CNX Resources (CNX) 10-K 7 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 22, 2018	Jun. 30, 2017
Document Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Registrant Name	CNX Resources Corporation
Entity Central Index Key	1,070,412
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		223,758,284
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,685,654,421

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Oil and Gas Sales Revenue	$ 1,125,224	$ 793,248	$ 726,921
Gain (Loss) on Hedging Activity	206,930	(141,021)	392,942
Gas Royalty Interests and Purchased Gas Sales	53,795	43,256	14,450
Other Operating Income	69,182	64,485	64,424
Other Income	69,182	64,485	64,424
Gain (Loss) on Disposition of Assets	(188,063)	(14,270)	(61,148)
Total Revenue and Other Income	1,455,131	759,968	1,198,737
Oil and Gas Property, Lease Operating Expense	88,932	96,434	121,847
Gas Gathering, Transportation, Marketing and Processing Costs	382,865	374,350	343,403
Production Tax Expense	29,267	31,049	30,438
E&P Depreciation, Depletion, and Amortization	412,036	419,939	371,783
Exploration and Production Costs	48,074	14,522	10,119
Production Royalty Interests and Purchased Gas Costs	52,597	42,717	10,721
Other Expenses	112,369	88,754	65,858
Impairment of Oil and Gas Properties	137,865	0	828,905
Results of Operations, General and Administrative Related to Oil and Gas Producing Activities	93,211	104,843	102,270
Oil and Gas Production Expense	1,357,216	1,172,608	1,885,344
Other Nonoperating Expense	3,825	4,783	38,226
Gain (Loss) on Extinguishment of Debt	2,129	0	67,751
Interest Expense	161,443	182,195	199,121
Other General Expense	(20,666)	172,708	243,950
Total Costs	1,336,550	1,345,316	2,129,294
Earnings Before Income Taxes	118,581	(585,348)	(930,557)
Income Taxes	(176,458)	(34,403)	(280,359)
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest	295,039	(550,945)	(650,198)
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	85,708	(297,157)	275,313
Net Income (Loss)	$ 380,747	(848,102)	(374,885)
Net Income Attributable to CONSOL Energy Inc Shareholders		$ (839,148)	$ (364,475)
Earnings per share:
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.29	$ (2.40)	$ (2.84)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	0.37	(1.30)	1.20
Basic	1.66	(3.70)	(1.64)
Income (Loss) from Continuing Operations, Per Diluted Share	1.28	(2.40)	(2.84)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	0.37	(1.30)	1.20
Dilutive	1.65	(3.70)	(1.64)
Dividends Paid Per Share	$ 0	$ 0.01	$ 0.15

Consolidated Statement of Compr

Consolidated Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Income (Loss) Attributable to Parent [Abstract]
Net Income (Loss)	$ 380,747	$ (848,102)	$ (374,885)
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	12,228	(33,226)	(86,447)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	(43,470)	(78,051)
Other Comprehensive Income (Loss), Net of Tax	12,228	(76,696)	(164,498)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 392,975	$ (924,798)	$ (539,383)

Consolidated Statement of Comp4

Consolidated Statement of Comprehensive Income Parentheticals - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ (12,228)	$ 33,226	$ 86,447
Cash Flow Hedging [Member]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax	0	0	(55,767)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	25,011	45,054	10,465
Adjustment For Actuarially Determined Liabilities [Member]
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 16,281	$ 53,252	$ (56,304)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current Assets:
Cash and Cash Equivalents	$ 509,167	$ 46,299
Accounts and Notes Receivable:
Trade	156,817	124,514
Other Receivables, Net, Current	48,908	51,145
Inventories	10,742	15,301
Income Taxes Receivable, Current	31,523	114,481
Prepaid Expenses	95,347	75,576
Disposal Group, Including Discontinued Operation, Assets, Current	0	198,823
Total Current Assets	852,504	626,139
Property, Plant and Equipment:
Property, Plant and Equipment, Gross	9,316,495	9,183,959
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	3,526,742	3,214,984
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	0	2,171,464
Total Property, Plant and Equipment-Net	5,789,753	8,140,439
Other Assets:
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	197,921	190,964
Other	91,735	95,515
Disposal Group, Including Discontinued Operation, Other Assets	0	126,634
Other Assets	289,656	413,113
Total Assets	6,931,913	9,179,691
Current Liabilities:
Accounts Payable	211,161	157,102
Long-term Debt and Capital Lease Obligations, Current	7,111	7,924
Other Accrued Liabilities, Current	223,407	389,641
Disposal Group, Including Discontinued Operation, Liabilities, Current	0	385,347
Total Current Liabilities	441,679	940,014
Long-Term Debt:
Long-term Debt, Excluding Current Maturities	2,187,026	2,421,168
Capital Lease Obligations	20,347	27,262
Disposal Group, Including Discontinued Operation, Liabilities	0	313,639
Total Long-Term Debt	2,207,373	2,762,069
Deferred Credits and Other Liabilities
Deferred Tax Liabilities, Net, Noncurrent	44,373	105,096
Gas Well Closing	198,768	195,704
Salary Retirement	34,748	32,546
Other	105,073	138,059
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	0	1,065,315
Total Deferred Credits and Other Liabilities	382,962	1,536,720
TOTAL LIABILITIES	3,032,014	5,238,803
Stockholders' Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 223,743,322 Issued and Outstanding at December 31, 2017; 229,443,008 Issued and Outstanding at December 31, 2016	2,241	2,298
Capital in Excess of Par Value	2,450,323	2,460,864
Preferred Stock, 15,000,000 shares authorized, None issued and outstanding	0	0
Retained Earnings	1,455,811	1,727,789
Accumulated Other Comprehensive Loss	(8,476)	(392,556)
Total CONSOL Energy Inc. Stockholders' Equity	3,899,899	3,798,395
Noncontrolling Interest in Limited Partnerships	0	142,493
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	3,899,899	3,940,888
TOTAL LIABILITIES AND EQUITY	$ 6,931,913	$ 9,179,691

Consolidated Balance Sheets Par

Consolidated Balance Sheets Parentheticals - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Common Stock, Shares, Outstanding	223,743,322	229,443,008
Common Stock [Member]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	500,000,000	500,000,000
Common Stock, Shares, Issued	223,743,322	229,443,008
Common Stock, Shares, Outstanding	223,743,222	229,443,008
Treasury Stock, Shares	0	0
Preferred Stock [Member]
Preferred Stock, Shares Authorized	15,000,000	15,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Capital in Excess of Par Value	Retained Earnings (Deficit)	Accumulated Other Comprehensive Income (Loss)	Total CNX Resources Stockholders' Equity	Non-Controlling Interest
Balance, Beginning of Period at Dec. 31, 2014	$ 5,329,458	$ 2,306	$ 2,424,102	$ 3,054,150	$ (151,100)	$ 5,329,458	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(374,885)	0	0	(374,885)	0	(374,885)	10,410
Net Income Attributable to CONSOL Energy Inc Shareholders	(364,475)
Gas Cash Flow Hedge	78,051	0	0	0	78,051	78,051	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	(86,447)	0	0	0	(86,447)	(86,447)	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(539,383)	0	0	(374,885)	(164,498)	(539,383)	10,410
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(528,973)
Issuance of Treasury Stock	(12,181)	0	0	(12,181)	0	(12,181)	0
Proceeds from Issuance of Common Stock	8,288	10	8,278	0	0	8,288	0
Stock Repurchased During Period, Value	(71,674)	(22)	(17,683)	(53,969)	0	(71,674)	0
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation	(3,706)	0	(3,706)	0	0	(3,706)	0
Amortization of Stock-Based Compensation Awards	24,506	0	24,506	0	0	24,506	0
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders	(5,060)	0	0	0	0	0	(5,060)
Net Change in Noncontrolling Interest	148,399	0	0	0	0	0	148,399
Dividends	33,281	0	0	33,281	0	33,281	0
Balance, End of Period at Dec. 31, 2015	4,855,776	2,294	2,435,497	2,579,834	(315,598)	4,702,027	153,749
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax	(164,498)
Net Income (Loss)	(848,102)	0	0	(848,102)	0	(848,102)	8,954
Net Income Attributable to CONSOL Energy Inc Shareholders	(839,148)
Gas Cash Flow Hedge	43,470	0	0	0	43,470	43,470	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	(33,226)	0	0	0	(33,488)	(33,488)	(262)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(924,798)
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	(915,844)	0	0	(848,102)	(76,958)	(925,060)	9,216
Stock Granted, Value, Share-based Compensation, Forfeited	(1,649)	0	0	(1,649)	0	(1,649)	0
Proceeds from Issuance of Common Stock	4	4	0	0	0	4	0
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation	(4,931)	0	(4,931)	0	0	(4,931)	0
Amortization of Stock-Based Compensation Awards	31,483	0	30,298	0	0	30,298	1,185
Net Change in Noncontrolling Interest	(21,657)	0	0	0	0	0	(21,657)
Dividends	2,294	0	0	(2,294)	0	(2,294)	0
Balance, End of Period at Dec. 31, 2016	3,940,888	2,298	2,460,864	1,727,789	(392,556)	3,798,395	142,493
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax	(76,696)
Net Income (Loss)	380,747	0	0	380,747	0	380,747	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	12,228	0	0	0	12,228	12,228	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	392,975
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest	392,975	0	0	380,747	12,228	392,975	0
Stock Granted, Value, Share-based Compensation, Forfeited	(6,681)	0	0	(6,681)	0	(6,681)	0
Proceeds from Issuance of Common Stock	1,009	7	1,002	0	0	1,009	0
Stock Repurchased and Retired During Period, Value	(103,209)	(64)	(51,223)	(51,922)	0	(103,209)	0
Stockholders' Equity Note, Spinoff Transaction	(342,066)	0	22,697	(594,122)	371,852	(199,573)	(142,493)
Amortization of Stock-Based Compensation Awards	16,983	0	16,983	0	0	16,983	0
Balance, End of Period at Dec. 31, 2017	3,899,899	$ 2,241	$ 2,450,323	$ 1,455,811	$ (8,476)	$ 3,899,899	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Other Comprehensive Income (Loss), Net of Tax	$ 12,228

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Activities:
Net Income (Loss)	$ 380,747	$ (848,102)	$ (374,885)
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	(85,708)	297,157	(275,313)
Depreciation, Depletion and Amortization	412,036	419,939	371,783
Gain (Loss) on Hedging Activity	(206,930)	141,021	(392,942)
Derivative, Cash Received on Hedge	(41,174)	245,212	196,348
Impairment of Long-Lived Assets to be Disposed of	137,865	0	828,905
Share-based Compensation	16,983	19,316	14,314
(Gain) Loss on Sale of Assets	(188,063)	(14,270)	(61,148)
Gain (Loss) on Extinguishment of Debt	2,129	0	67,751
Deferred Income Tax Expense (Benefit)	(142,829)	75,892	(275,541)
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	0	22,268	35,466
Equity in Earnings of Affiliates	(49,830)	(53,078)	(54,897)
Changes in Operating Assets:
Accounts and Notes Receivable	(32,792)	(46,434)	101,107
Inventories	4,254	(1,486)	933
Increase (Decrease) in Income Taxes	76,196	(91,313)	69,404
Prepaid Expenses	631	76,668	128,402
Changes in Other Assets	22,018	(2,473)	63,656
Changes in Operating Liabilities:
Accounts Payable	45,669	(17,227)	(131,825)
Increase (Decrease) in Interest Payable, Net	(2,955)	(1,144)	26,486
Increase (Decrease) in Income Taxes Payable	0	0	0
Other Operating Liabilities	37,712	(48,315)	(161,181)
Changes in Other Liabilities	(7,778)	78,140	46,173
Other	54,887	15,461	12,609
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	433,068	267,232	235,605
Cash Provided by (Used in) Operating Activities, Discontinued Operations	215,619	197,026	275,991
Net Cash Provided by Operating Activities	648,687	464,258	511,596
Investing Activities:
Capital Expenditures	(632,846)	(172,739)	(840,349)
Proceeds from Divestiture of Interest in Joint Venture	0	213,295	0
Proceeds from Sales of Assets	414,185	46,989	86,737
Net Investment in Equity Affiliates	42,873	73,743	(72,288)
Cash Provided by (Used in) Investing Activities, Discontinued Operations	(46,133)	326,083	(170,317)
Net Cash Used in Investing Activities	(221,921)	487,371	(996,217)
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(175,788)	161,288	(825,900)
Financing Activities:
(Payments on) Proceeds from Short-Term Borrowings	0	(952,000)	952,000
Payments on Miscellaneous Borrowings	(8,037)	(7,802)	(3,645)
Payments On Long Term Notes Including Redemption Premium	(239,716)	0	(1,263,719)
Proceeds from Spin-off of CONSOL Energy Inc.	425,000	0	0
Proceeds from Issuance of Long-Term Notes	0	0	492,760
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Financing Activities	0	0	208
Dividends Paid	0	(2,294)	(33,281)
Proceeds from Issuance of Common Stock	1,009	4	8,288
Proceeds from Sale of Treasury Stock	(6,681)	(1,649)	(12,181)
Treasury Stock, Value, Acquired, Cost Method	(103,209)	0	(71,674)
Payments of Debt Issuance Costs	(361)	0	(6,250)
Cash Provided by (Used in) Financing Activities, Discontinued Operations	(31,903)	(6,663)	311,270
Net Cash (Used in) Provided by Financing Activities	36,102	(970,404)	373,776
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	68,005	(963,741)	62,506
Net Increase in Cash and Cash Equivalents	462,868	(18,775)	(110,845)
Cash and Cash Equivalents at Beginning of Period	46,299	65,074	175,919
Cash and Cash Equivalents at End of Period	$ 509,167	$ 46,299	$ 65,074

Discontinued Operations (Notes)

