgan Chase Line of Credit			150		34	⁽³⁾	October 2018			150		34	⁽⁴⁾	October 2021
*Secured Facilities:*
CFC Term Loan⁽²⁾⁽³⁾			250		140	⁽²⁾	December 2018			140		140	⁽³⁾	December 2023

Total		$	1,610	$	726



~~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

Number			Description

	~~4.1~~31.1		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.


		Oglethorpe Power Corporation (An Electric Membership Corporation)
Date: November 13, ~~2017~~2019	By:	/s/ Michael L. Smith
		Michael L. Smith President and Chief Executive Officer
Date: November 13, ~~2017~~2019		/s/ Elizabeth B. Higgins
		Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)