Oglethorpe Power 10-K 29 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017
Document and Entity Information Abstract
Entity Registrant Name	OGLETHORPE POWER CORP
Entity Central Index Key	788,816
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Entity Common Stock, Shares Outstanding	0
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED STATEMENTS OF REVE

CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues:
Sales to Members	$ 1,433,830	$ 1,506,807	$ 1,219,052
Sales to non-Members	366	424	130,773
Total operating revenues	1,434,196	1,507,231	1,349,825
Operating expenses:
Fuel	473,184	513,258	441,738
Production	401,374	434,306	457,264
Depreciation and amortization	224,098	217,534	168,920
Purchased power	59,996	54,108	56,925
Accretion	36,674	32,361	26,108
Deferral of Hawk Road and Smith Energy Facilities effect on net margin			(58,588)
Total operating expenses	1,195,326	1,251,567	1,092,367
Operating margin	238,870	255,664	257,458
Other income:
Investment income	56,122	51,656	40,424
Amortization of deferred gains	1,788	1,788	1,788
Allowance for equity funds used during construction	784	788	675
Other	6,291	2,671	9,143
Total other income	64,985	56,903	52,030
Interest charges:
Interest expense	374,345	366,892	354,269
Allowance for debt funds used during construction	(134,319)	(116,634)	(108,667)
Amortization of debt discount and expense	12,552	11,964	15,545
Net interest charges	252,578	262,222	261,147
Net margin	$ 51,277	$ 50,345	$ 48,341

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN
Net margin	$ (12,408)	$ 20,805	$ 21,426	$ 21,454	$ (12,160)	$ 18,630	$ 23,277	$ 20,598	$ 51,277	$ 50,345	$ 48,341
Other comprehensive margin:
Unrealized loss on available-for-sale securities										(428)	(410)
Amounts reclassified to regulatory assets									370
Total comprehensive margin									$ 51,647	$ 49,917	$ 47,931

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Electric plant:
In service	$ 8,886,407	$ 8,786,839
Less: Accumulated provision for depreciation	(4,302,332)	(4,115,339)
Net in service	4,584,075	4,671,500
Nuclear fuel, at amortized cost	358,562	377,653
Construction work in progress	2,935,868	3,228,214
Total electric plant	7,878,505	8,277,367
Investments and funds:
Nuclear decommissioning trust fund	445,055	386,029
Investment in associated companies	74,981	72,783
Long-term investments	140,622	99,874
Restricted investments	653,585	221,122
Other	22,562	20,730
Total investments and funds	1,336,805	800,538
Current assets:
Cash and cash equivalents	397,695	366,290
Restricted short-term investments	229,324	247,006
Receivables	156,781	155,042
Inventories, at average cost	266,219	259,831
Prepayments and other current assets	18,884	32,919
Total current assets	1,068,903	1,061,088
Deferred charges and other assets:
Regulatory assets	585,084	545,387
Prepayments to Georgia Power Company	45,575	3,948
Other	13,267	12,785
Total deferred charges	643,926	562,120
Total assets	10,928,139	10,701,113
Capitalization:
Patronage capital and membership fees	911,087	859,810
Accumulated other comprehensive deficit		(370)
Long-term debt	7,927,562	7,892,836
Obligations under capital leases	87,192	92,096
Other	20,051	18,765
Total capitalization	8,945,892	8,863,137
Current liabilities:
Long-term debt and capital leases due within one year	216,694	316,861
Short-term borrowings	190,626	102,168
Accounts payable	212,868	73,801
Accrued interest	79,510	93,634
Member power bill prepayments, current	6,171	176,988
Other current liabilities	55,136	59,979
Total current liabilities	761,005	823,431
Deferred credits and other liabilities:
Asset retirement obligations	734,997	698,051
Member power bill prepayments, non-current	203,615	48,115
Contract retainage		40,008
Regulatory liabilities	251,649	197,748
Other	30,981	30,623
Total deferred credits and other liabilities	1,221,242	1,014,545
Total equity and liabilities	10,928,139	10,701,113
Commitments and Contingencies (Notes 1, 7, 10, 11 and 12)

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Secured Long-term debt:
Total Secured Long-term, debt	$ 8,232,703	$ 8,304,523
Obligations under capital leases	94,358	98,531
Obligation under Rocky Mountain transactions	20,051	18,765
Patronage capital and membership fees	911,087	859,810
Accumulated other comprehensive (deficit)		(370)
Subtotal	9,258,199	9,281,259
Less: long-term debt and capital leases due within one year	(216,694)	(316,861)
Less: unamortized debt issuance costs	(87,802)	(93,133)
Less: unamortized bond discounts on long-term debt	(7,811)	(8,128)
Total capitalization	8,945,892	8,863,137
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043
Secured Long-term debt:
Debt Instrument Principal Outstanding	2,456,864	2,581,281
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044
Secured Long-term debt:
Debt Instrument Principal Outstanding	1,735,586	1,678,442
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020
Secured Long-term debt:
Debt Instrument Principal Outstanding	2,411	3,347
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035
Secured Long-term debt:
Debt Instrument Principal Outstanding	300,000	300,000
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031
Secured Long-term debt:
Debt Instrument Principal Outstanding	500,000	500,000
Public | First mortgage bonds payable: Series 2009A First Mortgage Bonds, 6.10%, due 2019
Secured Long-term debt:
Debt Instrument Principal Outstanding	350,000	350,000
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039
Secured Long-term debt:
Debt Instrument Principal Outstanding	400,000	400,000
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024
Secured Long-term debt:
Debt Instrument Principal Outstanding	7,072	8,083
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040
Secured Long-term debt:
Debt Instrument Principal Outstanding	450,000	450,000
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050
Secured Long-term debt:
Debt Instrument Principal Outstanding	300,000	300,000
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042
Secured Long-term debt:
Debt Instrument Principal Outstanding	250,000	250,000
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044
Secured Long-term debt:
Debt Instrument Principal Outstanding	250,000	250,000
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046
Secured Long-term debt:
Debt Instrument Principal Outstanding	250,000	250,000
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2003A Burke, Heard, Monroe and 2003B Burke Auction rate bonds, fully redeemed January 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		95,230
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2004 Burke and Monroe Auction rate bonds, fully redeemed January 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		11,525
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2005 Burke and Monroe Auction rate bonds, fully redeemed January 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		15,865
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008A through 2008C Burke Fixed rate bonds, 5.30% to 5.70%, fully defeased December 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		255,035
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008E Burke Fixed rate bonds, 7.00%, fully defeased December 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		144,750
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2009A Heard and Monroe, and 2009B Monroe Weekly rate bonds, 1.65% to 1.75%, due 2030 through 2038
Secured Long-term debt:
Debt Instrument Principal Outstanding	112,055	112,055
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke Weekly rate bonds, 1.70% to 1.72%, due 2036 through 2037
Secured Long-term debt:
Debt Instrument Principal Outstanding	133,550	133,550
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2013A Appling, Burke and Monroe Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040
Secured Long-term debt:
Debt Instrument Principal Outstanding	212,760	212,760
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A Burke, Heard, Monroe and 2017B Burke Indexed put bonds - weekly reset, 2.56% due 2040 through 2045
Secured Long-term debt:
Debt Instrument Principal Outstanding	122,620
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke Indexed put bonds - monthly reset, 1.69% due 2041 through 2045
Secured Long-term debt:
Debt Instrument Principal Outstanding	200,000
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 E, F Burke Indexed put bonds - weekly reset, 2.56% due 2041 through 2045
Secured Long-term debt:
Debt Instrument Principal Outstanding	$ 199,785
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable, paid in full January 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		419
CoBank | ACB notes payable: Transmission first mortgage notes payable: variable, paid in full January 2017
Secured Long-term debt:
Debt Instrument Principal Outstanding		$ 2,181

CONSOLIDATED STATEMENTS OF CAP6

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical)	Dec. 31, 2017
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043
Secured Long-term debt:
Interest rate, average rate (as a percent)	4.02%
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	1.84%
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.84% to 8.43% (average rate of 4.02% at December 31, 2017) due in quarterly installments through 2043 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	8.43%
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044
Secured Long-term debt:
Interest rate, average rate (as a percent)	3.36%
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	2.51%
Federal Financing Bank | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 2.51% to 3.87% (average rate of 3.36% at December 31, 2017) due in quarterly installments through 2044 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	3.87%
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020
Secured Long-term debt:
Interest rate, average rate (as a percent)	4.69%
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	4.55%
National Rural Utilities Cooperative Finance Corporation | First mortgage notes payable to National Rural Utilities Cooperative Finance Corporation at interest rates varying from 4.55% to 4.90% (average rate of 4.69% at December 31, 2017) due in quarterly installments through 2020 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	4.90%
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035
Secured Long-term debt:
Interest rate (as a percent)	5.534%
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031
Secured Long-term debt:
Interest rate (as a percent)	6.191%
Public | First mortgage bonds payable: Series 2009A First Mortgage Bonds, 6.10%, due 2019
Secured Long-term debt:
Interest rate (as a percent)	6.10%
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039
Secured Long-term debt:
Interest rate (as a percent)	5.95%
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024
Secured Long-term debt:
Interest rate (as a percent)	1.81%
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040
Secured Long-term debt:
Interest rate (as a percent)	5.375%
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050
Secured Long-term debt:
Interest rate (as a percent)	5.25%
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042
Secured Long-term debt:
Interest rate (as a percent)	4.20%
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044
Secured Long-term debt:
Interest rate (as a percent)	4.55%
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046
Secured Long-term debt:
Interest rate (as a percent)	4.25%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008A through 2008C Burke Fixed rate bonds, 5.30% to 5.70%, fully defeased December 2017 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	5.30%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008A through 2008C Burke Fixed rate bonds, 5.30% to 5.70%, fully defeased December 2017 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	5.70%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2008E Burke Fixed rate bonds, 7.00%, fully defeased December 2017
Secured Long-term debt:
Interest rate (as a percent)	7.00%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2009A Heard and Monroe, and 2009B Monroe Weekly rate bonds, 1.65% to 1.75%, due 2030 through 2038 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	1.65%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2009A Heard and Monroe, and 2009B Monroe Weekly rate bonds, 1.65% to 1.75%, due 2030 through 2038 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	1.75%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke Weekly rate bonds, 1.70% to 1.72%, due 2036 through 2037 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	1.70%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2010A Burke and Monroe, and 2010B Burke Weekly rate bonds, 1.70% to 1.72%, due 2036 through 2037 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	1.72%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2013A Appling, Burke and Monroe Term rate bonds, 2.40% through April 1, 2020, due 2038 through 2040
Secured Long-term debt:
Interest rate (as a percent)	2.40%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A Burke, Heard, Monroe and 2017B Burke Indexed put bonds - weekly reset, 2.56% due 2040 through 2045
Secured Long-term debt:
Interest rate (as a percent)	2.56%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke Indexed put bonds - monthly reset, 1.69% due 2041 through 2045
Secured Long-term debt:
Interest rate (as a percent)	1.69%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 E, F Burke Indexed put bonds - weekly reset, 2.56% due 2041 through 2045
Secured Long-term debt:
Interest rate (as a percent)	2.56%

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net margin	$ 51,277	$ 50,345	$ 48,341
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	374,411	362,716	313,320
Accretion cost	36,674	32,361	26,108
Amortization of deferred gains	(1,788)	(1,788)	(1,788)
Allowance for equity funds used during construction	(784)	(788)	(675)
Deferred outage costs	(40,644)	(40,599)	(40,803)
Deferral of Hawk Road and Smith Energy Facilities effect on net margin			(58,588)
(Gain) loss on sale of investments	(18,614)	96	(34,464)
Regulatory deferral of costs associated with nuclear decommissioning	(2,605)	(20,440)	21,532
Other	(9,240)	(7,286)	(8,353)
Change in operating assets and liabilities:
Receivables	(1,182)	(24,578)	(98)
Inventories	(6,388)	23,947	(28,403)
Prepayments and other current assets	614	(2,172)	(4,317)
Accounts payable	129,187	(76,495)	(37,155)
Accrued interest	(14,124)	34,804	(11)
Accrued and withheld taxes	(1,531)	1,102	3,731
Other current liabilities	(8,646)	(11,937)	2,805
Member power bill prepayments	(15,317)	6,155	20,994
Total adjustments	420,023	275,098	173,835
Net cash provided by operating activities	471,300	325,443	222,176
Cash flows from investing activities:
Property additions	(1,019,695)	(613,019)	(495,426)
Guarantee settlement proceeds	1,104,000
Activity in nuclear decommissioning trust fund - Purchases	(450,113)	(395,506)	(558,568)
Activity in nuclear decommissioning trust fund - Proceeds	442,989	389,011	553,654
Increase in restricted investments	(432,463)	(86,432)	(16,301)
Decrease (increase) in restricted short-term investments	17,682	6,198	(6,076)
Activity in other long-term investments - Purchases	(108,704)	(61,200)	(89,263)
Activity in other long-term investments - Proceeds	78,356	50,529	86,563
Other	(43,056)	13,554	(13,068)
Net cash used in investing activities	(411,004)	(696,865)	(538,485)
Cash flows from financing activities:
Long-term debt proceeds	544,503	790,385	423,637
Long-term debt payments	(677,641)	(114,702)	(162,903)
Increase (decrease) in short-term borrowings, net	88,458	(159,310)	27,109
Other	15,789	8,301	4,113
Net cash (used in) provided by financing activities	(28,891)	524,674	291,956
Net increase (decrease) in cash and cash equivalents	31,405	153,252	(24,353)
Cash and cash equivalents at beginning of period	366,290	213,038	237,391
Cash and cash equivalents at end of period	397,695	366,290	213,038
Cash paid for -
Interest (net of amounts capitalized)	251,186	212,574	240,817
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	2,414	63,011	144,161
Change in accrued property additions	(28,457)	(50,775)	119,775
Interest paid-in-kind	$ 57,144	$ 47,814	$ 36,021