Discontinued Operations (Notes)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	NOTE 2—DISCONTINUED OPERATIONS: On November 28, 2017, CNX announced that it had completed the tax-free spin-off of its coal business resulting in two independent, publicly traded companies, a coal company, CONSOL Energy, formerly known as CONSOL Mining Corporation and CNX, a natural gas exploration and production company. Following the Separation, CONSOL Energy and its subsidiaries hold the coal assets previously held by CNX, including its Pennsylvania Mining Complex, Baltimore Marine Terminal, its direct and indirect ownership interest in CONSOL Coal Resources LP, formerly known as CNXC Coal Resources LP and other related coal assets previously held by CNX. As of the close of business on November 15, 2017, CNX's shareholders received one share of CONSOL Energy common stock for every eight shares of CNX’s common stock held as of the Record Date. The coal company has been reclassified to discontinued operations for all periods presented. In August 2016, CNX completed the sale of the Miller Creek and Fola Mining Complexes. In the transaction, the buyer acquired the Miller Creek and Fola assets and assumed the Miller Creek and Fola mine closing and reclamation liabilities. In order to equalize the value exchange, CNX paid $28,271 of cash at closing, which included property taxes associated with the properties sold and other closing costs (a portion of which will be held in escrow for purposes of obtaining the surety bonds required for the permits to transfer). This amount was included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flows for the year ended December 31, 2016 . CNX will also pay a total of $13,700 in remaining installments over the next three years, ending in January 2020. The net loss on the sale of $53,130 , excluding the related impairment charge discussed below, was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. Prior to the closing, the Miller Creek and Fola Mining Complexes were classified as held for sale in discontinued operations and in accordance with the accounting guidance for Property, Plant and Equipment, assets held for sale are required to be measured at the lower of carrying value or fair value less costs to sell. Upon meeting the assets held for sale criteria, the Company determined the carrying value of the Miller Creek and Fola Mining Complexes exceeded the fair value less costs to sell. As a result, an impairment charge of $355,681 was recorded during the year ended December 31, 2016 . This impairment was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income. In March 2016, CNX completed the sale of its membership interests in CONSOL Buchanan Mining Company, LLC (BMC), which owned and operated the Buchanan Mine located in Mavisdale, Virginia; various assets relating to the Amonate Mining Complex located in Amonate, Virginia; Russell County, Virginia coal reserves and Pangburn Shaner Fallowfield coal reserves located in Southwestern, Pennsylvania to Coronado IV LLC ("Coronado"). Various CNX assets were excluded from the sale including coalbed methane, natural gas and minerals other than coal, current assets of BMC, certain coal seams and certain surface rights and properties. Coronado assumed only specified liabilities and various CNX liabilities were excluded and not assumed. The excluded liabilities included BMC’s indebtedness, trade payables and liabilities arising prior to closing, as well as the liabilities of the subsidiaries other than BMC which were parties to the sale. In addition, the buyer agreed to pay CNX for Buchanan Mine coal sold outside the U.S. and Canada during the five years following closing a royalty of 20% of any excess of the gross sales price per ton over the following amounts: (1) year one, $75.00 per ton; (2) year two, $78.75 per ton; (3) year three, $82.69 per ton; (4) year four, $86.82 per ton; (5) year five, $91.16 per ton. Total royalty income recognized under this agreement was $10,073 and $9,575 for the years ended December 31, 2017 and 2016, respectively. In connection with the separation and distribution agreement with CONSOL Energy (See Note 20 - Related Party) the royalty related to Buchanan Mine was retained by CNX and any related income is included in Other Expense on the Consolidated Statements of Income. Cash proceeds of $402,799 were received at closing and are included in Net Cash Provided by Discontinued Investing Activities on the Consolidated Statements of Cash Flows for the year ended December 31, 2016 . The net loss on the sale was $38,364 and was included in Loss from Discontinued Operations, net on the Consolidated Statements of Income for the year ended December 31, 2016 . For all periods presented in the accompanying Consolidated Statements of Income, BMC along with the various other assets and the Miller Creek and Fola Mining Complexes are classified as discontinued operations. The following table details selected financial information for the divested business included within discontinued operations: For the Years Ended December 31, 2017 2016 2015 Coal Sales $ 1,127,907 $ 1,199,950 $ 1,687,237 Freight-Outside Coal 66,297 47,790 25,597 Miscellaneous Other Income 73,645 74,382 67,969 Gain on Sale of Assets — 269,124 13,362 Total Revenue and Other Income $ 1,267,849 $ 1,591,246 $ 1,794,165 Total Costs 1,147,254 1,652,921 1,362,508 Income (Loss) From Operations Before Income Taxes $ 120,595 $ (61,675 ) $ 431,657 Impairment on Assets Held for Sale — 355,681 — Income Tax Expense (Benefit) 23,984 (129,153 ) 145,934 Less: Net Income Attributable to Noncontrolling interest 10,903 8,954 10,410 Income (Loss) From Discontinued Operations, net $ 85,708 $ (297,157 ) $ 275,313 The major classes of assets and liabilities of discontinued operations: December 31, Assets: Cash and Cash Equivalents $ 14,176 Accounts Receivable - Trade 95,790 Other Receivables 18,756 Inventories 50,160 Prepaid Expense 17,571 Other Current Assets 2,370 Total Current Assets $ 198,823 Property, Plant and Equipment, Net 2,171,464 Other Assets 126,634 Total Assets of Discontinued Operations $ 2,496,921 Liabilities: Accounts Payable $ 84,550 Other Current Liabilities 300,797 Total Current Liabilities $ 385,347 Long Term Debt 313,639 Postretirement Benefits Other Than Pensions 659,474 Pneumoconiosis Benefits 108,073 Mine Closing 218,631 Gas Well Closing 27,648 Workers' Compensation 65,932 Salary Retirement 79,997 Other liabilities (94,440 ) Total Liabilities of Discontinued Operations $ 1,764,301

Acquisitions and Dispositions

Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2017
ACQUISITIONS AND DISPOSITIONS: [Abstract]
Acquisitions and Dispositions:	ACQUISITIONS AND DISPOSITIONS: In September 2017, CNX closed on the sale of approximately 22,000 acres of surface land in Colorado. CNX received net cash proceeds of $23,703 which is included in the cash flows from investing activities. The net gain on the sale was $18,758 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In a two part closing in July and September 2017, CNX executed the sale of approximately 7,500 net undeveloped acres of the Marcellus Shale in Allegheny and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $36,649 which is included in the cash flows from investing activities. The net gain on the sale of these assets was $15,251 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In June 2017, CNX closed on the sale of approximately 11,100 net undeveloped acres of the Marcellus and Utica Shale in Allegheny, Washington, and Westmoreland counties, Pennsylvania. CNX received total cash proceeds of $83,500 which is included in cash flows from investing activities. The net gain on the sale of these assets was $58,541 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In June 2017, the Company finalized the sale of 12 producing wells, 15 drilled but uncompleted wells (DUCs), and approximately 11,000 net developed and undeveloped Marcellus and Utica acres in Doddridge and Wetzel counties in West Virginia that were previously classified as held for sale. CNX received total cash proceeds of $125,507 which is included in cash flows from investing activities, as well as undeveloped acreage. The net loss on the sale was $9,430 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In May 2017, CNX finalized the sale of approximately 6,300 net undeveloped acres of the Utica-Point Pleasant Shale in Jefferson, Belmont and Guernsey counties, Ohio that were previously classified as held for sale. CNX received total cash proceeds of $76,585 which is included in cash flows from investing activities. The net gain on the sale of these assets was $72,346 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In April 2017, CNX finalized the sale of its Knox Energy LLC and Coalfield Pipeline Company subsidiaries that were previously classified as held for sale. At closing, CNX received net cash proceeds of $19,055 which is included in cash flows from investing activities. The net gain on the sale of these assets was $606 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income. In February 2017, Knox met all of the criteria to be classified as held for sale. As part of the required evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $ 137,865 was included in Impairment of Exploration and Production Properties within the the Consolidated Statements of Income during the year ended December 31, 2017. In September 2015, CNX sold its 49% interest in Western Allegheny Energy (WAE), a joint venture with Rosebud Mining Company engaged in coal mining activities in Pennsylvania. At closing, the Company received $76,297 in cash and a $2,136 reduction in certain liabilities. During the third quarter of 2015, CNX also received a cash distribution of $10,780 from WAE. The net gain on the sale was $48,468 and was included in the Gain on Sale of Assets in the Consolidated Statements of Income.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES: Income tax benefit provided on earnings from continuing operations consisted of: For The Years Ended December 31, 2017 2016 2015 Current: U.S. Federal $ (31,791 ) $ (101,596 ) $ 839 U.S. State (1,838 ) (8,699 ) (5,657 ) (33,629 ) (110,295 ) (4,818 ) Deferred: U.S. Federal (166,112 ) 80,207 (308,797 ) U.S. State 23,283 (4,315 ) 33,256 (142,829 ) 75,892 (275,541 ) Total Income Tax Benefit $ (176,458 ) $ (34,403 ) $ (280,359 ) The components of the net deferred taxes are as follows: December 31, 2017 2016 Deferred Tax Assets: Alternative minimum tax 188,080 219,872 Net operating loss - State 107,756 74,310 Net operating loss - Federal 99,524 144,450 Foreign tax credit 44,402 39,850 Gas well closing 16,648 20,512 Salary retirement 9,404 16,928 Capital lease 2,020 3,210 Gas derivatives — 72,105 Other 33,697 48,961 Total Deferred Tax Assets 501,531 640,198 Valuation Allowance (136,576 ) (282,778 ) Net Deferred Tax Assets 364,955 357,420 Deferred Tax Liabilities: Property, plant and equipment (385,366 ) (450,695 ) Gas derivatives (15,248 ) — Advance gas royalties (3,648 ) (5,824 ) Equity Partnerships (1,251 ) (2,237 ) Other (3,815 ) (3,760 ) Total Deferred Tax Liabilities (409,328 ) (462,516 ) Net Deferred Tax Liability $ (44,373 ) $ (105,096 ) Deferred taxes are recorded for certain tax benefits, including net operating losses and tax credit carry-forwards, provided that management assesses the utilization of those assets to be more likely than not. A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 2017 and 2016 , positive evidence considered included financial earnings generated over the past three years for certain subsidiaries, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods, the inability to achieve forecasted results for those periods and the impact of expected future financial results from normal operations on the utilization of tax credits. CNX continues to report, on an after federal tax basis, a deferred tax asset related to state operating losses of $107,756 with a related valuation allowance of $61,560 at December 31, 2017 . The deferred tax asset related to state operating losses, on an after tax adjusted basis, was $74,310 with a related valuation allowance of $60,488 at December 31, 2016 . A review of positive and negative evidence regarding these state tax benefits concluded that the valuation allowances for various CNX subsidiaries was warranted. These net operating losses expire at various times between 2018 and 2037. A valuation allowance on foreign tax credits of $44,402 and $39,850 has also been recorded at December 31, 2017 and 2016 , respectively. The foreign tax credits expire at various times between 2021 and 2023. A valuation allowance on deferred equity compensation for covered individuals as provided by Section 162(m) of $5,957 was recorded for 2017 . No such valuation allowance was recorded for 2016 . A valuation allowance on charitable contribution carry-forwards of $3,156 and $5,051 has been recorded for 2017 and 2016 , respectively. The Company's charitable contributions carry-forwards expire at various times between 2018 and 2022. As of December 31, 2017 , the Company has a deferred tax asset related to federal net operating losses of $99,524 , which expire at various times between 2034 and 2037. In connection with the restructuring and separation of the Company's coal business in November 2017, certain net operating loss carry-forwards were required to be written off under the Tax Cuts and Jobs Act (the "Act") passed on December 22, 2017. As a result, the Company has written off the deferred tax assets associated with these net operating losses, a reduction of $24,942 to the total deferred tax asset for net operating losses. The deferred tax assets attributable to the state tax effect of future deductible temporary differences for certain CNX subsidiaries with histories of financial and tax losses were also reviewed for positive and negative evidence regarding the realization of the associated deferred tax assets. A valuation allowance of $9,088 and $ 10,591 on an after federal tax adjusted basis has also been recorded for 2017 and 2016 , respectively. As of December 31, 2017 , the Company has a deferred tax asset relating to federal alternative minimum tax credits of $188,080 , a decrease of $31,792 from the prior year that resulted from the monetization of alternative minimum tax credits on the Company's 2016 Federal income tax return as well as estimated monetization anticipated for 2017 . During 2017 , the valuation allowance relating to federal alternative minimum tax credits decreased by $154,384 to $12,413 at December 31, 2017 . Under the Act, passed on December 22, 2017, the corporate alternative minimum tax was repealed. The Act also provided that existing alternative minimum tax credits are refundable beginning in 2018. As a result, it is now more likely than not that the benefit of CNX's alternative minimum tax credits will be realized. Accordingly, the previously recorded valuation allowance has been released. It should be noted that the Company does have a valuation allowance of $12,413 at December 31, 2017 reflecting the anticipated government sequestration of a portion of monetized alternative minimum tax credits. This amount represents 6.6% of the Company's total alternative minimum tax credits. Management will continue to assess the potential for realized deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, that could materially impact net income. The following is a reconciliation, stated as a percentage of pretax income, of the United States statutory federal income tax rate to CNX's effective tax rate: For the Years Ended December 31, 2017 2016 2015 Amount Percent Amount Percent Amount Percent Statutory U.S. federal income tax rate $ 41,503 35.0 % $ (204,872 ) 35.0 % $ (325,695 ) 35.0 % Uncertain tax positions 27,359 23.1 1,351 (0.2 ) — — Effect of spin on Federal NOL's 24,942 21.0 — — — — Accrual to tax return reconciliation (1,147 ) (1.0 ) (4,564 ) 0.8 (6,312 ) 0.7 IRS and state tax examination settlements — — (13,463 ) 2.3 (36 ) — Net effect of state income taxes 15,538 13.1 (20,954 ) 3.6 (15,400 ) 1.7 Effect of change in state valuation allowance (430 ) (0.4 ) 18,999 (3.2 ) 39,492 (4.2 ) Effect of change in federal valuation allowance (145,772 ) (122.9 ) 184,227 (31.5 ) 25,903 (2.8 ) Other deferred adjustments 7,616 6.4 — — — — Effect of federal rate reduction (131,784 ) (111.1 ) — — — — Effect of federal tax credits (19,081 ) (16.1 ) — — — — Other 4,798 4.0 4,873 (0.8 ) 1,689 (0.2 ) Income Tax Benefit / Effective Rate $ (176,458 ) (148.9 )% $ (34,403 ) 6.0 % $ (280,359 ) 30.2 % On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act which made significant changes that affect CNX. CNX believes that those changes will positively impact its future after-tax earnings, primarily due to the lower U.S. Federal tax rate and the repeal of the corporate alternative minimum tax. Beginning January 1, 2018, CNX will be taxed at a 21% federal corporate tax rate. The Company has reflected the impact of this rate on its deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the change in the period in which the law is enacted. The impact of this change was a net benefit of $115,291 in the income tax provision for the period ended December 31, 2017. The Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. As discussed above, CNX has credits that are expected to be refunded between 2018 and 2021 as a result of the Act and monetization opportunities under current law in 2017. The Company's effective tax rate reflects the release of previously recorded valuation allowances against alternative minimum tax credit carry-forwards of $154,385 , including other immaterial changes to valuation, as those credits will now be able to be monetized, net of anticipated sequestration, under the Act. The Act is a comprehensive tax reform bill containing a number of other provisions that either currently or in the future could impact CNX. The effect of certain limitations effective for the tax year 2018 and forward, specifically related to the deductibility of executive compensation, have been evaluated. The net benefits for the Act as recorded as provisional amounts as of December 31, 2017 , represent the Company's best estimate using information available to the Company as of February 7, 2018. The Company anticipates U.S. regulatory agencies will issue further regulations over the next year which may alter this estimate. The Company is still evaluating, among other things, the application of limitations for executive compensation related to contracts existing prior to November 2, 2017, and provisions in the Act addressing the deductibility of interest expense after January 1, 2018. The Company will refine its estimates to incorporate new or better information as it comes available through the filing date of its 2017 U.S. income tax returns in the fourth quarter of 2018. A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows: For the Years Ended December 31, 2017 2016 Balance at beginning of period $ 9,103 $ 12,702 Increase in unrecognized tax benefits resulting from tax positions taken during current period 21,902 666 Increase in unrecognized tax benefits resulting from tax positions taken during prior periods 7,474 — Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations (666 ) — Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities — (4,265 ) Balance at end of period $ 37,813 $ 9,103 If these unrecognized tax benefits were recognized, $29,376 and $666 would affect CNX's effective income tax rate for 2017 and 2016 , respectively. CNX and its subsidiaries file income tax returns in the United States and returns within various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to United States federal, state, local or non-U.S. income tax examinations by tax authorities for the years before 2016. In 2017 , CNX recognized an increase in unrecognized tax benefits of $28,710 for tax benefits resulting from a tax position taken on our federal tax return for the Marginal Well Credit and Consideration of Interest on Depletion in 2016 and plan to take on our 2017 return. CNX recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of December 31, 2017 and 2016 , the Company had an accrued liability of $644 and $306 , respectively, for interest related to uncertain tax positions. Interest expense of $337 and $253 was recorded in the Company's Consolidated Statements of Income for the years ended December 31, 2017 and 2016 , respectively. During the years ended December 31, 2017 and 2016 , CNX paid no interest related to income tax deficiencies. CNX recognizes penalties accrued related to uncertain tax positions in its income tax expense. As of December 31, 2017 and 2016 , CNX had no accrued liabilities for tax penalties.

Stock Repurchase (Notes)

Stock Repurchase (Notes)	12 Months Ended
	Dec. 31, 2017
Stock Repurchase [Abstract]
Repurchase Agreements, Valuation, Policy [Policy Text Block]	NOTE 4— STOCK REPURCHASE: In September 2017, CNX's Board of Directors approved a one-year stock repurchase program of up to $ 200,000 that terminated on November 1, 2017. On October 30, 2017, the Board approved an increase to the aggregate amount of the repurchase plan to $ 450,000 . The repurchases may be effected from time-to-time through open market purchases, privately negotiated transactions, Rule 10b5-1 plans, accelerated stock repurchases, block trades, derivative contracts or otherwise in compliance with Rule 10b-18. The timing of any repurchases will be based on a number of factors, including available liquidity, the Company's stock price, the Company's financial outlook, and alternative investment options. The share repurchase program does not obligate the Company to repurchase any dollar amount or number of shares and the Board may modify, suspend, or discontinue its authorization of the program at any time. The Board of Directors will continue to evaluate the size of the stock repurchase program based on CNX's free cash flow position, leverage ratio, and capital plans. During the year ended December 31, 2017 , 6,410,900 shares were repurchased and retired at an average price of $ 16.08 per share for a total cost of $103,209 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT: December 31, Property, Plant and Equipment 2017 2016 Intangible drilling cost $ 3,849,689 $ 3,583,599 Proved gas properties 1,999,891 2,016,916 Gas gathering equipment 1,182,234 1,138,299 Unproved gas properties 919,733 1,116,282 Gas wells and related equipment 834,120 800,617 Surface land and other equipment 309,602 323,908 Other gas assets 221,226 204,338 Total Property, Plant and Equipment $ 9,316,495 $ 9,183,959 Less: Accumulated Depreciation, Depletion and Amortization 3,526,742 3,214,984 Total Property, Plant and Equipment - Net $ 5,789,753 $ 5,968,975 The following assets would be amortized using the units-of-production method. Amounts reflect properties where drilling operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 2017 and 2016 , respectively. December 31, 2017 2016 Unproved gas properties $ 919,733 $ 1,116,282 Gas Advance Royalties 13,220 13,762 Total $ 932,953 $ 1,130,044 As of December 31, 2017 and 2016 , plant and equipment includes gross assets under capital lease of $ 73,688 and $ 73,892 , respectively. Included in Gas gathering equipment is a capital lease for the Jewell Ridge Pipeline of $ 66,919 at December 31, 2017 and 2016 . CNX also maintains a capital lease for vehicles of $ 6,769 and $ 6,973 at December 31, 2017 and 2016 , respectively, which is included in Other gas assets. Accumulated amortization for capital leases was $ 54,431 and $ 48,814 at December 31, 2017 and 2016 , respectively. Amortization expense for capital leases is included in Depreciation, Depletion and Amortization in the Consolidated Statements of Income. See Note 11–Leases for further discussion of capital leases. Industry Participation Agreements CNX had two significant industry participation agreements (referred to as "joint ventures" or "JVs") that provided drilling and completion carries for the Company's retained interests. CNX is party to a joint development agreement with Hess Ohio Developments, LLC (Hess) with respect to approximately 125 thousand net Utica Shale acres in Ohio in which each party has a 50% undivided interest. Under the agreement, as amended, Hess was obligated to pay a total of approximately $335,000 in the form of a 50% drilling carry of certain CNX working interest obligations as the acreage is developed. As of December 31, 2016, Hess' entire carry obligation has been met. CNX was party to a joint development agreement with Noble Energy, Inc. (Noble) with respect to approximately 700 thousand net Marcellus Shale oil and gas acres in West Virginia and Pennsylvania, in which each party owned a 50% undivided interest. In October 2016, CNX entered into an Exchange Agreement with Noble Energy, which terminated the joint development agreement related to the jointly owned gas assets held in connection with the joint venture with Noble and divided such jointly owned gas assets among CNX and Noble Energy. The transactions contemplated by the Exchange Agreement were closed on December 1, 2016 with an effective date of October 1, 2016. As part of the exchange: each party now owns and operates a 100% interest in properties and wells in two separate operating areas; each party has independent control and flexibility with respect to the scope and timing of future development over its operating area; and all acreage operated by CNX and Noble Energy, Inc. in their respective operating areas will remain fully dedicated to CNX Midstream Partners LP (see Note 20 - Related Party). The exchange was accounted for as a mineral conveyance, thus no gain or loss was recorded in connection with the transaction. In June 2017, Noble Energy announced that it has closed on a transaction divesting its upstream assets in northern West Virginia and southern Pennsylvania to HG Energy II Appalachia, LLC, a portfolio company of Quantum Energy Partners.

Short-Term Notes Payable

Short-Term Notes Payable	12 Months Ended
	Dec. 31, 2017
Short-term Debt [Abstract]
Short-Term Notes Payable:	SHORT-TERM NOTES PAYABLE: CNX's senior secured credit agreement expires on June 18, 2019. In November 2017, the facility was amended to allow for the spin-off of the Company's coal business (See Note 2 - Discontinued Operations). At that time, the lenders' commitments to the facility were reduced from $ 2,000,000 to $ 1,500,000 , and the borrowing base remained unchanged at $ 2,000,000 , including a $ 650,000 letters of credit aggregate sub-limit. CNX can also request an additional $ 500,000 increase in the aggregate borrowing limit amount. The facility is secured by substantially all of the assets of CNX Resources Corporation and certain of its subsidiaries. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Availability under the facility is limited to a borrowing base, which is determined by the lenders syndication agent and approved by the required number of lenders in good faith by calculating a value of CNX's proved natural gas reserves. The facility contains a number of affirmative and negative covenants that limit the Company's ability to dispose of assets, make investments, purchase or redeem CNX common stock, pay dividends, merge with another corporation and amend, modify or restate the senior unsecured notes. The April 2016 facility amendment requires that the Company must: (i) prepay outstanding loans under the revolving credit facility to the extent that cash on hand exceeds $150,000 for two consecutive business days; (ii) mortgage 85% of its proved reserves and 80% of its proved developed producing reserves, in each case, which are included in the borrowing base; (iii) maintain applicable deposit, securities and commodities accounts with the lenders or affiliates thereof; and (iv) enter into control agreements with respect to such applicable accounts. In addition, the Company pledged the equity interest it holds in CNX Gathering, LLC and CNX Midstream Partners, LP as collateral to secure loans under the credit agreement. Further, the credit facility allows unlimited investments in joint ventures for the development and operation of natural gas gathering systems. The facility also requires that CNX maintains a minimum interest coverage ratio of no less than 2.50 to 1.00, which is calculated as the ratio of Adjusted EBITDA to cash interest expense of CNX and certain of its subsidiaries, measured quarterly. CNX must also maintain a minimum current ratio of no less than 1.00 to 1.00, which is calculated as the ratio of current assets, plus revolver availability, to current liabilities, excluding borrowings under the revolver, measured quarterly. At December 31, 2017 , the interest coverage ratio was 4.01 to 1.00 and the current ratio was 4.78 to 1.00. At December 31, 2017 , the $1,500,000 facility had no borrowings outstanding and $ 239,072 of letters of credit outstanding, leaving $ 1,260,928 of unused capacity. At December 31, 2016 , the $2,000,000 facility had no borrowings outstanding and $325,676 of letters of credit outstanding, leaving $1,674,324 of unused capacity.

Other Accrued Liabilities

Other Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
Other Liabilities Disclosure [Abstract]
Accounts Payable and Accrued Liabilities Disclosure [Text Block]	NOTE 9—OTHER ACCRUED LIABILITIES: December 31, 2017 2016 Royalties $ 60,008 $ 42,425 Gas derivatives 41,291 231,573 Accrued interest 32,172 35,127 Transportation charges 13,004 9,856 Short-term incentive compensation 12,062 13,424 Deferred revenue 11,559 7,691 Accrued other taxes 9,779 9,261 Accrued payroll & benefits 6,615 7,322 Other 30,083 26,155 Current portion of long-term liabilities: Asset retirement obligations 5,302 5,302 Salary retirement 1,532 1,505 Total Other Accrued Liabilities $ 223,407 $ 389,641

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Long-term Debt	LONG-TERM DEBT: December 31, 2017 2016 Debt: Senior Notes due April 2022 at 5.875% (Principal of $1,705,682 and $1,850,000 plus Unamortized Premium of $3,544 and $4,731, respectively) $ 1,709,226 $ 1,854,731 Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,751 and $5,656, respectively) 495,249 494,344 Senior Notes due April 2020 at 8.25%, Issued at Par Value — 74,470 Senior Notes due March 2021 at 6.375%, Issued at Par Value — 20,611 Other Note Maturing in 2018 (Principal of $358 and $1,789 less Unamortized Discount of $8 and $117, respectively) 350 1,672 Less: Unamortized Debt Issuance Costs 17,536 23,356 2,187,289 2,422,472 Less: Amounts Due in One Year* 263 1,304 Long-Term Debt $ 2,187,026 $ 2,421,168 *Excludes current portion of Capital Lease Obligations of $6,848 and $6,620 at December 31, 2017 and 2016 , respectively. Annual undiscounted maturities on long-term debt during the next five years and thereafter are as follows: Year ended December 31, Amount 2018 $ 358 2019 — 2020 — 2021 — 2022 1,705,682 Thereafter 500,000 Total Long-Term Debt Maturities $ 2,206,040

Leases

Leases	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Leases of Lessee Disclosure [Text Block]	NOTE 11—LEASES: CNX uses various leased facilities and equipment in its operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2017 are as follows: Capital Operating Leases Leases Year Ended December 31, 2018 $ 8,562 $ 7,497 2019 8,362 6,334 2020 7,539 5,565 2021 6,706 5,438 2022 — 5,378 Thereafter — 41,433 Total minimum lease payments $ 31,169 $ 71,645 Less amount representing interest (3.00% – 7.36%) 3,974 Present value of minimum lease payments 27,195 Less amount due in one year 6,848 Total long-term capital lease obligation $ 20,347 Rental expense under operating leases was $16,797 , $20,772 , and $26,360 for the years ended December 31, 2017 , 2016 and 2015 , respectively.

Pension and OPEB

Pension and OPEB	12 Months Ended
	Dec. 31, 2017
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Components of Pension and Other Postretirement Benefit Plans:	NOTE 12—PENSION: CNX has a non-contributory defined benefit retirement plan. According to the Defined Benefit Plans Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification, if the lump sum distributions made during a plan year, which for CNX is January 1 to December 31, exceed the total of the projected service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments exceeded this threshold during the year ended December 31, 2015 . Accordingly, CNX recognized settlement expense of $3,132 for the year ended December 31, 2015 in Other Expense in the Consolidated Statements of Income. Lump sum payments did not exceed this threshold during the years ended December 31, 2017 or 2016 . The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows: December 31, 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 34,051 $ 33,196 Service cost 375 367 Interest cost 1,201 1,250 Actuarial loss 2,127 651 Benefits and other payments (1,474 ) (1,413 ) Benefit obligation at end of period $ 36,280 $ 34,051 Change in plan assets: Fair value of plan assets at beginning of period $ — $ — Company contributions 1,474 1,413 Benefits and other payments (1,474 ) (1,413 ) Fair value of plan assets at end of period $ — $ — Funded status: Current liabilities $ (1,532 ) $ (1,505 ) Noncurrent liabilities (34,748 ) (32,546 ) Net obligation recognized $ (36,280 ) $ (34,051 ) Amounts recognized in accumulated other comprehensive loss consist of: Net actuarial loss $ 14,374 $ 13,772 Prior service credit (626 ) (988 ) Net amount recognized (before tax effect) $ 13,748 $ 12,784 The components of the net periodic benefit cost are as follows: For the Years Ended December 31, 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 375 $ 367 $ 475 Interest cost 1,201 1,250 1,526 Amortization of prior service credits (362 ) (362 ) (362 ) Recognized net actuarial loss 1,525 1,505 2,252 Settlement loss — — 3,132 Net periodic benefit cost $ 2,739 $ 2,760 $ 7,023 Amounts included in accumulated other comprehensive loss which are expected to be recognized in 2018 net periodic benefit cost: Pension Benefits Prior service credit recognition $ (362 ) Actuarial loss recognition $ 1,492 CNX utilizes a corridor approach to amortize actuarial gains and losses that have been accumulated under the pension plan. Cumulative gains and losses that are in excess of 10% of the greater of either the projected benefit obligation (PBO) or the market-related value of plan assets are amortized over the expected remaining future lifetime of all plan participants for the pension plan. The following table provides information related to the pension plan with an accumulated benefit obligation in excess of plan assets: As of December 31, 2017 2016 Projected benefit obligation $ 36,280 $ 34,051 Accumulated benefit obligation $ 35,264 $ 32,838 Fair value of plan assets $ — $ — Assumptions: The weighted-average assumptions used to determine benefit obligations are as follows: For the Year Ended As of December 31, 2017 2016 Discount rate 3.70 % 4.26 % Rate of compensation increase 4.05 % 3.90 % The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans. The weighted-average assumptions used to determine net periodic benefit cost are as follows: For the Years ended December 31, 2017 2016 2015 Discount rate 4.26 % 4.55 % 4.07 % Rate of compensation increase 3.90 % 3.80 % 3.80 % Cash Flows: CNX expects to pay benefits of $1,532 from the non-qualified pension plan in 2018. The following benefit payments, which reflect expected future service, are expected to be paid: Pension Year ended December 31, Benefits 2018 $ 1,532 2019 $ 1,596 2020 $ 1,679 2021 $ 1,757 2022 $ 1,842 Year 2023-2027 $ 10,456