CONSOLIDATED STATEMENTS OF PATR

CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND ACCUMULATED OTHER COMPREHENSIVE (DEFICIT) MARGIN - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Members' Capital
Balance		$ 859,440		$ 809,523	$ 859,440	$ 809,523	$ 761,592
Components of comprehensive margin:
Net margin	$ (12,408)	21,454	$ (12,160)	20,598	51,277	50,345	48,341
Unrealized loss on available-for-sale securities						(428)	(410)
Amounts reclassified to regulatory assets					370
Total comprehensive margin					51,647	49,917	47,931
Balance	911,087		859,440		911,087	859,440	809,523
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Balance		859,810		809,465	859,810	809,465	761,124
Components of comprehensive margin:
Net margin					51,277	50,345	48,341
Balance	$ 911,087		859,810		911,087	859,810	809,465
Accumulated Other Comprehensive (Deficit) Margin
Increase (Decrease) in Members' Capital
Balance		$ (370)		$ 58	(370)	58	468
Components of comprehensive margin:
Unrealized loss on available-for-sale securities						(428)	(410)
Amounts reclassified to regulatory assets					$ 370
Balance			$ (370)			$ (370)	$ 58

Summary of significant accounti

Summary of significant accounting policies:	12 Months Ended
	Dec. 31, 2017
Summary of significant accounting policies:
Summary of significant accounting policies:	1. Summary of significant accounting policies: a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,115 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 728 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 119 megawatts of capacity, including 86 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.1 million people. b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2017 and 2016 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2017. Actual results could differ from those estimates. Certain fair value hierarchy disclosures have been revised to conform to the current period classification. Securities previously classified as "US Treasury and government agency securities" under Level 1 in the fair value hierarchy totaling $37,884,000 as of December 31, 2016 in the fair value table of Note 2 are now presented under Level 2 as "Mortgage backed securities" and "Federal agency securities." These changes do not impact the investment portfolio or the fair value of the assets that are recorded in the financial statements. c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities. d. Margin policy 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 the years 2017, 2016 and 2015, we achieved a margins for interest ratio of 1.14. e. Operating revenues Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded in approximately equal amounts throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred. Prior to 2016, operating revenues from sales to non-members consisted primarily of energy sales at Smith. The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2017, 2016 or 2015: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jackson EMC % % % Cobb EMC % % % Sawnee EMC n/a % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have a rate management program that allows us to expense and recover certain 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 in 2017, 2016 and 2015 were $11,000,000, $16,096,000 and $7,630,000, respectively. The cumulative amount billed since inception of the program totaled $54,087,000. Prior to 2016, members also subscribed to the Smith program, which allowed for the accelerated recovery of deferred net costs related to Smith. The Smith program ceased as of December 31, 2015 when the plant became available for scheduling to our members. The amount billed to participating members under this program in 2015 was $17,745,000 and the cumulative amount billed since inception totaled $58,922,000. f. Receivables A substantial portion of our receivables are related to electricity sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Member receivables at December 31, 2017 and 2016 were $126,211,000 and $136,552,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible. g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2017, 2016 and 2015 amounted to $90,520,000, $83,751,000, and $78,762,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On October 10, 2017, Georgia Power, as agent for the co-owners filed a separate claim seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering a period from January 1, 2015 through December 31, 2017. In addition, Georgia Power previously filed a separate claim to cover periods January 1, 2011 through December 31, 2013 which was subsequently amended and extended through December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts were recognized in the financial statements as of December 31, 2017 for this claim. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant. h. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to coal ash ponds, gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2015 and 2016, respectively. The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2017 and 2016. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ Liabilities settled ) ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2017 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ Liabilities settled – ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. The estimated costs of decommissioning are based on the most current study performed in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase in the cash flow estimates in 2015 was primarily attributable to security costs, waste disposal costs and inflation, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Hatch Vogtle Vogtle ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. Coal Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Our most current assessment of the final CCR rule resulted in a $1,604,000 change in cash flow estimates for coal ash pond decommissioning. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The 2017 and 2016 increases in cash flow estimates were primarily attributed to an increase in the closure cost estimates. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule, including potential changes, on our estimates and assumptions. Other. Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q. i. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2017 and 2016, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund, which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheet. In both 2017 and 2016, we contributed $4,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2017 and December 31, 2016. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2017 and 2016. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 External Trust Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) $ Other ) – $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $31,939,680. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2016 External Trust Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) ) $ Other ) ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (2) Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $12,270,144. Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. The nuclear decommissioning trust fund has produced an average annualized return of approximately 6.4% in the last ten years and 6.3% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates. j. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use standard depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The 2017 and 2016 depreciation rates for steam and nuclear production in the table below reflect revised rates from depreciation rate studies completed in 2015. Site specific depreciation studies are performed every five years. Annual depreciation rates in effect in 2017, 2016 and 2015 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2017. Depreciation expense for the years 2017, 2016 and 2015 was $218,027,000, $211,282,000, and $180,866,000, respectively. k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ended 2017, 2016 and 2015, the allowance for funds used during construction rates were 4.45%, 4.61% and 4.73%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants. l. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments. m. Restricted investments Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At December 31, 2017 and 2016, we had restricted investments totaling $882,909,000 and $468,179,000, respectively, of which $653,585,000 and $221,122,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank. n. Inventories We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost. The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed. At December 31, 2017 and December 31, 2016, fossil fuels inventories were $54,050,000 and $57,289,000, respectively. Inventories for spare parts at 2017 and 2016 were $212,169,000 and $202,542,000, respectively. o. Deferred charges and other assets Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages. For a discussion regarding regulatory assets, see Note 1q. p. Deferred credits and other liabilities 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 monthly and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2023, with the majority of the balance scheduled to be credited by the end of 2019. During 2016, in connection with the Vogtle Units No. 3 and No. 4 construction project, we were accruing long-term contract retainage amounts for substantial and mechanical milestones. As a result of a settlement agreement entered into by Georgia Power Company and the Co-owners and Toshiba in June 2017, these contract retainage amounts were reversed. For more information regarding the Vogtle construction project, see Note 8. q. Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members, which 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 members. ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Asset Retirement Obligations – Ashpond and other (k) Depreciation expense (d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) Interest rate options cost (f) Deferral of effects on net margin – Smith Energy Facility (g) Other regulatory assets (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (g) Major maintenance reserve (i) Amortization on capital leases (b) Deferred debt service adder (j) Asset retirement obligations – Nuclear (k) Other regulatory liabilities (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (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 26 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over 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 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (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. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (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. (k) Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes. (l) The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years. r. Related parties We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities. For 2017, 2016, and 2015, we incurred expenses from Georgia Transmission of $28,410,000, $27,399,000, and $28,172,000, respectively. We, Georgia Transmission and 38 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2017, 2016, and 2015, we incurred expenses from Georgia Systems Operations of $25,597,000, $23,994,000, and $22,616,000, respectively. s. Other income The components of other income within the Consolidated Statement of Revenues and Expenses were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ t. New accounting pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 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). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption. The adoption of this standard is not expected to have a material impact, on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was 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. The vast majority of our revenue 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. Historically, our Board has approved budget adjustments, typically at year end but may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. 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

Fair Value_

Fair Value:	12 Months Ended
	Dec. 31, 2017
Fair Value:
Fair Value:	2. Fair Value: Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at December 31, 2017 or December 31, 2016. 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2017 Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Domestic mutual funds $ – Municipal bonds $ – Federal agency securities $ – Other $ – Long-term investments: International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Dometic mutual funds $ – Federal agency securities $ – Other $ – Natural gas swaps $ – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2016 Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Municipal bonds $ – Federal agency securities $ – Other $ – Long-term investments: International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Domestic mutual funds $ – Federal agency securities $ – Other $ – Natural gas swaps $ ) – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a three-day redemption notice period. The estimated fair values of our long-term debt, including current maturities at December 31, 2017 and 2016 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 Carrying Fair Carrying Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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). 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 December 31, 2017 and 2016 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. For cash and cash equivalents and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. As discussed in Note 1m, restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The carrying amount approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

Derivative instruments_

Derivative instruments:	12 Months Ended
	Dec. 31, 2017
Derivative instruments:
Derivative instruments:	3. Derivative instruments: Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of December 31, 2017 all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. Gas hedges. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. At December 31, 2017 and 2016, the estimated fair value of our natural gas contracts were a net liability of $6,328,000 and a net asset of $15,090,000, respectively. As of December 31, 2017 and 2016, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2017 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit of approximately $6,328,000 with our counterparties. The following table reflects the volume activity of our natural gas derivatives as of December 31, 2017 that is expected to settle or mature each year: ​ ​ ​ ​ ​ Year Natural Gas (in millions) ​ ​ ​ ​ ​ 2018 2019 2020 2021 2022 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ 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 expected to incur through March 2017 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. In accordance with rate-making treatment, we deferred the premiums paid to purchase these swaptions and related carrying costs, and will continue to defer other incidentals. The deferral will continue and costs will be amortized and collected in rates from February 2020 through February 2044, corresponding with 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 December 31, 2017 and 2016. We do not apply hedge accounting to these derivative instruments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Assets Natural gas swaps Other current assets $ Natural gas swaps Other deferred charges $ – Liabilities Natural gas swaps Other current liabilities $ $ Natural gas swaps Other deferred credits $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, 2017, 2016 and 2015. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural Gas Swaps Fuel $ $ $ Natural Gas Swaps Fuel ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at December 31, 2017 and 2016. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Natural Gas Swaps Regulatory asset $ ) $ ) Natural Gas Swaps Regulatory liability – Interest Rate Options Regulatory asset – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Investments_

Investments:	12 Months Ended
	Dec. 31, 2017
Investments:
Investments:	4. Investments: Investments in debt and equity securities Investment securities we hold are classified as available-for-sale and are carried at market value. Prior to October 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were added to or deducted from accumulated other comprehensive (deficit) margin. During the fourth quarter of 2017, we began applying regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 75% of the gross unrealized losses were in effect for less than one year. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2017 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2016 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All of the available-for-sale investments are recorded at fair value in the accompanying consolidated balance sheets, therefore the carrying value equals the fair value. The contractual maturities of debt securities available-for-sale, which are included in the estimated fair value table above, at December 31, 2017 and 2016 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 Cost Fair Value Cost Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Due within one year $ $ $ $ Due after one year through five years Due after five years through ten years Due after ten years ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2017, 2016 and 2015: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross realized gains $ $ $ Gross realized losses ) ) ) Proceeds from sales ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in associated companies Investments in associated companies were as follows at December 31, 2017 and 2016: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ National Rural Utilities Cooperative Finance Corporation (CFC) $ $ CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ​ ​ ​ ​ ​ ​ ​ ​ The CFC investments consist of capital term certificates required in connection with our membership in CFC and a voluntary investment in CFC member capital securities. Accordingly, there is no market for these investments. The investment in Georgia Transmission represents capital credits. The investment in Georgia System Operations represents loan advances. Repayments of these advances are due by December 2022. CT Parts, LLC is an affiliated organization formed by us and Smarr EMC for the purpose of purchasing and maintaining spare parts inventory and for the administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost. Rocky Mountain transactions In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six separate owner trusts for the benefit of three investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years under six separate leases. RMLC then subleased the undivided interests back to us under six separate leases for an identical term. In 2012, we terminated five of the six lease transactions prior to the end of their lease terms. The remaining lease in place represented approximately 10% of the original lease transactions. Pursuant to a payment undertaking agreement, we have a guarantee for the annual basic rent payments due under the remaining lease. The fair value amount relating to the guarantee of basic rent payment is immaterial to us principally due to the high credit rating of the payment undertaker, Rabobank Nederland. The basic rental payments remaining through the end of the lease, which expires in 2027, are approximately $47,882,000. At the end of the term of the remaining facility lease, we have the option to cause RMLC to purchase the owner trust's undivided interest in Rocky Mountain at a fixed purchase option price of approximately $112,000,000. The payment undertaking agreement, along with the equity funding agreement with AIG Matched Funding Corp., would fund approximately $74,000,000 and $37,928,000 of this amount, respectively, and these amounts would be paid to the owner trust over five installments in 2027. If we do not elect to cause RMLC to purchase the owner trust's undivided interest in Rocky Mountain, Georgia Power has an option to purchase the undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) the undivided interest in Rocky Mountain to the owner trust, the owner trust has several options it can elect, including: • causing RMLC and us to renew the related facility lease and facility sublease for up to an additional 16 years and provide collateral satisfactory to the owner trust, • leasing its undivided interest to a third party under a replacement lease, or • retaining the undivided interest for its own benefit. Under the first two of these options we must arrange new financing for the outstanding amount of the loan used to finance the owner trust's upfront rental payment made to us when the lease closed on December 31, 1996. At the end of the lease term, the amount of the outstanding loan is anticipated to be approximately $74,000,000. If new financing cannot be arranged, the owner trust can ultimately cause us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificate or cause RMLC to exercise its purchase option or RMLC to renew the facility lease and facility sublease, respectively. The assets of RMLC are not available to pay our creditors.