Stock Based Compensation

Stock Based Compensation	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	STOCK-BASED COMPENSATION: CNX adopted the Equity Incentive Plan (the Equity Incentive Plan) on April 7, 1999. The Equity Incentive Plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the Equity Incentive Plan have been adopted and approved by the Board of Directors and the Company's Shareholders since the commencement of the Equity Incentive Plan. Most recently, in May 2016, the Company's Shareholders adopted and approved a 10,550,000 increase to the total number of shares available for issuance, which brought the total number of shares of common stock that can be covered by grants, after adjustment, in accordance with the terms of the Equity Incentive Plan, for the separation of the coal business from the gas business on November 28, 2017, to 48,915,944 . At December 31, 2017 , 7,411,143 shares of common stock remained available for grant under the plan. The Equity Incentive Plan provides that the aggregate number of shares available for issuance will be reduced by one share for each share relating to stock options and by 1.62 for each share relating to Performance Share Units (PSUs) or Restricted Stock Units (RSUs). No award of stock options may be exercised under the Equity Incentive Plan after the tenth anniversary of the grant date of the award. For those shares expected to vest, CNX recognizes stock-based compensation costs on a straight-line basis over the requisite service period of the award, which is generally the vesting term. Options and RSUs vest over a three-year term. PSUs granted in 2015 vest over a three-year term while PSUs granted in 2016 and 2017 vest over a five-year term at 20% per year subject to performance conditions. If an employee leaves the Company, all unvested shares are forfeited. The vesting of all awards will accelerate in the event of death and disability and may accelerate upon a change in control of CNX. The total stock-based compensation expense recognized during the years ended December 31, 2017 , 2016 and 2015 was $ 16,983 , $ 19,316 and $ 14,314 , respectively. The related deferred tax benefit totaled $ 6,114 , $ 7,272 and $ 5,210 , for the years ended December 31, 2017 , 2016 and 2015 , respectively. As of December 31, 2017 , CNX has $ 28,712 of unrecognized compensation cost related to all nonvested stock-based compensation awards, which is expected to be recognized over a weighted-average period of 2.75 years. When stock options are exercised and restricted and performance stock unit awards become vested, the issuances are made from CNX's common stock shares. Pursuant to the terms of the CNX Equity Plan and the outstanding awards, in the event of certain changes in the outstanding common stock of CNX or its capital structure, including by reason of a spin-off, the administrator of the CNX Equity Plan is required to appropriately adjust the number, exercise price, kind of shares, performance goals or other terms and conditions of Awards granted thereunder. In connection with the Separation, the Board of Directors of CNX has determined that it is appropriate that the outstanding awards be equitably adjusted pursuant to the terms of the CNX Equity Plan and/or converted into awards issued under the CONSOL Energy Inc. (CEIX) Equity Incentive Plan, such that the intrinsic value of the outstanding awards immediately following the separation remains the same as the intrinsic value of such awards immediately prior to the separation. It was agreed upon that a simple average of the volume weighted average price (VWAP) per share for each of the three trading days prior to the distribution of CONSOL Energy, Inc will be divided by the simple average of the VWAP for each of the 3 trading days subsequent to the distribution date of CNX or CEIX will be used to ensure intrinsic value was preserved for conversion of CONSOL Energy units to CNX or CEIX units. Each type of award is summarized below: • CONSOL Energy's stock options held by both CNX and CEIX employees and former employees were adjusted to provide holders 1.15504 options to purchase CNX common stock for every option of CONSOL Energy stock held. • CONSOL Energy's restricted stock and performance share units awarded to CNX employees under the Performance Share Program were adjusted to provide holders 1.15504 restricted shares or performance share units of CNX stock for every one restricted share or performance share unit of CONSOL Energy stock. • CONSOL Energy's restricted stock and performance share units awarded to CEIX employees were adjusted to provide holders .71890 restricted shares or performance share units of CEIX stock for every one restricted share or performance share unit of CONSOL Energy stock. The separation resulted in a modification of the equity plans but did not have a material impact on the financial statements as of December 31, 2017 . In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update on stock compensation that was intended to simplify and improve the accounting and statement of cash flow presentation for income taxes at settlement, forfeitures, and net settlements for withholding tax. The guidance is effective for public entities for fiscal years beginning after December 15, 2016. In accordance with this Update, $4,867 of additional income tax expense was recognized in the Consolidated Statements of Income for the year ended December 31, 2017 . Also in accordance with this Update, the value of shares withheld for employee tax withholding purposes of $6,681 and $1,649 for the years ended December 31, 2017 and 2016 were reclassified between Net Cash Provided by Operating Activities and Net Cash Used in Financing Activities of the Consolidated Statements of Cash Flows. As permitted by this Update, the Company has elected to account for forfeitures of stock compensation as they occur. The cumulative effect of the policy election to recognize forfeitures as they occur was nominal. Stock Options: CNX examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CNX identified two distinct employee populations and used the Black-Scholes option pricing model to value the options for each of the employee populations. The expected term computation presented in the table below is based upon a weighted average of the historical exercise patterns and post-vesting termination behavior of the two populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. The total fair value of options granted during the years ended December 31, 2017 and 2016 was $353 and $19,305 , respectively, based on the following assumptions and weighted average fair values: December 31, December 31, 2017 2016 Weighted average fair value of grants $ 6.19 $ 5.73 Risk-free interest rate 1.66 % 1.13 % Expected dividend yield — % 0.27 % Expected forfeiture rate — % 2.00 % Expected volatility 50.85 % 61.09 % Expected term in years 3.71 4.90 CNX did not grant stock option awards during the year ended December 31, 2015 . A summary of the status of stock options granted is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands) Balance at December 31, 2016 6,208,813 $43.12 Granted 56,947 $15.69 Exercised (126,221 ) $7.94 Forfeited/Expired (778,413 ) $30.77 Awards granted in conversion, as a result of the separation 831,189 $21.50 Balance at December 31, 2017 6,192,315 $21.51 5.60 $ — Vested 4,332,383 $27.81 4.42 $ — Exercisable at December 31, 2017 4,187,408 $28.38 4.33 $ — At December 31, 2017 , there are 5,756,074 employee stock options outstanding under the Equity Incentive Plan. Non-employee director stock options vest one year after the grant date. There are 436,241 stock options outstanding under these grants. The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX's closing stock price on the last trading day of the year ended December 31, 2017 and the option's exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2017 . This amount varies based on the fair market value of CNX's stock.The total intrinsic value of options exercised for the years ended December 31, 2017 , 2016 and 2015 was $1,067 , $ 0 and $ 2,744 , respectively. Cash received from option exercises for the years ended December 31, 2017 , 2016 and 2015 was $1,002 , $ 0 , and $ 8,281 , respectively. The tax impact from option exercises totaled $205 , $ 0 , and $ 208 for the years ended December 31, 2017 , 2016 and 2015 , respectively. Restricted Stock Units: Under the Equity Incentive Plan, CNX grants certain employees and non-employee directors RSU awards, which entitle the holder to receive shares of common stock as the award vests. Non-employee director RSUs vest at the end of one year. Compensation expense is recognized over the vesting period of the units, described above. The total fair value of RSUs granted during the years ended December 31, 2017 , 2016 and 2015 was $ 14,328 , $ 493 and $ 26,550 , respectively. The total fair value of restricted stock units vested during the years ended December 31, 2017 , 2016 and 2015 was $ 12,805 , $ 19,095 and $ 20,793 , respectively. The following table represents the nonvested restricted stock units and their corresponding fair value (based upon the closing share price) at the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2016 663,003 $31.97 Granted 863,483 $16.59 Vested (408,117 ) $31.38 Forfeited (54,823 ) $20.67 RSUs surrendered as a result of the separation (253,959 ) $21.14 RSUs granted in conversion, as a result of the separation 127,875 $16.02 Nonvested at December 31, 2017 937,462 $16.01 Performance Share Units: Under the Equity Incentive Plan, CNX grants certain employees performance share unit awards, which entitle the holder to shares of common stock subject to the achievement of certain market and performance goals. Compensation expense is recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. The total fair value of performance share units granted during the years ended December 31, 2017 , 2016 and 2015 was $ 9,789 , $ 24,283 and $ 18,771 , respectively. The total fair value of performance share units vested during the years ended December 31, 2017 , 2016 and 2015 was $17,646 , $ 0 and $ 20,083 , respectively. The following table represents the nonvested performance share units and their corresponding fair value (based upon the closing share price) on the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2016 1,424,551 $26.41 Granted 447,691 $21.87 PSUs issued as a result of 200% payout 187,062 $25.80 Vested (560,960 ) $31.46 Forfeited (16,124 ) $20.65 PSUs surrendered as a result of the separation (379,893 ) $24.04 PSUs granted in conversion, as a result of the separation 170,715 $25.53 Nonvested at December 31, 2017 1,273,042 $25.53 Performance Options: Under the Equity Incentive Plan in 2010, CNX granted certain employees performance options, which entitled the holder to shares of common stock subject to the achievement of certain performance goals. Compensation expense was recognized over the vesting period of the options. The Black-Scholes option valuation model was used to value each tranche separately. No performance options were granted in 2017, 2016, or 2015. A summary of the status of performance options is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands) Balance at December 31, 2016 802,804 $45.05 Granted — — Exercised — — Forfeited/Expired — — Options granted in conversion, as a result of the separation 124,464 0.04 $39.00 Balance at December 31, 2017 927,268 $39.00 2.42 $ — Vested 927,268 $39.00 2.42 $ — Exercisable at December 31, 2017 927,268 $39.00 2.42 $ —

Supplemental Cash Flow

Supplemental Cash Flow	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash Flow, Supplemental Disclosures [Text Block]	NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION: The following are non-cash transactions that impact the investing and financing activities of CNX. For non-cash transactions that relate to the separation, as well as, acquisitions and dispositions, see Note 2 - Discontinued Operations and Note - 3 Acquisitions and Dispositions. CNX obtains capital lease arrangements for company-used vehicles. For the years ended December 31, 2017 , 2016 amounts were nominal and for the year ended December 31, 2015 , CNX entered into non-cash capital lease arrangements of $ 4,241 . As of December 31, 2017 , 2016 and 2015 , CNX purchased goods and services related to capital projects in the amount of $ 2,379 , $ 5,501 and $25,827 , respectively, which are included in accounts payable. The following table shows cash paid (received) during the year for: For the Years Ended December 31, 2017 2016 2015 Interest (net of amounts capitalized) $ 152,047 $ 186,924 $ 207,094 Income taxes $ (121,773 ) $ (18,032 ) $ (59,584 )

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Dec. 31, 2017
CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS: [Abstract]
Concentration Risk Disclosure [Text Block]	NOTE 15—CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS: CNX markets natural gas primarily to gas wholesalers in the United States. Concentration of credit risk is summarized below: December 31, 2017 2016 Gas Wholesalers $ 126,387 $ 95,826 NGL, Condensate & Processing Facilities 29,841 27,468 Other 589 1,220 Total Accounts Receivable Trade $ 156,817 $ 124,514 During the year ended December 31, 2017 sales to Direct Energy Business Marketing LLC were $153,565 and sales to NJR Energy Services Company were $147,595 , each of which comprises over 10% of sales. During the year ended December 31, 2016 , sales to NJR Energy Services Company were $106,280 , which comprised over 10% of the Company's revenues. During the year ended December 31, 2015 , sales to NJR Energy Services Company were $131,299 , which comprised over 10% of the Company's revenues.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS: CNX determines the fair value of assets and liabilities based on the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants. The fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. The fair value hierarchy is based on whether the inputs to valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources (including NYMEX forward curves, LIBOR-based discount rates and basis forward curves), while unobservable inputs reflect the Company's own assumptions of what market participants would use. The fair value hierarchy includes three levels of inputs that may be used to measure fair value as described below: Level One - Quoted prices for identical instruments in active markets. Level Two - The fair value of the assets and liabilities included in Level 2 are based on standard industry income approach models that use significant observable inputs, including NYMEX forward curves, LIBOR-based discount rates and basis forward curves. Level Three - Unobservable inputs significant to the fair value measurement supported by little or no market activity. In those cases when the inputs used to measure fair value meet the definition of more than one level of the fair value hierarchy, the lowest level input that is significant to the fair value measurement in its totality determines the applicable level in the fair value hierarchy. The financial instrument measured at fair value on a recurring basis is summarized below: Fair Value Measurements at Fair Value Measurements at Description Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Gas Derivatives $ — $ 59,949 $ — $ — $ (188,156 ) $ — Put Option $ — $ (3,500 ) $ — $ — $ — $ —

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVE INSTRUMENTS: CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. These natural gas and NGL commodity hedges are accounted for on a mark-to-market basis with changes in fair value recorded in current period earnings. CNX is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties. None of the Company's counterparty master agreements currently require CNX to post collateral for any of its positions. However, as stated in the counterparty master agreements, if the Company's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would have to post collateral for instruments in a liability position in excess of defined thresholds. All of the Company's derivative instruments are subject to master netting arrangements with its counterparties. CNX recognizes all financial derivative instruments as either assets or liabilities at fair value on the Consolidated Balance Sheets on a gross basis. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions. The total notional amounts of production of the Company's derivative instruments at December 31, 2017 and December 31, 2016 were as follows: December 31, Forecasted to 2017 2016 Settle Through Natural Gas Commodity Swaps (Bcf) 1,067.2 744.7 2022 Natural Gas Basis Swaps (Bcf) 688.1 482.0 2022 Propane Commodity Swaps (Mbbls) — 126.0 — The gross fair value of the Company's derivative instruments at December 31, 2017 and December 31, 2016 were as follows: Asset Derivative Instruments Liability Derivative Instruments December 31, December 31, 2017 2016 2017 2016 Commodity Swaps: Prepaid Expense $ 62,369 $ 16 Other Accrued Liabilities $ 5,985 $ 209,980 Other Assets 59,281 29,596 Other Liabilities 42,419 67,139 Total Asset $ 121,650 $ 29,612 Total Liability $ 48,404 $ 277,119 Basis Only Swaps: Prepaid Expense $ 14,965 $ 56,916 Other Accrued Liabilities $ 35,306 $ 21,593 Other Assets 24,223 35,603 Other Liabilities 17,179 11,575 Total Asset $ 39,188 $ 92,519 Total Liability $ 52,485 $ 33,168 The effect of derivative instruments on the Company's Consolidated Statements of Income was as follows: For the Years Ended December 31, 2017 2016 2015 Cash (Paid) Received in Settlement of Commodity Derivative Instruments: Commodity Swaps: Natural Gas $ (34,928 ) $ 225,797 $ 193,976 Propane (1,216 ) (650 ) — Natural Gas Basis Swaps (5,030 ) 20,065 2,372 Total Cash (Paid) Received in Settlement of Commodity Derivative Instruments (41,174 ) 245,212 196,348 Unrealized Gain (Loss) on Commodity Derivative Instruments: Commodity Swaps: Natural Gas 319,605 (520,170 ) 81,142 Propane 1,147 (1,148 ) — Natural Gas Basis Swaps (72,648 ) 66,604 (7,653 ) Reclassified from Accumulated OCI — 68,481 123,105 Total Unrealized Gain (Loss) on Commodity Derivative Instruments 248,104 (386,233 ) 196,594 Gain (Loss) on Commodity Derivative Instruments: Commodity Swaps: Natural Gas $ 284,677 $ (294,373 ) $ 275,118 Propane (69 ) (1,798 ) — Natural Gas Basis Swaps (77,678 ) 86,669 (5,281 ) Reclassified from Accumulated OCI — 68,481 123,105 Total Gain (Loss) on Commodity Derivative Instruments $ 206,930 $ (141,021 ) $ 392,942 Changes in Accumulated OCI, net of tax, attributable to cash flow hedges that were de-designated December 31, 2014 were as follows: For the Years Ended December 31, 2016 2015 Beginning Balance – Accumulated OCI $ 43,470 $ 121,521 Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054) (43,470 ) (78,051 ) Ending Balance – Accumulated OCI $ — $ 43,470 The Company also enters into fixed price natural gas sales agreements that are satisfied by physical delivery. These physical commodity contracts qualify for the normal purchases and sales exception and are not subject to derivative instrument accounting.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	NOTE 18—COMMITMENTS AND CONTINGENT LIABILITIES: CNX and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. CNX accrues the estimated loss for these lawsuits and claims when the loss is probable and can be estimated. The Company's current estimated accruals related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CNX. It is possible that the aggregate loss in the future with respect to these lawsuits and claims could ultimately be material to the financial position, results of operations or cash flows of CNX; however, such amounts cannot be reasonably estimated. The amount claimed against CNX is disclosed below when an amount is expressly stated in the lawsuit or claim, which is not often the case. The following lawsuits and claims include those for which a loss is probable and an accrual has been recognized: Hale Litigation: This class action lawsuit was filed on September 23, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of force-pooled unleased gas owners whose ownership of the coalbed methane (CBM) gas was declared to be in conflict with rights of others. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on allegations CNX Gas Company failed to either pay royalties due to conflicting claimants or deemed lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order certifying four issues for class treatment: (1) allegedly excessive deductions; (2) royalties based on purported improperly low prices; (3) deduction of severance taxes; and (4) Plaintiffs' request for an accounting. On April 13, 2017, CNX filed a Petition for Allowance of Appeal with the Fourth Circuit, and on May 22, 2017 the Petition was denied. CNX and plaintiffs’ counsel have reached an agreement in principal to settle the certified class claims, subject to court approval. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CNX and is included in Other Accrued Liabilities on the Consolidated Balance Sheets. Addison Litigation: This class action lawsuit was filed on April 28, 2010 in the U.S. District Court in Abingdon, Virginia. The putative class consists of gas lessors whose gas ownership is in conflict. The lawsuit seeks a judicial declaration of ownership of the CBM and damages based on the allegations that CNX Gas Company failed to either pay royalties due to these conflicting claimant lessors or paid them less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. On September 30, 2013, the District Judge entered an Order certifying the class, and CNX Gas Company appealed the Order to the U.S. Fourth Circuit Court of Appeals. On August 19, 2014, the Fourth Circuit agreed with CNX Gas Company, reversed the Order certifying the class and remanded the case to the trial court for further proceedings consistent with the decision. On April 23, 2015, Plaintiffs filed a Renewed Motion for Class Certification, which CNX opposed. On March 29, 2017, the Court issued an Order denying class certification in this matter. CNX and plaintiff’s counsel have reached an agreement in principal to settle this lawsuit. The Company has established an accrual to cover its estimated liability for this case. This accrual is immaterial to the overall financial position of CNX and is included in Other Accrued Liabilities on the Consolidated Balance Sheets. At December 31, 2017 , CNX has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties as described by major category in the following table. These amounts represent the maximum potential of total future payments that the Company could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these unconditional purchase obligations and letters of credit are recorded as liabilities in the financial statements. CNX management believes that these commitments will expire without being funded, and therefore will not have a material adverse effect on financial condition. Amount of Commitment Expiration Per Period Total Amounts Committed Less Than 1 Year 1-3 Years 3-5 Years Beyond 5 Years Letters of Credit: Firm Transportation $ 239,052 $ 231,992 $ 7,060 $ — $ — Other 20 20 — — — Total Letters of Credit 239,072 232,012 7,060 — — Surety Bonds: Employee-Related 1,850 1,850 — — — Environmental 5,438 4,178 1,260 — — Other 12,485 10,823 1,662 — — Total Surety Bonds 19,773 16,851 2,922 — — Guarantees: CONSOL Energy 192,490 59,809 69,059 41,047 22,575 Total Guarantees 192,490 59,809 69,059 41,047 22,575 Total Commitments $ 451,335 $ 308,672 $ 79,041 $ 41,047 $ 22,575 Included in the above table are commitments and guarantees entered into in conjunction with the spin-off of the Company's coal business (See Note 2 - Discontinued Operations). Although CONSOL Energy agreed to indemnify us to the extent that we are called upon to pay any of these liabilities, there is no assurance that CONSOL Energy will satisfy its obligations to indemnify us in these situations. CNX enters into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2017 , the purchase obligations for each of the next five years and beyond were as follows: Obligations Due Amount Less than 1 year $ 181,303 1 - 3 years 264,773 3 - 5 years 237,625 More than 5 years 513,744 Total Purchase Obligations $ 1,197,445

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Reporting Disclosure [Text Block]	SEGMENT INFORMATION: The principal activity of CNX, which includes four reportable segments, is to produce pipeline quality natural gas for sale primarily to gas wholesalers. The Company's reportable segments are Marcellus Shale, Utica Shale, Coalbed Methane, and Other Gas. The Other Gas segment is primarily related to shallow oil and gas production which is not significant to the Company. It also includes the Company's purchased gas activities, unrealized gain or loss on commodity derivative instruments, exploration and production related other costs, impairment of exploration and production properties, as well as various other operating activities not allocated to each individual segment. The Company's unallocated expenses include selling, general and administrative activities, other expense, gain on sale of assets, loss on debt extinguishment, interest expense and income taxes. Prior to the spin-off of the coal company in November 2017 (See Note 2 - Discontinued Operations), CNX had a Coal division. The Coal division had three reportable segments; PA Operations, Virginia (VA) Operations and Other Coal. The VA Operations segment included the Buchanan Mine and the Other Coal segment was primarily comprised of the assets and operations of the Miller Creek and Fola Complexes, as well as coal terminal operations, closed and idle mine activities, selling, general and administrative activities and various other non-operated activities. In the preparation of the following information, intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Assets are reflected at the Total Operating level and are not allocated between each individual segment. These assets are not allocated to each individual segment due to the diverse asset base controlled by CNX, whereby each individual asset may service more than one segment. An allocation of such asset base would not be meaningful or representative on a segment by segment basis.
Reconciliation Of Assets And Liabilities From Segment To Consolidated [Text Block]	Reconciliation of Segment Information to Consolidated Amounts: Revenue and Other Operating Income: For the Years Ended December 31, 2017 2016 2015 Total Segment Sales from External Customers $ 1,179,019 $ 836,504 $ 741,371 Gain (Loss) on Commodity Derivative Instruments 206,930 (141,021 ) 392,942 Other Income 69,182 64,485 64,424 Total Consolidated Revenue and Other Operating Income $ 1,455,131 $ 759,968 $ 1,198,737 Earnings (Loss) From Continuing Operations Before Income Tax: For the Years Ended December 31, 2017 2016 2015 Segment Income (Loss) Before Income Taxes for Reportable Business Segments $ 191,126 $ (307,797 ) $ (584,337 ) Segment Loss Before Income Taxes for All Other Business Segments (97,036 ) (109,626 ) (140,496 ) Gain on Sale of Assets 188,063 14,270 61,148 Interest Expense (161,443 ) (182,195 ) (199,121 ) Loss on Debt Extinguishment (2,129 ) — (67,751 ) Earnings (Loss) From Continuing Operations Before Income Tax $ 118,581 $ (585,348 ) $ (930,557 ) Total Assets: December 31, 2017 2016 Segment Assets for Total Reportable Business Segments $ 6,122,746 $ 6,238,156 Segment Assets for All Other Business Segments 268,569 283,917 Items Excluded from Segment Assets: Cash and Other Investments 509,075 46,216 Recoverable Income Taxes 31,523 114,481 Discontinued Operations — 2,496,921 Total Consolidated Assets $ 6,931,913 $ 9,179,691

Related Party

Related Party	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	NOTE 20 — RELATED PARTY TRANSACTIONS CNX Gathering LLC and CNX Midstream Partners LP CNX Midstream Partners LP ("CNXM" or the "Partnership"), formerly known as CONE Midstream Partners LP (see Note 21 - Subsequent Event), is a master limited partnership formed in May 2014 by CNX Resources Corporation and Noble Energy, Inc., an unrelated third party, primarily to own, operate, develop and acquire natural gas gathering and other midstream energy assets to service their production in the Marcellus Shale in Pennsylvania and West Virginia. The Partnership's assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. The Partnership's general partner is CNX Midstream GP LLC, formerly known as CONE Midstream GP LLC, a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”), formerly known as CONE Gathering LLC. CNX Gathering, a Delaware limited liability company, is a joint venture formed by CNX and Noble Energy in September 2011. At December 31, 2017, CNX accounted for its ownership interests in each of the Partnership and CNX Gathering under the equity method of accounting. CNX Gathering is a variable interest entity for which the Company has the ability to exert significant influence, but not control, over the operating and financing policies of. The Partnership is a variable interest entity for which CNX Gathering, through it's ownership and control of the Partnership's general partner, has the power to direct the activities that most significantly impact the Partnership's economic performance. In addition, through its general partner interest and incentive distribution rights in the Partnership, CNX Gathering has the obligation to absorb the Partnership's losses and the right to receive benefits from the Partnership in accordance with those interests. Therefore, CNX Gathering has a controlling financial interest in the Partnership, is the primary beneficiary of the Partnership and consolidates it accordingly. Rule 3-09 of Regulation S-X provides that if a 50%-or-less-owned person accounted for by the equity method meets the first or third condition of the significant subsidiary tests set forth in Rule 1-02(w) of Regulation S-X, substituting 20% for 10%, separate financial statements for that 50%-or-less-owned person shall be filed. The significance tests are calculated as of the end of each of the Partnership's fiscal years with respect to each fiscal year. Pursuant to Rule 3-09 CNX Gathering LLC has met the significant subsidiary test as of December 31, 2017 and 2016, and for the three years ended December 31, 2017, and therefore the required financial statements are included as an exhibit to this Annual Report on Form 10-K. In November 2016, the Partnership acquired from CNX Gathering an additional 25% ownership interest in CNX Midstream DevCo I LP, formerly known as CONE Midstream Devco 1 LP, commonly referred to as the "Anchor Systems." The transaction included a total purchase consideration of $248,000 , comprised of $ 140,000 in cash and issuance of approximately 2,600,000 common limited partnership units to each of CNX and Noble Energy. Following the acquisition, CNX Gathering continues to have a 2 % general partner interest in the Partnership, while each Sponsor’s limited partner interest increased to 33.5% . At December 31, 2017 , CNX continues to own a 50% membership interest in CNX Gathering, which owns a 95% noncontrolling interest in CNX Midstream Devco II LP and CNX Midstream Devco III LP. In November 2017 the subordination period with respect to the Partnership’s subordinated units expired, and all of the 29,163,121 outstanding subordinated units, of which CNX owned half, automatically converted into common units on a one-for-one basis. The following is a summary of the Company's Investment in Affiliates balances included within the Consolidated Balance Sheets associated with CNX Gathering and the Partnership, respectively: CNX Gathering LLC CNX Midstream Partners LP Total Balance at December 31, 2015 $ 202,570 $ 11,047 $ 213,617 Equity in Earnings 17,112 31,148 48,260 Additional Contributions 4,621 — 4,621 Distribution of Earnings (8,224 ) (19,066 ) (27,290 ) Funds Received on Dropdown Transaction (70,000 ) — (70,000 ) Basis Differential 4,996 (4,996 ) — Balance at December 31, 2016 $ 151,075 $ 18,133 $ 169,208 Equity in Earnings 9,823 38,523 48,346 Distribution of Earnings (17,254 ) (24,929 ) (42,183 ) Asset Transfer (2,527 ) 2,527 — Balance at December 31, 2017 $ 141,117 $ 34,254 $ 175,371 The following transactions were included within Other Income and Transportation, Gathering and Compression within the Consolidated Statements of Income: For the Years Ended December 31, 2017 2016 2015 Other Income: Equity in Earnings of Affiliates - CNX Gathering $ 9,823 $ 17,112 $ 20,916 Equity in Earnings of Affiliates - CNX Midstream Partners LP $ 38,523 $ 31,148 $ 22,883 Transportation, Gathering and Compression: Gathering Services - CNX Gathering $ 914 $ 706 $ 1,077 Gathering Services - CNX Midstream Partners LP $ 136,068 $ 122,256 $ 104,291 At December 31, 2017 and 2016 , CNX had a net payable of $9,982 and $5,815 , respectively, due to both CNX Midstream Partners and CNX Gathering primarily for accrued but unpaid gathering services. CONSOL Energy Inc. In connection with the spin-off of its coal business, as discussed in Note 2 - Discontinued Operations, CNX and CONSOL Energy entered into several agreements that govern the relationship of the parties following the Distribution, including the following: • Separation and Distribution Agreement; • Transition Services Agreement; • Tax Matters Agreement; • Employee Matters Agreement; • Intellectual Property Matters Agreement; • CNX Resources Corporation to CONSOL Energy Inc. Trademark License Agreement; • CONSOL Energy Inc. to CNX Resources Corporation Trademark License Agreement; and • First Amendment to Amended and Restated Omnibus Agreement (“Omnibus Amendment”). There were also one-time transaction costs related to the spin-off of approximately $40,545 for the year ended December 31, 2017, that will be split equally by the two companies per the Separation and Distribution agreement. These costs consisted of consulting and professional fees associated with preparing for and executing the spin-off, as well as other items that were included within total costs of discontinued operations. As of December 31, 2017, CNX had a receivable from CONSOL Energy of $12,540 recorded in Total Current Assets on the Consolidated Balance Sheets. CNX also had recorded obligations to CONSOL Energy of $ 15,415 , of which $4,500 was recorded in Total Current Liabilities and $10,915 was included in Total Deferred Credits and Other Liabilities on the Consolidated Balance Sheets at December 31, 2017. These items relate to the reimbursement of the one-time transaction costs as well as other reimbursements per the terms of the separation and distribution agreement. All significant intercompany transactions between CNX and CONSOL Energy have been included in the Consolidated Financial Statements and are considered to have been effectively settled for cash at the time the transaction was recorded. The total net effect of these transactions between CNX and CONSOL Energy is reflected in the Consolidated Statements of Cash Flows as a financing activity. In the Consolidated Statements of Stockholders' Equity, the distribution of CONSOL Energy Inc. is the net of the variety of intercompany transactions including, but not limited too, collection of trade receivables, payment of trade payables and accrued liabilities, settlement of charges for allocated selling, general and administrative costs and payment of taxes by CNX on CONSOL Energy's behalf.