Income taxes_

Income taxes:	12 Months Ended
	Dec. 31, 2017
Income taxes:
Income taxes:	5. Income taxes: While we are a not-for-profit membership corporation formed under the laws of the state of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current or deferred income tax liability. Although we believe that treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, we believe that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on our financial condition or results of operations and cash flows. We account for income taxes pursuant to the authoritative guidance for accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. The difference between the statutory federal income tax rate on income before income taxes and our effective income tax rate is summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statutory federal income tax rate % % Patronage exclusion %) %) AMT credit monetization %) % Other %) %) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Effective income tax rate %) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The tax benefit reflected in the effective income tax rate reconciliation relates to the approximate $1,117,000 current tax benefit realized in 2017 as a result of monetizing the remaining balance of alternative minimum tax credits. This benefit is as a result of a refundable credit, and since it is applied after considering the patronage dividend deduction, it is not allocated to our members, but instead is a source of cash to the taxpayer applied against its normal operating expenses. The benefit is shown as a component of production operating expenses on the statement of revenues and expenses. The components of our net deferred tax assets and liabilities as of December 31, 2017 and 2016 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Net operating losses $ $ Tax credits (alternative minimum tax and other) – Accounting for Rocky Mountain transactions Other assets ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Less: Valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities Depreciation $ $ Accounting for Rocky Mountain transactions Other liabilities ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liabilities Less: Patronage exclusion ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred taxes $ – $ – ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2017, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Expiration Date Alternative NOLs ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ – $ 2019 – 2020 – ​ ​ ​ ​ ​ ​ ​ ​ $ – $ ​ ​ ​ ​ ​ ​ ​ ​ The net operating loss expiration dates start in the year 2018 and end in the year 2020. Due to the tax basis method for allocating patronage dividends and as shown by the above valuation allowance, it is not more likely than not that the deferred tax asset related to the net operating losses will be realized. On December 18, 2015, the Protecting Americans from Tax Hikes (PATH) Act was signed into law. The PATH Act allowed us to accelerate and monetize AMT credits in lieu of bonus depreciation through the tax year ended December 31, 2019. The remaining credit of $599,000 will be claimed on the tax return filed for the tax year ended December 31, 2017. On December 22, 2017, following its passage by the United States Congress, the President signed into law Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, or the Act. The Act will make significant changes to U.S. federal income tax laws. The Act reduces the federal tax rate for corporations from 35% to 21% effective January 1, 2018 and changes or applies limitations to certain tax deductions. As of December 31, 2017, we have not completed our accounting for the tax effects upon enactment of the Act; however we have been able to make a reasonable estimate of the effects on our existing deferred tax balances. We have remeasured the deferred tax assets and liabilities to reflect the applicable tax rate expected to be in effect when the timing differences reverse, which is 21%. No net impact to the results of operations was recorded as a result of this remeasurment, however the impact to the components of the net deferred tax assets and liabilities is reflected in the above table. We continue to analyze the impact of this tax reform legislation which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts, however we do not believe it will have a material impact on the company's results of operation or cash flows. The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. We may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. We file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2014 and forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2014 and forward. We have no liabilities recorded for uncertain tax positions.

Capital leases_

Capital leases:	12 Months Ended
	Dec. 31, 2017
Capital leases:
Capital leases:	6. Capital leases: In 1985, we sold and subsequently leased back from four purchasers their 60% undivided ownership interest in Scherer Unit No. 2. The gain from the sale is being amortized over the terms of the leases. The assumed interest rate at inception of the lease in 1985 was 11.05%. Three of the leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the lease, we can elect 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 The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2017 are as follows: ​ ​ ​ ​ ​ Year Ending December 31, (dollars in ​ ​ ​ ​ ​ 2018 $ 2019 2020 2021 2022 2023-2031 ​ ​ ​ ​ ​ Total minimum lease payments Less: Amount representing interest ) ​ ​ ​ ​ ​ Present value of net minimum lease payments Less: Current portion ) ​ ​ ​ ​ ​ Long-term balance $ ​ ​ ​ ​ ​ The Scherer No. 2 lease is reported as a capital lease. For rate-making purposes, however, we include the actual lease payments in our cost of service. The difference between lease payments and the aggregate of the amortization on the capital lease asset and the interest on the capital lease obligation is recognized as a regulatory asset. Capital lease amortization is recorded in depreciation and amortization expense.

Debt_

Debt:	12 Months Ended
	Dec. 31, 2017
Debt:
Debt:	7. Debt: Long-term debt consists of first mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and guaranteed by the Rural Utilities Service or the U.S. Department of Energy, first mortgage bonds payable (FMBs), first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds (PCBs) and first mortgage notes payable to CFC. Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds, and the CFC first mortgage notes. Maturities for long-term debt and capital lease obligations through 2022 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2018 2019 2020 2021 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FFB $ $ $ $ $ FMBs PCBs (1) – CFC – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ $ Capital Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In addition to regularly scheduled principal payments on the bonds, this includes amounts that would be due if the standby letters of credit supporting the Series 2009 and Series 2010 bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility the letters of credit were issued under was not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020 and $18.7 million in 2021. We anticipate extending these credit facilities before their expiration. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038. The weighted average interest rate on our long-term debt at December 31, 2017 and 2016 was 4.17% and 4.34%, respectively. Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts at December 31, 2017 and 2016 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 Principal Unamortized Debt Principal Unamortized Debt ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) FFB $ $ $ $ FMBs PCBs CFC – – CoBank – – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We use the effective interest rate method to amortize debt issuance costs and debt discounts as well as the straight-line method when the results approximate those of the effective interest rate method. Unamortized debt issuance costs and debt discounts are being amortized to expense over the life of the respective debt issues. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the Title XVII Loan Guarantee Program), we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 (as amended, the Loan Guarantee Agreement) pursuant to which the Department of Energy agreed to guarantee our obligations under the Note Purchase Agreement dated as of February 20, 2014 (the Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the FFB Notes and together with the Note Purchase Agreement, the FFB Credit Facility Documents). The FFB Credit Facility Documents provide for a multi-advance term loan facility (the Facility), under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility will be used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowings under the Facility may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will begin on February 20, 2020. Under both FFB Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. At December 31, 2017, aggregate Department of Energy-guaranteed borrowings totaled $1,735,586,000, including capitalized interest. Pursuant to the amended terms of the Loan Guarantee Agreement, we are restricted from receiving further advances until certain conditions are met, including Department of Energy approval of the Bechtel Agreement (as defined in Note 8) and the Department of Energy and we enter into an amendment to the Loan Guarantee Agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018. When these conditions are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. Under the Loan Guarantee Agreement, upon the occurrence of an "Alternate Amortization Event," the Department of Energy may require us to prepay the outstanding principal amount of all guaranteed borrowings over a period of five years, with level principal amortization. These events include (i) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii) termination of the Services Agreement as defined in Note 8 or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to certain related intellectual property rights, (iii) a decision by us not to continue construction of Vogtle Units No. 3 and No. 4, (iv) loss of or failure to receive necessary regulatory approvals under certain circumstances, (v) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vii) change of control of Oglethorpe and (viii) certain events of loss or condemnation. 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 of additional guaranteed funding under the Loan Guarantee Agreement. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of this additional loan guarantee by the Department of Energy cannot be assured and is 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: During 2017, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $22,098,000 for long-term financing of general and environmental improvements at existing plants. In January 2018, we received an additional $2,636,000 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 (Series 2017A Burke, Heard and Monroe and 2017B Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control 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 bears interest at an indexed variable rate until October 3, 2022, the initial mandatory tender date. Bonds that are not remarketed by the initial mandatory tender date will be returned to the holders thereof and will be subject to mandatory redemption on October 2, 2023. These 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. On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. d) Credit Facilities: As of December 31, 2017, we had a total of $1,610,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from October 2018 to March 2020. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2017, we had the ability to issue letters of credit totaling $760,000,000 in the aggregate, of which $509,000,000 remained available. At December 31, 2017, we had 1) $251,000,000 under these lines of credit in the form of issued letters of credit supporting variable rate demand bonds and collateral postings to third parties, and 2) $191,000,000 dedicated under one of these lines of credit to support a like amount of commercial paper that was outstanding. The weighted average interest rate on short-term borrowings at December 31, 2017 and December 31, 2016 was 1.58% and 0.93%, respectively.

Electric plant, construction an

Electric plant, construction and related agreements:	12 Months Ended
	Dec. 31, 2017
Electric plant, construction and related agreements:
Electric plant, construction and related agreements:	8. Electric plant, construction and related agreements: a. Electric plant We, along with Georgia Power, have entered into agreements providing for the purchase and subsequent joint operation of certain electric generating plants. Each co-owner is responsible for providing their own financing. The plant investments disclosed in the table below represent our undivided interest in each plant. A summary of our plant investments and related accumulated depreciation as of December 31, 2017 and 2016 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Plant Investment Accumulated Investment Accumulated ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ $ ) $ $ ) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) ) ) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) ) ) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) ) ) Scherer Unit No. 1 (Fossil – 60% ownership) ) ) Doyle (Combustion Turbine - 100% ownership) ) ) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) ) ) Hartwell (Combustion Turbine - 100% ownership) ) ) Hawk Road (Combustion Turbine - 100% ownership) ) ) Talbot (Combustion Turbine - 100% ownership) ) ) Chattahoochee (Combined cycle - 100% ownership) ) ) Smith (Combined cycle - 100% ownership) ) ) Wansley (Combustion Turbine – 30% ownership) ) ) Transmission plant ) ) Other ) ) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total in-service $ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Construction work in progress Vogtle Units No. 3 & No. 4 (2) $ $ Environmental and other generation improvements Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total construction work in progress $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts include plant acquisition adjustments at December 31, 2017 and 2016 of $197,000,000. (2) The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as described in Note 8b. Our proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production) on the accompanying Statement of Revenues and Expenses. b. Construction Vogtle Units No. 3 and No. 4 We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, 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 terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee), including any liability of Westinghouse for abandonment of work. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. On March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired on July 27, 2017, upon the effective date of the Services Agreement discussed below. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse 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 actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017. 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 was $3,680,000,000 (the Guarantee Obligations), of which our proportionate share was $1,104,000,000. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement. Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement, which was amended and restated on July 20, 2017 (the Services Agreement), for Westinghouse 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 Westinghouse'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, and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreement 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. Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion 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 (the Bechtel Agreement). 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, 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 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. Pursuant to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement and further amend the loan guarantee agreement to incorporate provisions relating to the Bechtel Agreement and other replacement agreements prior to receiving any further advances. 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; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1,000,000,000 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. On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations. We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget is net of the $1,104,000,000 of payments we received from Toshiba under the Guarantee Settlement Agreement. As of December 31, 2017, our total investment in the additional Vogtle units was $2,938,000,000, net of the payments received from Toshiba under the Guarantee Settlement Agreement. The payments from Toshiba were recorded as a reduction to the construction work in progress balance for the additional Vogtle units. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230,000,000. 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 the Rural Utilities Service. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yet to be tested. 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. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners. The ultimate outcome of these matters cannot be determined at this time.