Supplemental Gas Data

Supplemental Gas Data	12 Months Ended
	Dec. 31, 2017
SUPPLEMENTAL GAS DATA: [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	Supplemental Gas Data (unaudited): The following information was prepared in accordance with the FASB's Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” Capitalized Costs: As of December 31, 2017 2016 Intangible drilling costs 3,849,689 3,583,599 Proved gas properties 1,999,891 2,016,916 Gas gathering assets 1,182,234 1,138,299 Unproved gas properties 919,733 1,116,282 Gas wells and related equipment 834,120 800,617 Gas well plugging 181,038 176,961 Total Property, Plant and Equipment $ 8,966,705 $ 8,832,674 Accumulated Depreciation, Depletion and Amortization (3,408,606 ) (3,099,751 ) Net Capitalized Costs $ 5,558,099 $ 5,732,923 Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2017 2016 2015 Property acquisitions Proved properties $ 15,850 $ — $ — Unproved properties 32,038 1,537 76,676 Development 544,809 138,813 666,315 Exploration 48,020 32,259 95,371 Total $ 640,717 $ 172,609 $ 838,362 __________ (*) Includes costs incurred whether capitalized or expensed. Results of Operations for Producing Activities: For the Years Ended December 31, 2017 2016 2015 Natural Gas, NGLs and Oil Sales $ 1,125,224 $ 793,248 $ 726,921 Gain (Loss) on Commodity Derivative Instruments 206,930 (141,021 ) 392,942 Purchased Gas Sales 53,795 43,256 14,450 Total Revenue 1,385,949 695,483 1,134,313 Lease Operating Expense 88,932 96,434 121,847 Production, Ad Valorem, and Other Fees 29,267 31,049 30,438 Transportation, Gathering and Compression 382,865 374,350 343,403 Purchased Gas Costs 52,597 42,717 10,721 Impairment of Exploration and Production Properties 137,865 — 828,905 Exploration Costs 48,074 14,522 10,119 DD&A 412,036 419,939 371,783 Total Costs 1,151,636 979,011 1,717,216 Pre-tax Operating Income / (Loss) 234,313 (283,528 ) (582,903 ) Income Tax Benefit (348,676 ) (69,929 ) (251,490 ) Results of Operations for Producing Activities excluding Corporate and Interest Costs $ 582,989 $ (213,599 ) $ (331,413 ) The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production: For the Years Ended December 31, 2017 2016 2015 Production (MMcfe) 407,166 394,387 328,657 Total average sales price before effects of financial settlements (per Mcfe) $ 2.76 $ 2.01 $ 2.22 Average effects of financial settlements (per Mcfe) $ (0.10 ) $ 0.62 $ 0.59 Total average sales price including effects of financial settlements (per Mcfe) $ 2.66 $ 2.63 $ 2.81 Average lifting costs, excluding ad valorem and severance taxes (per Mcfe) $ 0.22 $ 0.24 $ 0.37 During the years ended December 31, 2017 , 2016 and 2015 , the Company drilled 90.0 , 36.0 , and 132.8 net development wells, respectively. There were no net dry development wells in 2017 , 2016 , or 2015 . During the year ended December 31, 2017 , the Company drilled 4.0 net exploratory wells. During the years ended December 31, 2016 and 2015 , we drilled 0.0 and 2.5 net exploratory wells, respectively. There were no net dry exploratory wells in 2017 , 2016 , or 2015 . At December 31, 2017 , there were 3.9 net development wells and 1.8 exploratory wells that are drilled but uncompleted. Additionally there are 13.0 net developmental wells that have been completed and are awaiting final tie-in to production. CNX is committed to provide 712.3 Bcf of gas under existing sales contracts or agreements over the course of the next four years. The Company expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments. Most of the Company's development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2017 , the number of producing wells, developed acreage and undeveloped acreage: Gross Net(1) Producing Gas Wells (including gob wells) 17,013 12,853 Producing Oil Wells 171 12 Acreage Position: Proved Developed Acreage 551,900 543,937 Proved Undeveloped Acreage 41,066 40,703 Unproved Acreage 4,434,714 3,817,015 Total Acreage 5,027,680 4,401,655 ____________ (1) Net acres include acreage attributable to the Company's working interests of the properties. Additional adjustments (either increases or decreases) may be required as the Company further develops title to and further confirms its rights with respect to its various properties in anticipation of development. The Company believes that its assumptions and methodology in this regard are reasonable. Proved Oil and Gas Reserves Quantities: Annually, the preparation of natural gas reserves estimates are completed in accordance with CNX prescribed internal control procedures, which include verification of input data into a gas reserves forecasting and economic evaluation software, as well as multi-functional management review. The input data verification includes reviews of the price and cost assumptions used in the economic model to determine the reserves. Also, the production volumes are reconciled between the system used to calculate the reserves and other accounting/measurement systems. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer with over 10 years of experience in the oil and gas industry. The Company's 2017 gas reserves results, which are reported in the Supplemental Gas Data year ended December 31, 2017 Form 10-K, were audited by Netherland, Sewell & Associates, Inc. The technical person primarily responsible for overseeing the audit of the Company's reserves is a registered professional engineer in the state of Texas with over 15 years of experience in the oil and gas industry. The gas reserves estimates are as follows: Condensate Consolidated Natural Gas NGLs & Crude Oil Operations (MMcf) (Mbbls) (Mbbls) (MMcfe) Balance December 31, 2014 (a) 6,317,600 77,790 7,213 6,827,616 Revisions (b) 1,055,225 45,711 6,569 1,368,909 Price Changes (2,866,123 ) (45,675 ) (3,208 ) (3,159,421 ) Extensions and Discoveries (c) 840,800 13,916 1,707 934,542 Production (287,287 ) (5,530 ) (1,365 ) (328,657 ) Balance December 31, 2015 (a) 5,060,215 86,212 10,916 5,642,989 Revisions (d) 11,559 (19,078 ) 510 (99,849 ) Price Changes (179,914 ) (1,647 ) (34 ) (190,009 ) Extensions and Discoveries (e) 643,688 10,960 1,783 720,146 Production (348,753 ) (6,710 ) (896 ) (394,387 ) Purchases of Reserves In-Place (f) 1,352,759 13,177 1,970 1,443,642 Sales of Reserves In-Place (f) (711,155 ) (22,382 ) (4,240 ) (870,884 ) Balance December 31, 2016 (a) 5,828,399 60,532 10,009 6,251,648 Revisions (g) (202,735 ) 1,162 (5,834 ) (232,321 ) Price Changes 173,738 1,188 (159 ) 181,470 Extensions and Discoveries (e) 1,769,029 17,887 1,800 1,887,153 Production (364,893 ) (6,456 ) (589 ) (407,166 ) Sales of Reserves In-Place (81,780 ) (2,622 ) (277 ) (99,172 ) Balance December 31, 2017 (a) 7,121,758 71,691 4,950 7,581,612 Proved developed resources: December 31, 2015 3,310,894 59,196 5,180 3,697,152 December 31, 2016 3,478,464 30,666 3,474 3,683,302 December 31, 2017 4,051,526 56,022 3,567 4,409,065 Proved undeveloped resources: December 31, 2015 1,749,320 27,016 5,736 1,945,837 December 31, 2016 2,349,934 29,866 6,536 2,568,346 December 31, 2017 3,070,232 15,669 1,383 3,172,547 __________ (a) Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods. (b) The upward revisions in 2015 of 1,369 Bcfe were due to 611 Bcfe increase in both performance and operating cost reductions for developed properties, a 1,200 Bcfe increase for undeveloped properties due to operating cost reductions and expected increases in well performance. These upward revisions in 2015 were offset by a 442 Bcfe downward revision for undeveloped properties that were removed from our operational plans due to "high-grading" and selecting our highest rate of return properties for future development. (c) Extensions and Discoveries in 2015 are due mainly to the high grading of locations which resulted in the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology. (d) The net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties offset by 268 Bcfe of improved analog performance. (e) Extensions and Discoveries in 2016 and 2017 are due to the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology. (f) Purchases and Sales of Reserves In-Place in 2016 is the result of the Company's fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy. (g) The downward revisions for 2017 is due to corporate planning changes by our JV partner in Ohio Utica which resulted in all PUD's being removed, causing a 458 Bcfe downward revision, offset, in part by improved well performance due to the enhanced RCS completions and improved operating costs. For the Year Ended December 31, 2017 Proved Undeveloped Reserves (MMcfe) Beginning proved undeveloped reserves 2,568,346 Undeveloped reserves transferred to developed(a) (735,076 ) Price Revisions 5,066 Revisions Due to Plan Changes (b) (472,118 ) Revisions Due to Changes Due to Well Performance (b) 107,421 Extension and discoveries (c) 1,698,908 Ending proved undeveloped reserves(d) 3,172,547 _________ (a) During 2017 , various exploration and development drilling and evaluations were completed. Approximately, $ 247,459 of capital was spent in the year ended December 31, 2017 related to undeveloped reserves that were transferred to developed. (b) The downward revisions for 2017 is due to corporate planning changes by our JV partner in Ohio Utica which resulted in PUD's being removed. (c) Extensions and discoveries are due mainly to the addition of wells on our Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology. (d) Included in proved undeveloped reserves at December 31, 2017 are approximately 301,063 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine that was sold in March 2016 to Coronado IV LLC (See Note 2 - Discontinued Operations for more information) with the rights to this gas being retained by the Company. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance resulting from an external factor. These reasons constitute the specific circumstances that exist to continue recognizing these reserves for CNX. At December 31, 2017 there were no wells pending the determination of proved reserves. The following table represents the capitalized exploratory well cost activity as indicated: December 31, 2017 2016 2015 Costs reclassified to wells, equipment and facilities based on the determination of proved reserves $ 40,149 $ 40,917 $ 17,179 Costs expensed due to determination of dry hole or abandonment of project $ — $ — $ — CNX proved natural gas reserves are located in the United States.

Supplemental Quarterly Info (Un

Supplemental Quarterly Info (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information [Text Block]	Supplemental Quarterly Information (unaudited): (Dollars in thousands, except per share data) Three Months Ended March 31, June 30, September 30, December 31, 2017 2017 2017 2017 Sales (A) $ 304,278 $ 354,409 $ 267,009 $ 460,253 Costs and Expenses (B) $ 162,148 $ 166,330 $ 171,606 $ 214,020 (Loss) Income from Continuing Operations (C) $ (75,234 ) $ 122,384 $ (34,254 ) $ 282,143 Income (Loss) from Discontinued Operations $ 36,268 $ 47,126 $ 7,813 $ (5,499 ) Net (Loss) Income $ (38,966 ) $ 169,510 $ (26,441 ) $ 276,644 Earnings Per Share Basic: (Loss) Income from Continuing Operations $ (0.33 ) $ 0.53 $ (0.15 ) $ 1.24 Income (Loss) from Discontinued Operations $ 0.16 $ 0.21 $ 0.04 $ (0.04 ) Net (Loss) Income $ (0.17 ) $ 0.74 $ (0.11 ) $ 1.20 Dilutive: (Loss) Income from Continuing Operations $ (0.33 ) $ 0.53 $ (0.15 ) $ 1.23 Income (Loss) from Discontinued Operations $ 0.16 $ 0.20 $ 0.04 $ (0.03 ) Net (Loss) Income $ (0.17 ) $ 0.73 $ (0.11 ) $ 1.20 Three Months Ended March 31, June 30, September 30, December 31, 2016 2016 2016 2016 Sales (A) $ 244,935 $ (23,518 ) $ 416,192 $ 57,874 Costs and Expenses (B) $ 162,910 $ 153,971 $ 160,811 $ 170,134 (Loss) Income from Continuing Operations $ (50,219 ) $ (256,535 ) $ 56,264 $ (300,455 ) Loss from Discontinued Operations $ (47,353 ) $ (213,293 ) $ (30,919 ) $ (5,592 ) Net (Loss) Income $ (97,572 ) $ (469,828 ) $ 25,345 $ (306,047 ) Earnings Per Share Basic: (Loss) Income from Continuing Operations $ (0.22 ) $ (1.12 ) $ 0.25 $ (1.31 ) Loss from Discontinued Operations $ (0.21 ) $ (0.93 ) $ (0.14 ) $ (0.02 ) Net (Loss) Income $ (0.43 ) $ (2.05 ) $ 0.11 $ (1.33 ) Dilutive: (Loss) Income from Continuing Operations $ (0.22 ) $ (1.12 ) $ 0.24 $ (1.30 ) Loss from Discontinued Operations $ (0.21 ) $ (0.93 ) $ (0.13 ) $ (0.03 ) Net (Loss) Income $ (0.43 ) $ (2.05 ) $ 0.11 $ (1.33 ) (A) Includes natural gas, NGLs, and oil sales; gain (loss) on commodity derivative instruments; and purchased gas sales. (B) Includes exploration and production costs and other operating expense; excludes DD&A, selling, general and administrative, loss on debt extinguishment, interest expense and other expense. (C) Includes an impairment of $137,865 that was recorded during the three months ended March 31, 2017 related to CNX's exploration and production properties. See Note 1 - Significant Accounting Policies in Item 8 of this Form 10-K for additional information.

Subsequent Event (Notes)

Subsequent Event (Notes)	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events [Text Block]	SUBSEQUENT EVENTS On January 3rd, 2018 CNX Resources Corporation closed on an agreement to purchase Noble Energy, Inc.'s 50% membership interest in CONE Gathering LLC for $305,000 in

Significant Accounting Policy (

Significant Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Consolidation, Policy [Policy Text Block]	Basis of Consolidation: The Consolidated Financial Statements include the accounts of CNX Resources Corporation, and its wholly owned and majority-owned and/or controlled subsidiaries, including certain variable interest entities that the Company is required to consolidate pursuant to the Consolidation topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. The portion of these entities that is not owned by the Company is presented as non-controlling interest. Investments in business entities in which CNX does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate consolidation method.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the consolidated financial statements are related to salary retirement benefits, stock-based compensation, asset retirement obligations, deferred income tax assets and liabilities, contingencies and the values of natural gas, NGLs, condensate and oil (collectively "natural gas") reserves.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents: Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Trade Accounts Receivable: Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CNX reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CNX regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectable amounts were not material in the periods presented. In addition, there were no material financing receivables with a contractual maturity greater than one year at December 31, 2017 or 2016 .
Inventory, Policy [Policy Text Block]	Inventories: Inventories are stated at the lower of cost or net realizable value. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's operations.
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment: CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. Gas advance royalties are royalties that are paid in advance for the right to use an owners land for the exploration and production of oil, NGLs and natural gas. These advance royalties are evaluated periodically, or at a minimum once per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and improvements 10 to 45 Machinery and equipment 3 to 25 Gathering and transmission 30 to 40 Leasehold improvements Life of Lease Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years. The following assets would be amortized using the units-of-production method. Amounts reflect properties where drilling operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 2017 and 2016 , respectively.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	Impairment of Long-lived Assets: Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets' carrying value.
Income Tax, Policy [Policy Text Block]	Income Taxes: Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized. CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]
Asset Retirement Obligations, Policy [Policy Text Block]	: CNX accrues for dismantling and removing costs of gas-related facilities and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Deprecation, Depletion and Amortization on the Consolidated Statements of Income.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Retirement Plan:
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition: Revenues are recognized when title passes to the customers. For natural gas, NGL and oil sales, this occurs at the contractual point of delivery. For land and research and development, revenue is recognized generally as the service is provided to the customer. CNX sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Sales line. CNX purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Sales and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas sales are recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third-party.
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies: From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	Stock-Based Compensation: Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CNX recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 13–Stock-Based Compensation for
Earnings Per Share, Policy [Policy Text Block]	Earnings per Share: Basic earnings per share are computed by dividing net income attributable to CNX shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, restricted stock units and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive:
Derivatives, Policy [Policy Text Block]	Accounting for Derivative Instruments:
Significant Accounting Policies [Text Block]	SIGNIFICANT ACCOUNTING POLICIES: A summary of the significant accounting policies of CNX Resources Corporation and subsidiaries ("CNX " or "the Company") is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements. Basis of Consolidation: The Consolidated Financial Statements include the accounts of CNX Resources Corporation, and its wholly owned and majority-owned and/or controlled subsidiaries, including certain variable interest entities that the Company is required to consolidate pursuant to the Consolidation topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. The portion of these entities that is not owned by the Company is presented as non-controlling interest. Investments in business entities in which CNX does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation. Investments in oil and natural gas producing entities are accounted for under the proportionate consolidation method. Discontinued Operations: Businesses divested are classified in the Consolidated Financial Statements as either discontinued operations or held for sale when the provision of Accounting Standards Codification (ASC) Topic 205 or ASC Topic 360 are met. For businesses classified as discontinued operations, the balance sheet amounts and results of operations are reclassified from their historical presentation to assets and liabilities of discontinued operations on the Consolidated Balance Sheets and to discontinued operations on the Consolidated Statements of Income and Cash Flows for all periods presented. The gains or losses associated with these divested businesses are recorded in discontinued operations on the Consolidated Statements of Income. The disclosures outside of Note 2- Discontinued Operations, for all periods presented, in the accompanying notes generally do not include the assets, liabilities, or operating results of businesses classified as discontinued operations. Use of Estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the consolidated financial statements are related to salary retirement benefits, stock-based compensation, asset retirement obligations, deferred income tax assets and liabilities, contingencies and the values of natural gas, NGLs, condensate and oil (collectively "natural gas") reserves. Cash and Cash Equivalents: Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less. Trade Accounts Receivable: Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CNX reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CNX regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectable amounts were not material in the periods presented. In addition, there were no material financing receivables with a contractual maturity greater than one year at December 31, 2017 or 2016 . Inventories: Inventories are stated at the lower of cost or net realizable value. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in the Company's operations. Property, Plant and Equipment: CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. Gas advance royalties are royalties that are paid in advance for the right to use an owners land for the exploration and production of oil, NGLs and natural gas. These advance royalties are evaluated periodically, or at a minimum once per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and improvements 10 to 45 Machinery and equipment 3 to 25 Gathering and transmission 30 to 40 Leasehold improvements Life of Lease Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years. Impairment of Long-lived Assets: Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets' carrying value. In February 2017, the Company approved a plan to sell its subsidiaries Knox Energy LLC and Coalfield Pipeline Company (collectively, “Knox”). Knox met all of the criteria to be classified as held for sale in February 2017. As part of the required evaluation under the held for sale guidance, during the first quarter, Knox’s book value was evaluated and it was determined that the approximate fair value less costs to sell Knox was less than the carrying value of the net assets to be sold. The resulting impairment of $ 137,865 was included in Impairment of Exploration and Production Properties within the the Consolidated Statements of Income during the year ended December 31, 2017. The sale of Knox closed in the second quarter of 2017 (See Note 3 - Acquisitions and Dispositions for more information). The disposal of Knox did not represent a strategic shift that would have had a major effect on the Company’s operations and financial results and was, therefore, not classified as a discontinued operation in accordance with Topic 205, Presentation of Financial Statements, and Topic 360, Property, Plant and Equipment. Impairment of Proved Properties: CNX performs a quantitative impairment test, whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable, over proved properties using the published NYMEX forward prices, timing, methods and other assumptions consistent with historical periods. Impairment tests require that the Company first compare future undiscounted cash flows by asset group to their respective carrying values. If the carrying amount exceeds the estimated undiscounted future cash flows, a reduction of the carrying amount of the natural gas properties to their estimated fair values is required, which is determined based on discounted cash flow techniques using a market-specific weighted average cost of capital. During the year ended December 31, 2015, certain of the Company’s proved properties, primarily shallow oil and gas assets, failed the undiscounted cash flow portion of the test. After performing the discounted cash flow portion of the test, CNX recorded an impairment of $824,742 , included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. The impairment related to approximately 95% of the Company’s shallow oil and gas assets in West Virginia and Pennsylvania. There were no other impairments related to proved properties in the years ended December 31, 2017, 2016 or 2015. Impairment of Unproved Properties: CNX evaluates capitalized costs of unproved gas properties for recoverability on a prospective basis. Indicators of potential impairment include potential shifts in business strategy, overall economic factors and historical experience. If it is determined that the properties will not yield proved reserves, the related costs are expensed in the period the determination is made. For the year ended December 31, 2015, unproved property impairments relating to the determination that the properties will not yield proved reserves were $4,163 and are included in Impairment of Exploration and Production Properties in the Consolidated Statements of Income. Valuation of the impaired assets is a Level 3 measurement as it incorporates significant unobservable inputs, such as future production levels and operating costs, within the discounted cash flow analysis. This impairment primarily related to the court ruling in June 2015 in the state of New York that officially bans hydraulic fracturing. Exploration expense, which is associated primarily with lease expirations, was $ 48,074 , $ 14,522 and $ 10,119 for the years ended December 31, 2017 , 2016 and 2015 , respectively, and is included in Exploration and Production Related Other Costs in the Consolidated Statements of Income. There were no other impairments related to unproved properties in the years ended December 31, 2017, 2016 or 2015. Income Taxes: Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of the Company's assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized. CNX evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that do not meet the more likely than not to be sustained criteria, the Company determines, on a cumulative probability basis, the largest amount of benefit that is more likely than not to be realized upon ultimate settlement. A previously recognized tax position is reversed when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that the Company believes are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. Asset Retirement Obligations: CNX accrues for dismantling and removing costs of gas-related facilities and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Deprecation, Depletion and Amortization on the Consolidated Statements of Income. Retirement Plan: CNX has a non-contributory defined benefit retirement plan. The benefits for this plan are based primarily on years of service and employees' pay. This plan is accounted for using the guidance outlined in the Compensation - Retirement Benefits Topic of the FASB Accounting Standards Codification. The cost of these retiree benefits are recognized over the employees' service periods. CNX uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income. Investment Plan: CNX has an investment plan that is available to most employees. Throughout the years ended December 31, 2017 and 2016, the Company's matching contribution was 6% of eligible compensation contributed by eligible employees. In 2015, the Company contributed an additional 3% of eligible compensation into the 401(k) plan accounts for employees hired or rehired on or after October 1, 2014 or who were under age 40 or had less than 10 years of service with the Company as of September 30, 2014. This additional contribution was eliminated on January 1, 2016. The Company may also make discretionary contributions to the Plan ranging from 1% to 6% ( 1% to 4% prior to January 1, 2016) of eligible compensation for eligible employees (as defined by the Plan). Discretionary contributions made by the Company were $2,761 for the year ended December 31, 2016. There were no such discretionary contributions made by the Company for the years ended December 31, 2017 and 2015. Total payments and costs were $2,866 , $5,858 and $6,329 for the years ended December 31, 2017 , 2016 and 2015 , respectively, including the discretionary contribution mentioned above. Revenue Recognition: Revenues are recognized when title passes to the customers. For natural gas, NGL and oil sales, this occurs at the contractual point of delivery. For land and research and development, revenue is recognized generally as the service is provided to the customer. CNX sells natural gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty. These transactions qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are, therefore, recorded net within the Consolidated Statements of Income in the Purchased Gas Sales line. CNX purchases natural gas produced by third-parties at market prices less a fee. The gas purchased from third-parties is then resold to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as Purchased Gas Sales and Purchase Gas Costs, respectively, in the Consolidated Statements of Income. Purchased gas sales are recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX from the third-party. Contingencies: From time to time, CNX, or its subsidiaries, are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations (including environmental remediation), employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense of these matters and are based upon the nature of the lawsuit, progress of the case in court, view of legal counsel, prior experience in similar matters and management's intended response. Environmental liabilities are not discounted or reduced by possible recoveries from third-parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred. Stock-Based Compensation: Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification. CNX recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the award's vesting term. See Note 13–Stock-Based Compensation for more information. Earnings per Share: Basic earnings per share are computed by dividing net income attributable to CNX shareholders by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similarly to basic earnings per share, except that the weighted average shares outstanding are increased to include additional shares from stock options, performance stock options, restricted stock units and performance share units, if dilutive. The number of additional shares is calculated by assuming that outstanding stock options and performance share options were exercised, that outstanding restricted stock units and performance share units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive: For the Years Ended December 31, 2017 2016 2015 Anti-Dilutive Options 2,773,423 6,208,813 3,621,002 Anti-Dilutive Restricted Stock Units 18,598 663,003 1,375,659 Anti-Dilutive Performance Share Units — 2,400,326 113,531 Anti-Dilutive Performance Share Options 927,268 802,804 802,804 3,719,289 10,074,946 5,912,996 The computations for basic and dilutive earnings per share are as follows: For the Years Ended December 31, 2017 2016 2015 Numerator: Income (Loss) from Continuing Operations $ 295,039 $ (550,945 ) $ (650,198 ) Income (Loss) from Discontinued Operations 85,708 (297,157 ) 275,313 Net Income (Loss) $ 380,747 $ (848,102 ) $ (374,885 ) Denominator: Weighted-average shares of common stock outstanding 228,835,112 229,387,403 229,186,125 Effect of dilutive shares 2,116,700 — — Weighted-average diluted shares of common stock outstanding 230,951,812 229,387,403 229,186,125 Earnings (Loss) Per Share: Basic (Continuing Operations) $ 1.29 $ (2.40 ) $ (2.84 ) Basic (Discontinued Operations) 0.37 (1.30 ) 1.20 Total Basic $ 1.66 $ (3.70 ) $ (1.64 ) Dilutive (Continuing Operations) $ 1.28 $ (2.40 ) $ (2.84 ) Dilutive (Discontinued Operations) 0.37 (1.30 ) 1.20 Total Dilutive $ 1.65 $ (3.70 ) $ (1.64 ) Shares of common stock outstanding were as follows: 2017 2016 2015 Balance, Beginning of Year 229,443,008 229,054,236 230,265,463 Issuance Related to Stock-Based Compensation (1) 711,214 388,772 1,001,873 Retirement of Common Stock (2) (6,410,900 ) — (2,213,100 ) Balance, End of Year 223,743,322 229,443,008 229,054,236 (1) See Note 13 - Stock-Based Compensation for additional information. (2) See Note 4 - Stock Repurchase for additional information. Other Comprehensive Loss: Changes in Accumulated Other Comprehensive Loss by component, net of tax, were as follows: Balance at December 31, 2016 $ (392,556 ) Other Comprehensive Loss before Reclassifications (541 ) Amounts Reclassified from Accumulated Other Comprehensive Loss 12,769 Distribution of CONSOL Energy, Inc. 371,852 Balance at December 31, 2017 $ (8,476 ) The following table shows the reclassification of adjustments out of Accumulated Other Comprehensive Loss: For the Years Ended December 31, 2017 2016 2015 Derivative Instruments (Note 17) Natural Gas Price Swaps and Options $ — $ (68,481 ) $ (123,105 ) Tax Expense — 25,011 45,054 Net of Tax $ — $ (43,470 ) $ (78,051 ) Actuarially Determined Long-Term Liability Adjustments* (Note 12) Amortization of Prior Service Costs $ (2,775 ) $ (590 ) $ (336,993 ) Recognized Net Actuarial Loss 23,043 23,857 119,222 Curtailment Loss — — 5 Settlement Loss — 22,196 19,053 Total 20,268 45,463 (198,713 ) Tax (Benefit) Expense (7,499 ) (16,959 ) 74,687 Net of Tax $ 12,769 $ 28,504 $ (124,026 ) *Excludes amounts related to the remeasurement of the Actuarially Determined Long-Term Liabilities for the years ended December 31, 2016 and December 31, 2015 . The table above only shows the reclassifications out of Accumulated Other Comprehensive Loss that relate to continuing operations. Accounting for Derivative Instruments: CNX enters into financial derivative instruments to manage its exposure to commodity price volatility. The derivatives are accounted for as an asset or a liability in the accompanying Consolidated Balance Sheets at their fair value using Level 2 inputs, which is further defined in Note 16 - Fair Value of Financial Instruments. Changes in the fair values of derivatives are recorded in earnings unless special hedge accounting criteria are met. CNX de-designated all of its cash flow hedges on December 31, 2014 and accounts for all existing and future natural gas and NGL commodity hedges on a mark-to-market basis, and records changes in fair value in current period earnings. In connection with this de-designation, CNX froze the balances recorded in Accumulated Other Comprehensive Income at December 31, 2014 and reclassified balances to earnings as the underlying physical transactions occurred. As of December 31, 2016, all gains that had been previously deferred in OCI were recognized in earnings. All of the Company's derivative instruments are subject to master netting arrangements with its counterparties, none of which currently require CNX to post collateral for any of its hedges. However, as stated in the counterparty master agreements, if the Company's obligations with one of its counterparties cease to be secured on the same basis as similar obligations with the other lenders under the credit facility, CNX would be required to post collateral for hedges that are in a liability position in excess of defined thresholds. Each of the Company's counterparty master agreements allows, in the event of default, the ability to elect early termination of outstanding contracts. If early termination is elected, CNX and the applicable counterparty would net settle all open hedge positions. CNX is exposed to credit risk in the event of non-performance by counterparties, whose creditworthiness is subject to continuing review. Historically, CNX has not experienced any issues of non-performance by derivative counterparties. Recent Accounting Pronouncements: In May 2017, the FASB issued Update 2017-09 - Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting, which reduces diversity in practice and cost and complexity when applying the guidance in this Topic to a change to the terms or conditions of a share-based payment award. The amendments in this Update provide guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. The amendments in the Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, and should be applied prospectively to an award modification on or after the adoption date. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Company's financial statements. In March 2017, the FASB issued Update 2017-07 - Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which improves the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendments in the Update require that an employer report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented separately from the service cost component and outside a subtotal of income from operations, if one is presented. Because CNX does not present an income from operations subtotal, that requirement is not applicable. Additionally, the Company's service cost component is deemed immaterial, and therefore, the other components of net benefit cost will not be presented separately. For public entities, the amendments in the Update are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted as of the beginning of a fiscal year for which financial statements have not been issued. The adoption of this guidance is not expected to have an impact on the Company's financial statements. In August 2016, the FASB issued Update 2016-15 - Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments relate to debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, and beneficial interests in securitization transactions. The Update also states that, in the absence of specific guidance for cash receipts and payments that have aspects of more than one class of cash flows, an entity should classify each separately identifiable source or use within the cash receipts and payments on the basis of their nature in financing, investing, or operating activities. In situations in which cash receipts or payments cannot be separated by source or use, the appropriate classification should depend on the activity that is likely to be the predominant source or use of cash flows for the item. The amendments in the Update will be applied using a retrospective transition method to each period presented and, for public entities, are effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years.The adoption of this guidance is not expected to have an impact on the Company's financial statements. In May 2014, the FASB issued Update 2014-09, Revenue from Contracts with Customers. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU No. 2015-14 Revenue from Contracts with Customers - Deferral of the Effective Date which approved a one year deferral of ASU No. 2014-09 for annual reporting periods beginning after December 15, 2017. During the fourth quarter of 2017, the Company substantially completed its detailed review of the impact of the standard on each of its contracts. The Company adopted the ASUs using the modified retrospective method of adoption on January 1, 2018 and did not require an adjustment to the opening balance of equity. The Company does not expect the standard to have a significant impact on its results of operations, liquidity or financial position in 2018. The Company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and generate the disclosures required under the new standard. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers including disaggregation of revenue and remaining performance obligations, beginning with our Form 10-Q for the three months ended March 31, 2018. In February 2016, the FASB issued Update 2016-02 - Leases (Topic 842), which increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Update 2016-02 does retain a distinction between finance leases and operating leases, which is substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising from a lease to not significantly change from previous GAAP. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election by class of underlying asset not to recognize lease assets and lease liabilities, but to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the right-to-use asset and lease liability will be initially measured at the present value of the lease payments in the statement of financial position.The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. CNX is currently reviewing all existing leases and agreements that are covered by this standard and is evaluating the impact on the financial statements and related disclosures. Reclassifications: Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2017, with no effect on previously reported net income or stockholder's equity. Subsequent Events: The Company has evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were ide