Employee benefit plans_

Employee benefit plans:	12 Months Ended
	Dec. 31, 2017
Employee benefit plans:
Employee benefit plans:	9. Employee benefit plans: Our retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of his or her eligible annual compensation. At our discretion, we may match the employee's contribution and have done so each year of the plan's existence. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee's eligible compensation, depending on the amount and timing of the employee's contribution. Our contributions to the matching feature of the plan were approximately $1,436,000, $1,371,000 and $1,310,000 in 2017, 2016 and 2015, respectively. Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 11% of an employee's eligible annual compensation. Prior to 2016, the effective rate of the employer retirement contribution was 8%. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $3,791,000, $3,678,000 and $2,611,000 in 2017, 2016 and 2015, respectively.

Nuclear insurance_

Nuclear insurance:	12 Months Ended
	Dec. 31, 2017
Nuclear insurance:
Nuclear insurance:	10. Nuclear insurance: The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to $13,400,000,000. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $450,000,000 a licensee of a nuclear power plant could be assessed a deferred premium of up to $127,000,000 per incident for each licensed reactor operated by it, but not more than $19,000,000 per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in four nuclear reactors, we could be assessed a maximum of $153,000,000 per incident, but not more than $23,000,000 in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than September 10, 2018. Georgia Power, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to provide property damage insurance coverage in an amount up to $1,500,000,000 for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1,250,000,000 for nuclear losses in excess of the $1,500,000,000 primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750,000,000 for non-nuclear losses in excess of the $1,500,000,000 primary coverage. Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. 3 and No. 4. This policy provides $2,750,000,000 in limits for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums, if losses each year exceed the accumulated reserve funds available to the insurer. The portion of the current maximum annual assessment for Georgia Power that would be payable by Oglethorpe based on ownership share, is limited to approximately $40,000,000. Claims resulting from terrorist acts are covered under both the ANI and NEIL policies subject to normal policy limits. The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3,200,000,000 plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to Georgia Power, for the benefit of all the co-owners, or to bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. Uninsured losses and other expenses could have a material adverse effect on our financial condition and results of operations.

Commitments_

Commitments:	12 Months Ended
	Dec. 31, 2017
Commitments:
Commitments:	11. Commitments: a. Operating leases As of December 31, 2017, our estimated minimum rental commitments for our railcar leases for use at our coal-fired facilities over the next five years and thereafter are as follows: ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ 2018 $ 2019 2020 Thereafter – ​ ​ ​ ​ ​ These railcar leasing costs are added to the cost of the fossil inventories and are recognized in fuel expense. Rental expenses totaled $4,919,000, $4,456,000 and $4,849,000 in 2017, 2016 and 2015, respectively. We are assessing our future railcar needs and evaluating our leasing options. b. Fuel To supply a portion of the fuel requirements to our generating units, Southern Nuclear on our behalf for nuclear fuel, and Georgia Power, on our behalf for coal, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs. For further discussion of total nuclear fuel expense, see Note 1g. On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC (Transco) for additional firm natural gas transportation to our Smith facility. The new natural gas pipeline by Transco was placed into service in August 2017. Total fixed charges over the 25-year base term will be approximately $942,500,000. As of December 31, 2017, our estimated minimum long-term commitments are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Coal Nuclear Fuel Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ $ $ 2019 2020 2021 – 2022 – Thereafter – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters:	12 Months Ended
	Dec. 31, 2017
Contingencies and Regulatory Matters:
Contingencies and Regulatory Matters:	12. 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. Environmental Matters As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We are also subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities. In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs. Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

Quarterly financial data (unaud

Quarterly financial data (unaudited):	12 Months Ended
	Dec. 31, 2017
Quarterly financial data (unaudited):
Quarterly financial data (unaudited):	13. Quarterly financial data (unaudited): Summarized quarterly financial information for 2017 and 2016 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Second Third Fourth ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 Operating revenues $ $ $ $ Operating margin Net margin ) 2016 Operating revenues $ $ $ $ Operating margin Net margin ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The negative net margins in the fourth quarter of 2017 and 2016 were due to reductions to revenue requirements in order to achieve the targeted margins for interest ratio of 1.14.

Summary of significant accoun22

Summary of significant accounting policies: (Policies)	12 Months Ended
	Dec. 31, 2017
Summary of significant accounting policies:
Business description	a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,115 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 728 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 119 megawatts of capacity, including 86 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.1 million people.
Basis of accounting	b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2017 and 2016 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2017. Actual results could differ from those estimates. Certain fair value hierarchy disclosures have been revised to conform to the current period classification. Securities previously classified as "US Treasury and government agency securities" under Level 1 in the fair value hierarchy totaling $37,884,000 as of December 31, 2016 in the fair value table of Note 2 are now presented under Level 2 as "Mortgage backed securities" and "Federal agency securities." These changes do not impact the investment portfolio or the fair value of the assets that are recorded in the financial statements.
Patronage capital and membership fees	c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities.
Margin policy	d. Margin policy 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 the years 2017, 2016 and 2015, we achieved a margins for interest ratio of 1.14.
Operating revenues	e. Operating revenues Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded in approximately equal amounts throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred. Prior to 2016, operating revenues from sales to non-members consisted primarily of energy sales at Smith. The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2017, 2016 or 2015: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jackson EMC % % % Cobb EMC % % % Sawnee EMC n/a % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have a rate management program that allows us to expense and recover certain 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 in 2017, 2016 and 2015 were $11,000,000, $16,096,000 and $7,630,000, respectively. The cumulative amount billed since inception of the program totaled $54,087,000. Prior to 2016, members also subscribed to the Smith program, which allowed for the accelerated recovery of deferred net costs related to Smith. The Smith program ceased as of December 31, 2015 when the plant became available for scheduling to our members. The amount billed to participating members under this program in 2015 was $17,745,000 and the cumulative amount billed since inception totaled $58,922,000.
Receivables	f. Receivables A substantial portion of our receivables are related to electricity sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Member receivables at December 31, 2017 and 2016 were $126,211,000 and $136,552,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible.
Nuclear fuel cost	g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2017, 2016 and 2015 amounted to $90,520,000, $83,751,000, and $78,762,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Plants Hatch and Vogtle Units No. 1 and No. 2 covering the period of 2005 through 2010. Our ownership share of the $36,474,000 total award was $10,949,000, which was received in April 2015. The effects of the award were recorded during the first quarter of 2015 and resulted in a $7,320,000 reduction in total operating expenses, including reductions to fuel expense and production costs, as well as a $3,629,000 reduction to plant in service. On October 10, 2017, Georgia Power, as agent for the co-owners filed a separate claim seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering a period from January 1, 2015 through December 31, 2017. In addition, Georgia Power previously filed a separate claim to cover periods January 1, 2011 through December 31, 2013 which was subsequently amended and extended through December 31, 2014. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts were recognized in the financial statements as of December 31, 2017 for this claim. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.
Asset retirement obligations and other retirement costs	h. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to coal ash ponds, gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants' asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2015 and 2016, respectively. The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2017 and 2016. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ Liabilities settled ) ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2017 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ Liabilities settled – ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. The estimated costs of decommissioning are based on the most current study performed in 2015. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.5%. The increase in the cash flow estimates in 2015 was primarily attributable to security costs, waste disposal costs and inflation, among other factors. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Hatch Vogtle Vogtle ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. Coal Ash Pond. On April 17, 2015 the Environmental Protection Agency published its final coal combustion residuals (CCR) rule which regulates CCRs as non-hazardous materials under Subtitle D of the Resource Conservation and Recovery Act. The rule took effect on October 19, 2015. Our most current assessment of the final CCR rule resulted in a $1,604,000 change in cash flow estimates for coal ash pond decommissioning. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR rule. The 2017 and 2016 increases in cash flow estimates were primarily attributed to an increase in the closure cost estimates. Additional adjustments to the asset retirement obligations are expected periodically as we continue to assess the impact of the rule, including potential changes, on our estimates and assumptions. Other. Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q.
Nuclear decommissioning funds	i. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC's regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2017 and 2016, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund, which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheet. In both 2017 and 2016, we contributed $4,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2017 and December 31, 2016. The funds are invested in a diversified mix of approximately 60% equity and 40% fixed income securities for both 2017 and 2016. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 External Trust Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) $ Other ) – $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $31,939,680. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2016 External Trust Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) ) $ Other ) ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (2) Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $12,270,144. Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. The nuclear decommissioning trust fund has produced an average annualized return of approximately 6.4% in the last ten years and 6.3% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates.
Depreciation	j. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use standard depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The 2017 and 2016 depreciation rates for steam and nuclear production in the table below reflect revised rates from depreciation rate studies completed in 2015. Site specific depreciation studies are performed every five years. Annual depreciation rates in effect in 2017, 2016 and 2015 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2017. Depreciation expense for the years 2017, 2016 and 2015 was $218,027,000, $211,282,000, and $180,866,000, respectively.
Electric plant	k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ended 2017, 2016 and 2015, the allowance for funds used during construction rates were 4.45%, 4.61% and 4.73%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants.
Cash and cash equivalents	l. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments.
Restricted investments	m. Restricted investments Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At December 31, 2017 and 2016, we had restricted investments totaling $882,909,000 and $468,179,000, respectively, of which $653,585,000 and $221,122,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.
Inventories	n. Inventories We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost. The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed. At December 31, 2017 and December 31, 2016, fossil fuels inventories were $54,050,000 and $57,289,000, respectively. Inventories for spare parts at 2017 and 2016 were $212,169,000 and $202,542,000, respectively.
Deferred charges and other assets	o. Deferred charges and other assets Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and progress payments for equipment associated with future nuclear refueling outages. For a discussion regarding regulatory assets, see Note 1q.
Deferred credits and other liabilities	p. Deferred credits and other liabilities 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 monthly and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2023, with the majority of the balance scheduled to be credited by the end of 2019. During 2016, in connection with the Vogtle Units No. 3 and No. 4 construction project, we were accruing long-term contract retainage amounts for substantial and mechanical milestones. As a result of a settlement agreement entered into by Georgia Power Company and the Co-owners and Toshiba in June 2017, these contract retainage amounts were reversed. For more information regarding the Vogtle construction project, see Note 8.
Regulatory assets and liabilities	q. Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts with our members, which 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 members. ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Asset Retirement Obligations – Ashpond and other (k) Depreciation expense (d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) Interest rate options cost (f) Deferral of effects on net margin – Smith Energy Facility (g) Other regulatory assets (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (g) Major maintenance reserve (i) Amortization on capital leases (b) Deferred debt service adder (j) Asset retirement obligations – Nuclear (k) Other regulatory liabilities (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (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 26 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over 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 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (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. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (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. (k) Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes. (l) The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years.
Related parties	r. Related parties We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities. For 2017, 2016, and 2015, we incurred expenses from Georgia Transmission of $28,410,000, $27,399,000, and $28,172,000, respectively. We, Georgia Transmission and 38 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2017, 2016, and 2015, we incurred expenses from Georgia Systems Operations of $25,597,000, $23,994,000, and $22,616,000, respectively.
Other income	s. Other income The components of other income within the Consolidated Statement of Revenues and Expenses were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
New accounting pronouncements	t. New accounting pronouncements In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for us for the annual reporting period beginning after December 15, 2017 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). We have completed our evaluation of the new revenue standard and adopted the amendments within the new standard effective January 1, 2018. There was no cumulative impact upon adoption. The adoption of this standard is not expected to have a material impact, on an annual basis, to our revenue recognition based on our existing contracts with customers. Our evaluation process included, but was 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. The vast majority of our revenue 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. Historically, our Board has approved budget adjustments, typically at year end but may be made throughout the year, that affect our annual revenue requirement. As a result, at the end of each reporting period we will determine whether the variable consideration cumulatively received from our Members exceeds the consideration to which we expect to be entitled on an annual basis. We will recognize a refund liability for the consideration which we expect to refund to our Members, if such excess consideration received would result in a significant reversal in the cumulative revenues recognized. 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. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $618,000 of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard will have no impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. In February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements. In June 2016, the FASB issued "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements. In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as the amendments did not change how we present and classify the eight identified cash flow classification issues within our consolidated statement of cash flows. 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. As permitted, on October 1, 2017, we early adopted these amendments and applied their provisions retrospectively. The adoption of this standard had no impact on our consolidated financial statements as we did not have any restricted cash balances in 2017 and 2016.

Summary of significant accoun23

Summary of significant accounting policies: (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of significant accounting policies:
Schedule of members whose revenues accounted for 10% or more of total operating revenues	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Jackson EMC % % % Cobb EMC % % % Sawnee EMC n/a % % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule reflecting details of Asset Retirement Obligations included in the consolidated balance sheets	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ Liabilities settled ) ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2017 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear Coal Ash Other Total ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2015 $ $ $ $ Liabilities settled – ) ) ) Accretion Change in cash flow estimates – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance at December 31, 2016 $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of estimated costs of decommissioning of co-owned nuclear facilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2015 site study Hatch Hatch Vogtle Vogtle ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Estimated costs based on site study in 2015 dollars: Radiated structures $ $ $ $ Spent fuel management Non-radiated structures ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total estimated site study costs $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of external and internal trust funds by type of investment	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 External Trust Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) $ Other ) – $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.16 Purchases Net (1) Unrealized 12.31.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) – $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Also included in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $31,939,680. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2016 External Trust Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ $ Debt ) ) $ Other ) ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Internal Funds: 12.31.15 Purchases Net (2) Unrealized 12.31.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ – $ $ $ Debt ) ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (2) Also iancluded in net proceeds are net realized gains or losses, interest income and dividends, contributions and fees of $12,270,144.
Schedule of annual depreciation rates	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Range of 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Steam production 49-65 % % % Nuclear production 37-60 % % % Hydro production 50 % % % Other production 27-33 % % % Transmission 36 % % % General 3-50 2.00-33.33 % 2.00-33.33 % 2.00-33.33 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ * Calculated based on the composite depreciation rates in effect for 2017.
Schedule of regulatory assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Asset Retirement Obligations – Ashpond and other (k) Depreciation expense (d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) Interest rate options cost (f) Deferral of effects on net margin – Smith Energy Facility (g) Other regulatory assets (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ $ Deferral of effects on net margin – Hawk Road Energy Facility (g) Major maintenance reserve (i) Amortization on capital leases (b) Deferred debt service adder (j) Asset retirement obligations – Nuclear (k) Other regulatory liabilities (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net regulatory assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ (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 26 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over 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 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Deferred charges related to Vogtle Units No. 3 and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of net loss associated with the change in fair value and expired cost of interest rate options purchased to hedge interest rates on certain borrowings related to Vogtle Units No.3 and No.4 construction. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (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. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (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. (k) Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes. (l) The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years.
Schedule of components of other income	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capital credits from associated companies (Note 4) $ $ $ Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs Miscellaneous other ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Fair Value_ (Tables)

Fair Value: (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value:
Schedule of assets and liabilities measured at fair value on a recurring basis	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2017 Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Domestic mutual funds $ – Municipal bonds $ – Federal agency securities $ – Other $ – Long-term investments: International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Dometic mutual funds $ – Federal agency securities $ – Other $ – Natural gas swaps $ – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, 2016 Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ – International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Municipal bonds $ – Federal agency securities $ – Other $ – Long-term investments: International equity trust $ – Corporate bonds and debt $ – US Treasury securities $ – Mortgage backed securities $ – Domestic mutual funds $ – Federal agency securities $ – Other $ – Natural gas swaps $ ) – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of estimated fair values of long-term debt, including current maturities	The estimated fair values of our long-term debt, including current maturities at December 31, 2017 and 2016 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 Carrying Fair Carrying Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Derivative instruments_ (Tables

Derivative instruments: (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative instruments:
Schedule of volume activity of natural gas derivatives that is expected to settle or mature each year	​ ​ ​ ​ ​ Year Natural Gas (in millions) ​ ​ ​ ​ ​ 2018 2019 2020 2021 2022 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​
Schedule of fair value of derivative instruments and effect on our consolidated balance sheets	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Assets Natural gas swaps Other current assets $ Natural gas swaps Other deferred charges $ – Liabilities Natural gas swaps Other current liabilities $ $ Natural gas swaps Other deferred credits $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of the realized gains and (losses) on derivative instruments recognized in margin	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural Gas Swaps Fuel $ $ $ Natural Gas Swaps Fuel ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of unrealized gains and (losses) on derivative instruments deferred on the balance sheet	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Natural Gas Swaps Regulatory asset $ ) $ ) Natural Gas Swaps Regulatory liability – Interest Rate Options Regulatory asset – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Investments_ (Tables)

Investments: (Tables)	12 Months Ended
	Dec. 31, 2017
Investments:
Summary of available-for-sale securities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2017 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Gross Unrealized 2016 Cost Gains Losses Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other – ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of contractual maturities of debt securities available-for-sale	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 Cost Fair Value Cost Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Due within one year $ $ $ $ Due after one year through five years Due after five years through ten years Due after ten years ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Summary of realized gains and losses and proceeds from sales of securities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross realized gains $ $ $ Gross realized losses ) ) ) Proceeds from sales ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of investments in associated companies	​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ National Rural Utilities Cooperative Finance Corporation (CFC) $ $ CT Parts, LLC Georgia Transmission Corporation Georgia System Operations Corporation Other ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ ​ ​ ​ ​ ​ ​ ​ ​

Income taxes_ (Tables)

Income taxes: (Tables)	12 Months Ended
	Dec. 31, 2017
Income taxes:
Summary of difference between statutory federal income tax rate on income before income taxes and effective income tax rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 2015 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statutory federal income tax rate % % Patronage exclusion %) %) AMT credit monetization %) % Other %) %) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Effective income tax rate %) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​
Schedule of components of net deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 2016 ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Net operating losses $ $ Tax credits (alternative minimum tax and other) – Accounting for Rocky Mountain transactions Other assets ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax assets Less: Valuation allowance ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities Depreciation $ $ Accounting for Rocky Mountain transactions Other liabilities ​ ​ ​ ​ ​ ​ ​ ​ Deferred tax liabilities ​ ​ ​ ​ ​ ​ ​ ​ Net deferred tax liabilities Less: Patronage exclusion ) ) ​ ​ ​ ​ ​ ​ ​ ​ Net deferred taxes $ – $ – ​ ​ ​ ​ ​ ​ ​ ​
Schedule of federal tax net operating loss carryforwards and alternative minimum tax credits	As of December 31, 2017, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows: ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Expiration Date Alternative NOLs ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ – $ 2019 – 2020 – ​ ​ ​ ​ ​ ​ ​ ​ $ – $ ​ ​ ​ ​ ​ ​ ​ ​

Capital leases_ (Tables)

Capital leases: (Tables)	12 Months Ended
	Dec. 31, 2017
Capital leases:
Schedule of minimum lease payments under capital leases together with present value of net minimum lease payments	The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2017 are as follows: ​ ​ ​ ​ ​ Year Ending December 31, (dollars in ​ ​ ​ ​ ​ 2018 $ 2019 2020 2021 2022 2023-2031 ​ ​ ​ ​ ​ Total minimum lease payments Less: Amount representing interest ) ​ ​ ​ ​ ​ Present value of net minimum lease payments Less: Current portion ) ​ ​ ​ ​ ​ Long-term balance $ ​ ​ ​ ​ ​

Debt_ (Tables)

Debt: (Tables)	12 Months Ended
	Dec. 31, 2017
Debt:
Schedule of maturities for long-term debt and capital lease obligations	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2018 2019 2020 2021 2022 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FFB $ $ $ $ $ FMBs PCBs (1) – CFC – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ $ Capital Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) In addition to regularly scheduled principal payments on the bonds, this includes amounts that would be due if the standby letters of credit supporting the Series 2009 and Series 2010 bonds were drawn upon and became payable in accordance with their terms, such as would occur if the credit facility the letters of credit were issued under was not renewed or extended at its expiration date. These amounts equal $18.7 million in 2018, $37.4 million in 2019, $170.9 million in 2020 and $18.7 million in 2021. We anticipate extending these credit facilities before their expiration. The nominal maturities of the Series 2009 and Series 2010 pollution control bonds range from 2030 through 2038.
Schedule of principal amount of long-term debt and the associated unamortized debt issuance costs and debt discounts	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 Principal Unamortized Debt Principal Unamortized Debt ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) FFB $ $ $ $ FMBs PCBs CFC – – CoBank – – – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Electric plant, construction 30

Electric plant, construction and related agreements: (Tables)	12 Months Ended
	Dec. 31, 2017
Electric plant, construction and related agreements:
Summary of plant investments and related accumulated depreciation	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 2016 (dollars in thousands) Plant Investment Accumulated Investment Accumulated ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ $ ) $ $ ) Vogtle Units No. 3 & No. 4 (Nuclear – 30% ownership) ) ) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) ) ) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) ) ) Scherer Unit No. 1 (Fossil – 60% ownership) ) ) Doyle (Combustion Turbine - 100% ownership) ) ) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) ) ) Hartwell (Combustion Turbine - 100% ownership) ) ) Hawk Road (Combustion Turbine - 100% ownership) ) ) Talbot (Combustion Turbine - 100% ownership) ) ) Chattahoochee (Combined cycle - 100% ownership) ) ) Smith (Combined cycle - 100% ownership) ) ) Wansley (Combustion Turbine – 30% ownership) ) ) Transmission plant ) ) Other ) ) Property under capital lease: Scherer Unit No. 2 (Fossil – 60% leasehold) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total in-service $ $ ) $ $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Construction work in progress Vogtle Units No. 3 & No. 4 (2) $ $ Environmental and other generation improvements Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total construction work in progress $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (1) Amounts include plant acquisition adjustments at December 31, 2017 and 2016 of $197,000,000. (2) The 2017 amount is net of a $1,104,000,000 credit recorded as a result of payments received from Toshiba under the Guarantee Settlement Agreement as described in Note 8b.

Commitments_ (Tables)

Commitments: (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments:
Schedule of estimated minimum rental commitments for railcar leases for use at coal-fired facilities over the next five years and thereafter	As of December 31, 2017, our estimated minimum rental commitments for our railcar leases for use at our coal-fired facilities over the next five years and thereafter are as follows: ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ 2018 $ 2019 2020 Thereafter – ​ ​ ​ ​ ​
Schedule of estimated minimum long-term commitments	As of December 31, 2017, our estimated minimum long-term commitments are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Coal Nuclear Fuel Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 $ $ $ 2019 2020 2021 – 2022 – Thereafter – ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Quarterly financial data (una32

Quarterly financial data (unaudited): (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly financial data (unaudited):
Summary of quarterly financial information	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First Second Third Fourth ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) 2017 Operating revenues $ $ $ $ Operating margin Net margin ) 2016 Operating revenues $ $ $ $ Operating margin Net margin ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Summary of significant accoun33

Summary of significant accounting policies: - Accounting policies (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)itemMW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business description
Number of electric distribution cooperative members | item			38
Summer planning reserve capacity of generating units (in megawatts) | MW			7,115
Number of people to whom energy is distributed on a retail basis by the entity's members | item			4,100,000
Basis of accounting
Long-term investments	$ 140,622,000	$ 99,874,000	$ 140,622,000	$ 99,874,000
Patronage capital and membership fees
Membership fees paid by members			$ 190
Minimum equity as a percentage of total long-term debt and equities for distributions of patronage capital			20.00%
Maximum percentage of aggregate net margins in which specified percentage of total long-term debt and equities cannot exceed on or after distributions expended			35.00%
Minimum equity as a percentage of total long-term debt and equities after distributions of patronage capital			30.00%
Margin policy
Minimum margins for interest ratio under the first mortgage indenture			1.10
Margins for interest ratio	1.14	1.14	1.14	1.14	1.14
Receivables
Member receivables	$ 126,211,000	$ 136,552,000	$ 126,211,000	$ 136,552,000
Electric plant
Construction rates for allowance of funds (as a percent)			4.45%	4.61%	4.73%
Restricted investments
Guaranteed interest rate on deposit (as a percent)			5.00%	5.00%
Restricted investments	882,909,000	468,179,000	$ 882,909,000	$ 468,179,000
Restricted investments, long-term	653,585,000	221,122,000	653,585,000	221,122,000
Inventories
Fossil fuels inventories	54,050,000	57,289,000	54,050,000	57,289,000
Spare parts	$ 212,169,000	202,542,000	$ 212,169,000	202,542,000
Related parties
Number of electric distribution cooperative members | item			38
Other income
Capital credits from associated companies			$ 1,531,000	1,679,000	$ 1,859,000
Net revenue from Georgia Transmission and Georgia System Operations for shared Administrative and General costs			6,816,000	6,553,000	6,278,000
Miscellaneous other			(2,056,000)	(5,561,000)
Miscellaneous other					1,006,000
Total			$ 6,291,000	2,671,000	9,143,000
Significant Other Observable Inputs (Level 2) | Mortgage backed securities and federal agency securities
Basis of accounting
Long-term investments		$ 37,884,000		37,884,000
Smarr EMC
Business description
Summer planning reserve capacity of generating units (in megawatts) | MW			728
Green Power EMC
Business description
Summer planning reserve capacity of generating units (in megawatts) | MW			119
Green Power EMC | Solar energy
Business description
Summer planning reserve capacity of generating units (in megawatts) | MW			86
Georgia Transmission
Business description
Number of electric distribution cooperative members | item			38
Related parties
Number of electric distribution cooperative members | item			38
Expenses incurred for transmission services, system operations services and administrative support services			$ 28,410,000	27,399,000	28,172,000
Georgia System Operations Corporation
Business description
Number of electric distribution cooperative members | item			38
Related parties
Number of electric distribution cooperative members | item			38
Expenses incurred for transmission services, system operations services and administrative support services			$ 25,597,000	$ 23,994,000	$ 22,616,000

Summary of significant accoun34

Summary of significant accounting policies: - Concentrations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total operating revenues | Revenues of members | Jackson EMC
Concentration
Operating revenues (as a percent)	14.70%	14.30%	9.70%
Total operating revenues | Revenues of members | Cobb EMC
Concentration
Operating revenues (as a percent)	14.30%	13.70%	13.10%
Total operating revenues | Revenues of members | Sawnee EMC
Concentration
Operating revenues (as a percent)		10.50%	10.40%
Vogtle Units Number 3 And Number 4
Concentration
Amounts billed to members	$ 11,000,000	$ 16,096,000	$ 7,630,000
Cumulative amounts billed to members	54,087,000
Smith
Concentration
Amounts billed to members			$ 17,745,000
Cumulative amounts billed to members	$ 58,922,000

Summary of significant accoun35

Summary of significant accounting policies: - Nuclear fuel cost information (Details) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 14, 2014
Nuclear fuel cost
Nuclear fuel expense		$ 90,520,000	$ 83,751,000	$ 78,762,000
Nuclear Fuel Disposal Cost Settlement, January 1, 2005 through December 31, 2010 | Plant Hatch and Plant Vogtle
Nuclear fuel cost
Settlement amount, all parties					$ 36,474,000
Settlement amount, entity share	$ 10,949,000
Reduction of total operating expenses	7,320,000
Reduction to plant in service	$ 3,629,000
Nuclear Fuel Disposal Cost Settlement, January 1, 2011 through December 31, 2013 | Plant Hatch and Plant Vogtle
Nuclear fuel cost
Damages receivable		$ 0

Summary of significant accoun36

Summary of significant accounting policies: - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations
Balance at the beginning of the period	$ 698,051	$ 602,230
Liabilities settled	(2,145)	(1,260)
Accretion	36,674	32,361	$ 26,108
Change in cash flow estimates	2,417	64,720
Balance at the end of the period	734,997	698,051	602,230
Nuclear
Asset Retirement Obligations
Balance at the beginning of the period	517,565	488,458
Liabilities settled	(17)
Accretion	31,026	29,107
Balance at the end of the period	548,574	517,565	488,458
Coal Ash Pond
Asset Retirement Obligations
Balance at the beginning of the period	156,465	93,622
Liabilities settled	(943)	(553)
Accretion	4,629	2,215
Change in cash flow estimates	1,604	61,181
Balance at the end of the period	161,755	156,465	93,622
Other
Asset Retirement Obligations
Balance at the beginning of the period	24,021	20,150
Liabilities settled	(1,185)	(707)
Accretion	1,019	1,039
Change in cash flow estimates	813	3,539
Balance at the end of the period	$ 24,668	$ 24,021	$ 20,150

Summary of significant accoun37

Summary of significant accounting policies: - Estimated costs of nuclear decommissioning (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Nuclear decommissioning
Assumed escalation rate for labor, material and equipment (as a percent)	2.50%
Hatch Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	$ 258,000
Hatch Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	282,000
Vogtle Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	253,000
Vogtle Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	275,000
Radiated structures | Hatch Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	193,000
Radiated structures | Hatch Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	213,000
Radiated structures | Vogtle Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	178,000
Radiated structures | Vogtle Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	195,000
Spent fuel management | Hatch Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	49,000
Spent fuel management | Hatch Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	47,000
Spent fuel management | Vogtle Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	49,000
Spent fuel management | Vogtle Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	47,000
Non-radiated structures | Hatch Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	16,000
Non-radiated structures | Hatch Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	22,000
Non-radiated structures | Vogtle Unit No. 1
Nuclear decommissioning
Estimated costs based on site study	26,000
Non-radiated structures | Vogtle Unit No. 2
Nuclear decommissioning
Estimated costs based on site study	$ 33,000

Summary of significant accoun38

Summary of significant accounting policies: - Nuclear decommissioning information (Details) - USD ($)	12 Months Ended		120 Months Ended	336 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2015
Nuclear decommissioning
Additional contribution to external trust funds	$ 0	$ 0
Additional amount collected for nuclear decommissioning	$ 4,750,000	$ 4,750,000
Percentage of decommissioning fund classified as equity	60.00%	60.00%
Percentage of decommissioning funds classified as fixed income securities	40.00%	40.00%
External and Internal Trust Funds:
Cost	$ 498,234,000	$ 442,148,000	$ 498,234,000	$ 498,234,000
Average annualized return produced by the nuclear decommissioning trust fund (as a percent)			6.40%	6.30%
External and Internal Trust Funds
External and Internal Trust Funds:
Net realized gains or losses, interest income and dividends, contributions and fees	31,939,680	12,270,144
External Trust Funds
External and Internal Trust Funds:
Cost		348,957,000			$ 342,639,000
Purchases	450,113,000	395,506,000
Net Proceeds	(430,406,000)	(389,189,000)
Unrealized Gain (Loss)	76,391,000	37,073,000
Fair Value	445,055,000	386,029,000	$ 445,055,000	$ 445,055,000
Internal Trust Funds
External and Internal Trust Funds:
Cost		65,005,000			59,052,000
Purchases	73,153,000	42,783,000
Net Proceeds	(60,920,000)	(36,830,000)
Unrealized Gain (Loss)	11,669,000	7,052,000
Fair Value	88,907,000	72,057,000	88,907,000	88,907,000
Equity
External and Internal Trust Funds:
Cost	246,549,000	237,317,000	246,549,000	246,549,000
Equity | External Trust Funds
External and Internal Trust Funds:
Cost		200,595,000			198,265,000
Purchases	61,406,000	46,865,000
Net Proceeds	(44,607,000)	(43,395,000)
Unrealized Gain (Loss)	76,221,000	38,749,000
Fair Value	293,615,000	240,484,000	293,615,000	293,615,000
Equity | Internal Trust Funds
External and Internal Trust Funds:
Cost		38,798,000			33,513,000
Net Proceeds	4,900,000	5,285,000
Unrealized Gain (Loss)	11,669,000	7,263,000
Fair Value	55,367,000	46,061,000	55,367,000	55,367,000
Debt
External and Internal Trust Funds:
Cost	240,878,000	201,492,000	240,878,000	240,878,000
Debt | External Trust Funds
External and Internal Trust Funds:
Cost		148,011,000			144,187,000
Purchases	388,609,000	347,383,000
Net Proceeds	(384,199,000)	(343,040,000)
Unrealized Gain (Loss)	170,000	(1,675,000)
Fair Value	152,591,000	146,855,000	152,591,000	152,591,000
Debt | Internal Trust Funds
External and Internal Trust Funds:
Cost		26,207,000			25,539,000
Purchases	73,153,000	42,783,000
Net Proceeds	(65,820,000)	(42,115,000)
Unrealized Gain (Loss)		(211,000)
Fair Value	33,540,000	25,996,000	33,540,000	33,540,000
Other | External Trust Funds
External and Internal Trust Funds:
Cost		351,000			$ 187,000
Purchases	98,000	1,258,000
Net Proceeds	(1,600,000)	(2,754,000)
Unrealized Gain (Loss)		(1,000)
Fair Value	$ (1,151,000)	$ (1,310,000)	$ (1,151,000)	$ (1,151,000)

Summary of significant accoun39

Summary of significant accounting policies: - Depreciation and related information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Depreciation
Depreciation expense	$ 218,027,000	$ 211,282,000	$ 180,866,000
Steam production
Depreciation
Annual depreciation rates (as a percent)	2.91%	2.84%	1.93%
Steam production | Minimum
Depreciation
Useful Life	49 years
Steam production | Maximum
Depreciation
Useful Life	65 years
Nuclear production
Depreciation
Annual depreciation rates (as a percent)	1.96%	1.96%	1.55%
Nuclear production | Minimum
Depreciation
Useful Life	37 years
Nuclear production | Maximum
Depreciation
Useful Life	60 years
Hydro production
Depreciation
Useful Life	50 years
Annual depreciation rates (as a percent)	2.00%	2.00%	2.00%
Other production
Depreciation
Annual depreciation rates (as a percent)	2.58%	2.55%	2.38%
Other production | Minimum
Depreciation
Useful Life	27 years
Other production | Maximum
Depreciation
Useful Life	33 years
Transmission
Depreciation
Useful Life	36 years
Annual depreciation rates (as a percent)	2.75%	2.75%	2.75%
General | Minimum
Depreciation
Useful Life	3 years
Annual depreciation rates (as a percent)	2.00%	2.00%	2.00%
General | Maximum
Depreciation
Useful Life	50 years
Annual depreciation rates (as a percent)	33.33%	33.33%	33.33%

Summary of significant accoun40

Summary of significant accounting policies: - Regulatory assets and liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 585,084	$ 545,387
Total Regulatory Liabilities	251,649	197,748
Net Regulatory Assets	333,435	347,639
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	12,813	9,829
Deferral of effects on net margin- Hawk Road Energy Facility | Hawk Road
Regulatory Assets and Liabilities
Total Regulatory Liabilities	19,553	20,163
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	47,087	28,379
Amortization on capital leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	20,055	23,084
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	95,695	86,082
Asset retirement obligations | Nuclear
Regulatory Assets and Liabilities
Total Regulatory Liabilities	53,571	11,766
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 2,875	18,445
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory liabilities	9 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 52,989	55,084
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	26 years
Amortization on capital leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 33,846	32,274
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	40,525	39,986
Asset retirement obligations | Ashpond and Other Decommissioning
Regulatory Assets and Liabilities
Total Regulatory Assets	68,289	33,747
Depreciation expense
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 42,667	44,091
Depreciation expense | Plant Vogtle
Regulatory Assets and Liabilities
Operating license expected extension period for Plant Vogtle	20 years
Operating license period	40 years
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units Number 3 And Number 4
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 48,702	43,444
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	112,102	107,394
Deferral of effects on net margin - Smith Energy Facility | Smith
Regulatory Assets and Liabilities
Total Regulatory Assets	166,454	172,399
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 19,510	$ 16,968
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	32 years
Coal-fired maintenance outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	48 months
Nuclear refueling outage costs | Minimum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	18 months
Nuclear refueling outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	24 months

Summary of significant accoun41

Summary of significant accounting policies: - New accounting pronouncements (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements
Regulatory assets	$ 585,084,000	$ 545,387,000
ASU 2016-01
New Accounting Pronouncements
Regulatory assets	$ 618,000

Fair Value_ - Asset and liabili

Fair Value: - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair value measurement
Long-term investments	$ 140,622,000	$ 99,874,000
Natural gas swaps
Fair value measurement
Derivative assets		(15,090,000)
Derivative liabilities	6,328,000
International equity trust
Fair value measurement
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Total Fair Value | Natural gas swaps
Fair value measurement
Derivative assets		(15,090,000)
Derivative liabilities	$ 6,328,000
Recurring basis | Total Fair Value | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	142,419,000	170,408,000
Recurring basis | Total Fair Value | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	88,820,000	66,861,000
Long-term investments	20,071,000	15,946,000
Recurring basis | Total Fair Value | Corporate bonds and debt
Fair value measurement
Nuclear decommissioning trust funds	66,317,000	60,019,000
Long-term investments	16,215,000	11,853,000
Recurring basis | Total Fair Value | US Treasury securities
Fair value measurement
Nuclear decommissioning trust funds	38,791,000	34,119,000
Long-term investments	6,670,000	5,909,000
Recurring basis | Total Fair Value | Mortgage backed securities
Fair value measurement
Nuclear decommissioning trust funds	49,379,000	41,914,000
Long-term investments	7,267,000	6,844,000
Recurring basis | Total Fair Value | Domestic mutual funds
Fair value measurement
Nuclear decommissioning trust funds	47,833,000
Long-term investments	87,011,000	57,932,000
Recurring basis | Total Fair Value | Municipal bonds
Fair value measurement
Nuclear decommissioning trust funds	92,000	943,000
Recurring basis | Total Fair Value | Federal agency securities
Fair value measurement
Nuclear decommissioning trust funds	3,725,000	7,102,000
Long-term investments	259,000	1,085,000
Recurring basis | Total Fair Value | Other
Fair value measurement
Nuclear decommissioning trust funds	7,679,000	4,663,000
Long-term investments	3,129,000	305,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value measurement
Nuclear decommissioning trust funds	142,419,000	170,408,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities
Fair value measurement
Nuclear decommissioning trust funds	38,791,000	34,119,000
Long-term investments	6,670,000	5,909,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds
Fair value measurement
Nuclear decommissioning trust funds	47,833,000
Long-term investments	87,011,000	57,932,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value measurement
Nuclear decommissioning trust funds	7,679,000	4,663,000
Long-term investments	3,129,000	305,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value measurement
Derivative assets		(15,090,000)
Derivative liabilities	6,328,000
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value measurement
Nuclear decommissioning trust funds	88,820,000	66,861,000
Long-term investments	20,071,000	15,946,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value measurement
Nuclear decommissioning trust funds	66,317,000	60,019,000
Long-term investments	16,215,000	11,853,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities
Fair value measurement
Nuclear decommissioning trust funds	49,379,000	41,914,000
Long-term investments	7,267,000	6,844,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Fair value measurement
Nuclear decommissioning trust funds	92,000	943,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value measurement
Nuclear decommissioning trust funds	3,725,000	7,102,000
Long-term investments	259,000	1,085,000
Recurring basis | Significant Unobservable Inputs (Level 3) | Total Fair Value
Fair value measurement
Financial assets having unobservable inputs classified as Level 3	0	0
Financial liabilities having unobservable inputs classified as Level 3	$ 0	$ 0

Fair Value_ - Estimated fair va

Fair Value: - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Value
Grouping Financial Statement Captions
Long-term debt	$ 8,232,703	$ 8,304,523
Total Fair Value
Grouping Financial Statement Captions
Long-term debt	$ 9,155,942	$ 9,043,029

Derivative instruments_ - Volum

Derivative instruments: - Volume activity of natural gas derivatives (Details) - Natural gas swaps item in Millions	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)
Gas hedges
Derivative liabilities | $	$ 6,328,000
Derivative assets | $		$ 15,090,000
Collateral or letters of credit required to be posted with counterparties, if credit-risk-related contingent features were triggered due to credit rating being downgraded below investment grade | $	$ 6,328,000
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	83.1
2,018
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	27.1
2,019
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	18.9
2,020
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	16.1
2,021
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	13.1
2,022
Gas hedges
Derivative volume activity that is expected to settle or mature each year (in MMBTUs)	7.9

Derivative instruments_ - Inter

Derivative instruments: - Interest rate options (Details) - Interest rate options	3 Months Ended
	Dec. 31, 2011USD ($)item	Mar. 31, 2017USD ($)
Derivative instruments and hedging activities
Number of derivative instruments originally purchased | item	17
Purchased amount of derivative instrument	$ 100,000,000
Notional Dollar Amount	$ 2,200,000,000
Number of nuclear units expected to be financed | item	2
Derivative notional value expired		$ 80,169,000
LIBOR
Derivative instruments and hedging activities
Variable rate basis	LIBOR

Derivative instruments_ - Fair

Derivative instruments: - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Assets:
Fair value of assets		$ 15,090,000
Liabilities:
Fair value of liabilities	$ 6,328,000
Other current assets
Assets:
Fair value of assets	412,000	13,833,000
Other deferred charges
Assets:
Fair value of assets		3,289,000
Other current liabilities
Liabilities:
Fair value of liabilities	1,575,000	54,000
Other deferred credits
Liabilities:
Fair value of liabilities	$ 5,165,000	$ 1,977,000

Derivative instruments_ - Reali

Derivative instruments: - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Total unrealized gains (losses)	$ (6,328)	$ 9,302
Natural gas swaps | Regulatory asset
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized losses on derivatives	(6,328)	(62)
Natural gas swaps | Regulatory liability
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized gains on derivatives		15,152
Natural gas swaps | Fuel
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Gains	3,818	2,445	$ 206
Losses	(1,677)	(19,697)	(20,102)
Total gains (losses) on derivatives	$ 2,141	(17,252)	$ (19,896)
Interest rate options | Regulatory asset
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet
Unrealized losses on derivatives		$ (5,788)

Investments_ - Activity and mat

Investments: - Activity and maturities of available-for-sale securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Available-for-sale securities
Available-for-sale securities, gross unrealized losses that were in effect for less than one year (as a percent)	75.00%
Cost	$ 498,234	$ 442,148
Gains	93,769	52,221
Losses	(6,326)	(8,466)
Fair Value	585,677	485,903
Equity
Available-for-sale securities
Cost	246,549	237,317
Gains	91,954	51,054
Losses	(4,064)	(5,041)
Fair Value	334,439	283,330
Debt
Available-for-sale securities
Cost	240,878	201,492
Gains	1,814	1,167
Losses	(2,262)	(3,423)
Fair Value	240,430	199,236
Cost
Due within one year	54,785	8,292
Due after one year through five years	53,050	52,452
Due after five years through ten years	51,367	65,657
Due after ten years	81,676	75,091
Total	240,878	201,492
Fair Value
Due within one year	54,143	8,268
Due after one year through five years	52,834	52,054
Due after five years through ten years	51,600	64,971
Due after ten years	81,853	73,943
Total	240,430	199,236
Other
Available-for-sale securities
Cost	10,807	3,339
Gains	1
Losses		(2)
Fair Value	$ 10,808	$ 3,337

Investments_ - Gross realized g

Investments: - Gross realized gains, losses and proceeds from available-for-sale securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments:
Gross realized gains	$ 35,523	$ 19,934	$ 53,453
Gross realized losses	(16,909)	(20,030)	(18,989)
Proceeds from sales	$ 521,345	$ 439,540	$ 640,217

Investments_ - Investment in as

Investments: - Investment in associated companies (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Investment in associated companies
Investment in associated companies	$ 74,981	$ 72,783
National Rural Utilities Cooperative Finance Corporation
Investment in associated companies
Investment in associated companies	24,056	24,049
CT Parts, LLC
Investment in associated companies
Investment in associated companies	10,243	10,250
Georgia Transmission Corporation
Investment in associated companies
Investment in associated companies	28,690	27,285
Georgia System Operations Corporation
Investment in associated companies
Investment in associated companies	8,500	7,500
Other
Investment in associated companies
Investment in associated companies	$ 3,492	$ 3,699

Investments_ - Rocky Mountain t

Investments: - Rocky Mountain transactions (Details) - Rocky Mountain	2 Months Ended	12 Months Ended
	Jan. 31, 1997item	Dec. 31, 2012USD ($)installmentitem
Rocky Mountain Lease Transaction
Number of long-term lease transactions | item	6
Percentage of undivided ownership interest	74.61%
Number of separate owner trusts to whom undivided interest was leased | item	6
Number of investors in ownership trusts | item	3
Term of lease as a percentage of the estimated useful life of the jointly owned utility plant	120.00%
Term of lease	30 years
Number of leases terminated prior to end of lease term | item		5
Percentage of leases which remained in place		10.00%
Basic rental payments due		$ 47,882,000
Purchase option price		$ 112,000,000
Number of installments available to pay to the owner trust | installment		5
Outstanding loan amount		$ 74,000,000
Percentage to be purchased under first option if financing cannot be arranged		49.00%
Maximum
Rocky Mountain Lease Transaction
Additional term of sublease		16 years
AIG Matched Funding Corp
Rocky Mountain Lease Transaction
Fund amount, under payment undertaking agreement		$ 74,000,000
Fund amount, under equity funding agreement		$ 37,928,000

Income taxes_ - Statutory feder

Income taxes: - Statutory federal and effective income tax rate and components of deferred tax assets and liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income taxes
Current period income tax expense	$ 0
Current income tax liability	$ 0
Difference between statutory federal income tax rate on income before income taxes and effective income tax rate
Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
Patronage exclusion (as a percent)	(34.10%)	(34.70%)	(34.70%)
AMT credit monetization (as a percent)	(2.20%)	(0.00%)	(0.00%)
Other (as a percent)	(0.90%)	(0.30%)	(0.30%)
Effective income tax rate (as a percent)	(2.20%)	0.00%	0.00%
Deferred tax assets
Net operating losses	$ 19,668,000	$ 29,724,000
Tax credits (alternative minimum tax and other)		599,000
Accounting for Rocky Mountain transactions	231,268,000	349,127,000
Other assets	75,013,000	109,793,000
Deferred tax assets	325,949,000	489,243,000
Less: Valuation allowance	(19,668,000)	(29,724,000)
Net deferred tax assets	306,281,000	459,519,000
Deferred tax liabilities
Depreciation	271,652,000	435,570,000
Accounting for Rocky Mountain transactions	114,514,000	170,402,000
Other liabilities	78,407,000	123,121,000
Deferred tax liabilities	464,573,000	729,093,000
Net deferred tax liabilities	158,292,000	269,574,000
Less: Patronage exclusion	(158,292,000)	$ (269,574,000)
Alternative Minimum Tax Credits
Difference between statutory federal income tax rate on income before income taxes and effective income tax rate
Tax benefit reflected in effective income tax rate	$ 1,117,000

Income taxes_ - NOLs and altern

Income taxes: - NOLs and alternative minimum tax credits (Details) $ in Thousands	Dec. 31, 2017USD ($)
Income taxes
NOLs	$ 76,411
2,018
Income taxes
NOLs	61,533
2,019
Income taxes
NOLs	10,516
2,020
Income taxes
NOLs	$ 4,362

Income taxes_ - Other tax infor

Income taxes: - Other tax information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income taxes
Federal tax rate (as a percent)		35.00%	35.00%	35.00%
Uncertain tax positions		$ 0
State jurisdictions | Minimum
Income taxes
Statute of limitations for filing an income tax return		3 years
State jurisdictions | Maximum
Income taxes
Period during which state impact of any federal changes remains subject to examination by various states		1 year
Statute of limitations for filing an income tax return		5 years
Forecast
Income taxes
Federal tax rate (as a percent)	21.00%

Capital leases_ (Details)

Capital leases: (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)item	Dec. 31, 1985item	Dec. 31, 2016USD ($)
Capital leases
Assumed interest rate on lease (as a percent)		11.05%
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments
Long-term balance	$ 87,192		$ 92,096
Minimum
Capital leases
Leases renewal period	1 year
Maximum
Capital leases
Leases renewal period	5 years
Lease renewal through December 31, 2027
Capital leases
Number of leases for which lease term is extended | item	3
Lease renewal through June 30, 2031
Capital leases
Number of leases for which lease term is extended | item	1
Scherer Unit Number 2
Capital leases
Number of purchasers from which entity sold and leased back assets | item		4
Percentage of undivided ownership interest of purchasers in assets under lease		60.00%
Minimum lease payments under the capital leases together with the present value of the net minimum lease payments
2,018	$ 22,424
2,019	14,949
2,020	14,949
2,021	14,949
2,022	7,474
2023-2031	92,905
Total minimum lease payments	167,650
Less: Amount representing interest	(73,292)
Present value of net minimum lease payments	94,358
Less: Current portion	(7,166)
Long-term balance	$ 87,192

Debt_ - Maturities for long-ter

Debt: - Maturities for long-term debt and capital lease obligations and debt outstanding (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt
Principal	$ 8,232,703	$ 8,304,523
Unamortized Debt Issuance Costs and Debt Discounts	95,613	$ 101,260
Maturities for long-term debt and capital lease obligations
2,018	216,694
2,019	551,964
2,020	350,574
2,021	203,791
2,022	$ 189,305
Long-term debt
Debt
Weighted average interest rate on long-term debt	4.17%	4.34%
Maturities for long-term debt and capital lease obligations
2,018	$ 209,528
2,019	546,502
2,020	344,492
2,021	197,069
2,022	181,764
Facility
Debt
Principal	4,192,450	$ 4,259,723
Unamortized Debt Issuance Costs and Debt Discounts	51,593	55,754
Maturities for long-term debt and capital lease obligations
2,018	188,857
2,019	157,105
2,020	172,189
2,021	177,383
2,022	180,754
FMBs
Debt
Principal	3,057,072	3,058,083
Unamortized Debt Issuance Costs and Debt Discounts	34,673	36,717
Maturities for long-term debt and capital lease obligations
2,018	1,010
2,019	351,010
2,020	1,010
2,021	1,010
2,022	1,010
PCBs
Debt
Principal	980,770	980,770
Unamortized Debt Issuance Costs and Debt Discounts	9,347	8,789
Maturities for long-term debt and capital lease obligations
2,018	18,677
2,019	37,352
2,020	170,902
2,021	18,676
Series 2009 and Series 2010 bonds
Maturities for long-term debt and capital lease obligations
2,018	18,700
2,019	37,400
2,020	170,900
2,021	18,700
CFC
Debt
Principal	2,411	3,347
Maturities for long-term debt and capital lease obligations
2,018	984
2,019	1,035
2,020	391
CoBank
Debt
Principal		$ 2,600
Capital Lease Obligations
Maturities for long-term debt and capital lease obligations
2,018	7,166
2,019	5,462
2,020	6,082
2,021	6,722
2,022	$ 7,541

Debt_ - Other information (Deta

Debt: - Other information (Details)	Dec. 28, 2017USD ($)item	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)item	Oct. 12, 2017USD ($)	Sep. 28, 2017USD ($)	Dec. 31, 2016	Feb. 20, 2014USD ($)item
Debt
Weighted average interest rate on short-term borrowings (as a percent)			1.58%			0.93%
Line of credit
Debt
Aggregate borrowings			$ 1,610,000,000
Number of separate facilities | item			4
Letter of credit
Debt
Aggregate borrowings			$ 760,000,000
Available borrowing capacity			509,000,000
Letters of credit, amount outstanding			251,000,000
Commercial paper
Debt
Line of credit, amount outstanding			$ 191,000,000
Facility
Debt
Number of future advance promissory notes | item							2
Spread on variable rate (as a percent)			0.375%
Line of credit, amount outstanding			$ 1,735,586,000
Term of credit facility (in years)			5 years
Period of cessation of construction activities which would result in prepayment of outstanding principal			12 months
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal			12 months
Facility | Maximum
Debt
Aggregate borrowings							$ 3,057,069,461
Capitalized interest							$ 335,471,604
Conditional commitment issued by guarantor under the Loan Guarantee Agreement					$ 1,620,000,000
Rural Utilities Service Guaranteed Loans
Debt
Proceeds from issuance of debt		$ 2,636,000	$ 22,098,000
First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A Burke, Heard, Monroe and 2017B Burke Indexed put bonds - weekly reset, 2.56% due 2040 through 2045
Debt
Principal amount				$ 122,620,000
First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 CDEF Burke
Debt
Repayments of debt, defeasance	$ 399,785,000
Principal amount	$ 399,785,000
Number of bonds purchased by bank | item	2
Pollution Control Revenue Bonds Series 2017C and Series 2017D
Debt
Principal amount	$ 200,000,000
Fixed rate interest (as a percent)	4.125%
Pollution Control Revenue Bonds Series 2017E
Debt
Principal amount	$ 100,000,000
Fixed rate interest (as a percent)	3.25%
Pollution Control Revenue Bonds Series 2017F
Debt
Principal amount	$ 99,785,000
Fixed rate interest (as a percent)	3.00%

Electric plant, construction 58

Electric plant, construction and related agreements: - Summary of plant investments and related accumulated depreciation (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Electric plant, construction and related agreements
Investment	$ 8,886,407,000	$ 8,786,839,000
Accumulated Depreciation	(4,302,332,000)	(4,115,339,000)
Total construction work in progress	2,935,868,000	3,228,214,000
Plant acquisition adjustments	197,000,000	197,000,000
Vogtle Units Number 1 And Number 2
Electric plant, construction and related agreements
Investment	2,916,852,000	2,885,559,000
Accumulated Depreciation	$ (1,751,558,000)	(1,712,642,000)
Ownership interest (as a percent)	30.00%
Vogtle Units Number 3 And Number 4
Electric plant, construction and related agreements
Investment	$ 36,745,000	36,163,000
Accumulated Depreciation	(2,514,000)	(1,567,000)
Total construction work in progress	$ 2,721,949,000	3,069,476,000
Ownership interest (as a percent)	30.00%
Guarantee obligations, maximum exposure received	$ 1,104,000,000
Hatch Units Number 1 And Number 2
Electric plant, construction and related agreements
Investment	824,890,000	809,971,000
Accumulated Depreciation	$ (420,000,000)	(407,400,000)
Ownership interest (as a percent)	30.00%
Wansley Units Number 1 And Number 2
Electric plant, construction and related agreements
Investment	$ 587,436,000	577,781,000
Accumulated Depreciation	$ (236,155,000)	(190,974,000)
Ownership interest (as a percent)	30.00%
Scherer Unit Number 1
Electric plant, construction and related agreements
Investment	$ 1,102,085,000	1,083,772,000
Accumulated Depreciation	$ (399,774,000)	(368,948,000)
Ownership interest (as a percent)	60.00%
Doyle
Electric plant, construction and related agreements
Investment	$ 136,351,000	135,849,000
Accumulated Depreciation	$ (106,370,000)	(102,642,000)
Ownership interest (as a percent)	100.00%
Rocky Mountain Units Number 1, Number 2 And Number 3
Electric plant, construction and related agreements
Investment	$ 609,048,000	607,742,000
Accumulated Depreciation	$ (246,758,000)	(234,765,000)
Ownership interest (as a percent)	75.00%
Hartwell
Electric plant, construction and related agreements
Investment	$ 225,808,000	227,878,000
Accumulated Depreciation	$ (104,269,000)	(104,342,000)
Ownership interest (as a percent)	100.00%
Hawk Road
Electric plant, construction and related agreements
Investment	$ 251,671,000	250,595,000
Accumulated Depreciation	$ (73,998,000)	(69,984,000)
Ownership interest (as a percent)	100.00%
Talbot
Electric plant, construction and related agreements
Investment	$ 292,250,000	290,790,000
Accumulated Depreciation	$ (128,344,000)	(119,874,000)
Ownership interest (as a percent)	100.00%
Chattahoochee
Electric plant, construction and related agreements
Investment	$ 313,587,000	313,693,000
Accumulated Depreciation	$ (133,378,000)	(123,946,000)
Ownership interest (as a percent)	100.00%
Smith
Electric plant, construction and related agreements
Investment	$ 642,732,000	614,453,000
Accumulated Depreciation	$ (170,366,000)	(176,701,000)
Ownership interest (as a percent)	100.00%
Wansley
Electric plant, construction and related agreements
Investment	$ 3,887,000	3,582,000
Accumulated Depreciation	$ (3,552,000)	(3,569,000)
Ownership interest (as a percent)	30.00%
Transmission
Electric plant, construction and related agreements
Investment	$ 92,929,000	92,085,000
Accumulated Depreciation	(55,502,000)	(53,251,000)
Other production
Electric plant, construction and related agreements
Investment	92,179,000	99,644,000
Accumulated Depreciation	(54,927,000)	(61,356,000)
Scherer Unit Number 2
Electric plant, construction and related agreements
Investment	757,957,000	757,282,000
Accumulated Depreciation	$ (414,867,000)	(383,378,000)
Ownership interest (as a percent)	60.00%
Environmental and other generation improvements
Electric plant, construction and related agreements
Total construction work in progress	$ 212,476,000	158,181,000
Other Construction Work In Progress
Electric plant, construction and related agreements
Total construction work in progress	$ 1,443,000	$ 557,000

Electric plant, construction 59

Electric plant, construction and related agreements: - Construction information (Details) - Vogtle Units Number 3 And Number 4	Jan. 11, 2018item	Nov. 02, 2017USD ($)	Jun. 09, 2017USD ($)item	Dec. 31, 2017USD ($)item	Dec. 31, 2008itemMW
Construction
Number of petitions which parties have filed | item	2
Guarantee obligations, maximum exposure received				$ 1,104,000,000
Total investment in additional vogtle units				$ 2,938,000,000
Ownership participation agreement
Construction
Number of nuclear units | item				2
Ownership interest (as a percent)				30.00%
Ownership participation agreement | Occurrence of certain adverse events | Minimum
Construction
Ownership interests voting required to continue construction (as a percent)		90.00%
Increase in project budget		$ 1,000,000,000
Project extension term		1 year
Ownership approval to change primary construction contractor (as a percent)		90.00%
Ownership approval required for material amendments (as a percent)		67.00%
Engineering, Procurement and Construction Agreement (the EPC Agreement) | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Construction
Number of nuclear units | item					2
Generating capacity of each nuclear unit | MW					1,100
Project budget				$ 7,000,000,000
Estimated aggregate cancellation costs of site				$ 230,000,000
Guarantee Settlement Agreement | In the event of abandonment of work
Construction
Guarantee obligations, maximum exposure			$ 1,104,000,000
Guarantee Settlement Agreement | The Co-owners and Toshiba | In the event of abandonment of work
Construction
Guarantee obligations, maximum exposure			$ 3,680,000,000
Number of payments made | item			3
Amended and Restated Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Construction
Written notice period for termination of agreement			30 days

Employee benefit plans_ (Detail

Employee benefit plans: (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Employee benefit plans:
Maximum percentage of eligible annual compensation that the employee can contribute subject to IRS limitations	60.00%
Percentage of employee's contribution percent matched	75.00%
Employer matching contribution, as a percent of employee's eligible compensation	6.00%
Amount of contributions to the matching feature of the 401(k) plan	$ 1,436,000	$ 1,371,000	$ 1,310,000
Contribution to employer retirement contribution feature (as a percent)	11.00%		8.00%
Amount of contributions to the employer retirement contribution feature of the 401(k) plan	$ 3,791,000	$ 3,678,000	$ 2,611,000

Nuclear insurance_ (Details)

Nuclear insurance: (Details)	12 Months Ended
	Dec. 31, 2017USD ($)item
Nuclear insurance:
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Act	$ 13,400,000,000
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant	450,000,000
Maximum amount that a company could be assessed per incident for each licensed reactor	127,000,000
Maximum aggregate amount that a reactor can assess in a calendar period for each incident	$ 19,000,000
Number of nuclear reactors in which entity has ownership interest | item	4
Maximum deferred premium amount which the entity could be assessed per incident on the basis of its joint ownership interest in four nuclear reactors	$ 153,000,000
Maximum deferred premium amount which the entity could be assessed per calendar year on the basis of its joint ownership interest in four nuclear reactors	$ 23,000,000
Period considered for inflation adjustment for maximum assessment per reactor and maximum yearly assessment	5 years
Maximum property damage insurance provided to nuclear generating facilities	$ 1,500,000,000
Additional coverage provided for losses in excess of primary coverage	1,250,000,000
Sublimit for non-nuclear losses	750,000,000
Maximum limits for accidental property damage occurring during construction under the policy	2,750,000,000
Portion of the current maximum annual assessment for Georgia Power that would be payable by the entity based on ownership share	40,000,000
Aggregate payment for claims resulting from terrorist acts in one year period	$ 3,200,000,000

Commitments_ - Operating Leases

Commitments: - Operating Leases (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating leases
2,018	$ 5,277,000
2,019	2,923,000
2,020	583,000
Rental expenses	$ 4,919,000	$ 4,456,000	$ 4,849,000

Commitments_ - Long-term commit

Commitments: - Long-term commitments (Details) - USD ($)	Apr. 11, 2014	Dec. 31, 2017
Coal
Fuel
2,018		$ 14,809,000
2,019		7,526,000
2,020		4,598,000
Nuclear Fuel
Fuel
2,018		56,500,000
2,019		32,500,000
2,020		25,300,000
2,021		30,900,000
2,022		26,300,000
Thereafter		39,600,000
Gas Transportation
Fuel
2,018		66,905,000
2,019		60,854,000
2,020		57,530,000
2,021		57,481,000
2,022		48,515,000
Thereafter		$ 776,587,000
Precedent Agreement | Transcontinental Gas Pipeline Company, LLC (Transco)
Fuel
Base term of an agreement	25 years
Aggregate agreement fixed charge	$ 942,500,000

Quarterly financial data (una64

Quarterly financial data (unaudited): (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Quarterly financial data (unaudited):
Operating revenues	$ 327,001	$ 385,906	$ 367,119	$ 354,170	$ 348,714	$ 431,013	$ 379,343	$ 348,161	$ 1,434,196	$ 1,507,231	$ 1,349,825
Operating margin	31,548	68,770	69,222	69,330	39,494	70,929	74,148	71,093	238,870	255,664	257,458
Net margin	$ (12,408)	$ 20,805	$ 21,426	$ 21,454	$ (12,160)	$ 18,630	$ 23,277	$ 20,598	$ 51,277	$ 50,345	$ 48,341
Margins for interest ratio	1.14				1.14				1.14	1.14	1.14