Mine Closing, Reclamation, and

Mine Closing, Reclamation, and Gas Well Closing ARO Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2017
MINE CLOSING, RECLAMATION & GAS WELL CLOSING [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	NOTE 6—ASSET RETIREMENT OBLIGATIONS: The reconciliation of changes in the asset retirement obligations at December 31, 2017 and 2016 is as follows: As of December 31, 2017 2016 Balance at beginning of period $ 201,006 $ 145,778 Accretion expense 5,760 3,755 Payments (6,875 ) (4,241 ) Revisions in estimated cash flows 5,356 56,398 Other (1,177 ) (684 ) Balance at end of period $ 204,070 $ 201,006
Asset Retirement Obligations, Policy [Policy Text Block]	: CNX accrues for dismantling and removing costs of gas-related facilities and related surface reclamation using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This topic requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Estimates are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Amortization of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in Deprecation, Depletion and Amortization on the Consolidated Statements of Income.

Property, Plant and Equipment P

Property, Plant and Equipment PP&E Accounting Policy (Policies)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Policy [Policy Text Block]	Property, Plant and Equipment: CNX uses the successful efforts method of accounting for natural gas producing activities. Costs of property acquisitions, successful exploratory, development wells and related support equipment and facilities are capitalized. Periodic valuation provisions for impairment of capitalized costs of unproved mineral interests are expensed. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are also amortized on a units-of-production method. Units-of-production amortization rates are revised at least once per year, or more frequently if events and circumstances indicate an adjustment is necessary. Such revisions are accounted for prospectively as changes in accounting estimates. Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred. Gas advance royalties are royalties that are paid in advance for the right to use an owners land for the exploration and production of oil, NGLs and natural gas. These advance royalties are evaluated periodically, or at a minimum once per year, for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Any revisions are accounted for prospectively as changes in accounting estimates. Depreciation of plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms, generally as follows: Years Buildings and improvements 10 to 45 Machinery and equipment 3 to 25 Gathering and transmission 30 to 40 Leasehold improvements Life of Lease Costs for purchased software are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed seven years. The following assets would be amortized using the units-of-production method. Amounts reflect properties where drilling operations have not yet commenced and therefore, are not being amortized for the years ended December 31, 2017 and 2016 , respectively.

Significant Accounting Policy33

Significant Accounting Policy (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block]	The table below sets forth the share-based awards that have been excluded from the computation of the diluted earnings per share because their effect would be anti-dilutive: For the Years Ended December 31, 2017 2016 2015 Anti-Dilutive Options 2,773,423 6,208,813 3,621,002 Anti-Dilutive Restricted Stock Units 18,598 663,003 1,375,659 Anti-Dilutive Performance Share Units — 2,400,326 113,531 Anti-Dilutive Performance Share Options 927,268 802,804 802,804 3,719,289 10,074,946 5,912,996
Schedule of Basic and Dilutive Earnings Per Share [Text Block]	For the Years Ended December 31, 2017 2016 2015 Numerator: Income (Loss) from Continuing Operations $ 295,039 $ (550,945 ) $ (650,198 ) Income (Loss) from Discontinued Operations 85,708 (297,157 ) 275,313 Net Income (Loss) $ 380,747 $ (848,102 ) $ (374,885 ) Denominator: Weighted-average shares of common stock outstanding 228,835,112 229,387,403 229,186,125 Effect of dilutive shares 2,116,700 — — Weighted-average diluted shares of common stock outstanding 230,951,812 229,387,403 229,186,125 Earnings (Loss) Per Share: Basic (Continuing Operations) $ 1.29 $ (2.40 ) $ (2.84 ) Basic (Discontinued Operations) 0.37 (1.30 ) 1.20 Total Basic $ 1.66 $ (3.70 ) $ (1.64 ) Dilutive (Continuing Operations) $ 1.28 $ (2.40 ) $ (2.84 ) Dilutive (Discontinued Operations) 0.37 (1.30 ) 1.20 Total Dilutive $ 1.65 $ (3.70 ) $ (1.64 )
Schedule of Stock by Class [Table Text Block]	Shares of common stock outstanding were as follows: 2017 2016 2015 Balance, Beginning of Year 229,443,008 229,054,236 230,265,463 Issuance Related to Stock-Based Compensation (1) 711,214 388,772 1,001,873 Retirement of Common Stock (2) (6,410,900 ) — (2,213,100 ) Balance, End of Year 223,743,322 229,443,008 229,054,236 (1) See Note 13 - Stock-Based Compensation for additional information.

Mine Closing, Reclamation, an34

Mine Closing, Reclamation, and Gas Well Closing (Tables)	12 Months Ended
	Dec. 31, 2017
MINE CLOSING, RECLAMATION & GAS WELL CLOSING [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	As of December 31, 2017 2016 Balance at beginning of period $ 201,006 $ 145,778 Accretion expense 5,760 3,755 Payments (6,875 ) (4,241 ) Revisions in estimated cash flows 5,356 56,398 Other (1,177 ) (684 ) Balance at end of period $ 204,070 $ 201,006

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	December 31, Property, Plant and Equipment 2017 2016 Intangible drilling cost $ 3,849,689 $ 3,583,599 Proved gas properties 1,999,891 2,016,916 Gas gathering equipment 1,182,234 1,138,299 Unproved gas properties 919,733 1,116,282 Gas wells and related equipment 834,120 800,617 Surface land and other equipment 309,602 323,908 Other gas assets 221,226 204,338 Total Property, Plant and Equipment $ 9,316,495 $ 9,183,959 Less: Accumulated Depreciation, Depletion and Amortization 3,526,742 3,214,984 Total Property, Plant and Equipment - Net $ 5,789,753 $ 5,968,975
Schedule of Amortization Expense Per Unit of Production [Table Text Block]	December 31, 2017 2016 Unproved gas properties $ 919,733 $ 1,116,282 Gas Advance Royalties 13,220 13,762 Total $ 932,953 $ 1,130,044

Other Accrued Liabilities (Tabl

Other Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Other Liabilities Disclosure [Abstract]
Schedule of Accrued Liabilities [Table Text Block]	December 31, 2017 2016 Royalties $ 60,008 $ 42,425 Gas derivatives 41,291 231,573 Accrued interest 32,172 35,127 Transportation charges 13,004 9,856 Short-term incentive compensation 12,062 13,424 Deferred revenue 11,559 7,691 Accrued other taxes 9,779 9,261 Accrued payroll & benefits 6,615 7,322 Other 30,083 26,155 Current portion of long-term liabilities: Asset retirement obligations 5,302 5,302 Salary retirement 1,532 1,505 Total Other Accrued Liabilities $ 223,407 $ 389,641

Long-Term Debt Annual Discounte

Long-Term Debt Annual Discounted Maturities (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Instrument [Line Items]
Schedule of Long-term Debt Instruments [Table Text Block]	December 31, 2017 2016 Debt: Senior Notes due April 2022 at 5.875% (Principal of $1,705,682 and $1,850,000 plus Unamortized Premium of $3,544 and $4,731, respectively) $ 1,709,226 $ 1,854,731 Senior Notes due April 2023 at 8.00% (Principal of $500,000 less Unamortized Discount of $4,751 and $5,656, respectively) 495,249 494,344 Senior Notes due April 2020 at 8.25%, Issued at Par Value — 74,470 Senior Notes due March 2021 at 6.375%, Issued at Par Value — 20,611 Other Note Maturing in 2018 (Principal of $358 and $1,789 less Unamortized Discount of $8 and $117, respectively) 350 1,672 Less: Unamortized Debt Issuance Costs 17,536 23,356 2,187,289 2,422,472 Less: Amounts Due in One Year* 263 1,304 Long-Term Debt $ 2,187,026 $ 2,421,168
Schedule of Maturities of Long-term Debt [Table Text Block]	Annual undiscounted maturities on long-term debt during the next five years and thereafter are as follows: Year ended December 31, Amount 2018 $ 358 2019 — 2020 — 2021 — 2022 1,705,682 Thereafter 500,000 Total Long-Term Debt Maturities $ 2,206,040

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Leases [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	Capital Operating Leases Leases Year Ended December 31, 2018 $ 8,562 $ 7,497 2019 8,362 6,334 2020 7,539 5,565 2021 6,706 5,438 2022 — 5,378 Thereafter — 41,433 Total minimum lease payments $ 31,169 $ 71,645 Less amount representing interest (3.00% – 7.36%) 3,974 Present value of minimum lease payments 27,195 Less amount due in one year 6,848 Total long-term capital lease obligation $ 20,347

Pension and OPEB (Tables)

Pension and OPEB (Tables)	12 Months Ended
	Dec. 31, 2017
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Schedule of Changes in Accumulated Postemployment Benefit Obligations [Table Text Block]	The reconciliation of changes in the benefit obligation, plan assets and funded status of the pension benefits is as follows: December 31, 2017 2016 Change in benefit obligation: Benefit obligation at beginning of period $ 34,051 $ 33,196 Service cost 375 367 Interest cost 1,201 1,250 Actuarial loss 2,127 651 Benefits and other payments (1,474 ) (1,413 ) Benefit obligation at end of period $ 36,280 $ 34,051 Change in plan assets: Fair value of plan assets at beginning of period $ — $ — Company contributions 1,474 1,413 Benefits and other payments (1,474 ) (1,413 ) Fair value of plan assets at end of period $ — $ — Funded status: Current liabilities $ (1,532 ) $ (1,505 ) Noncurrent liabilities (34,748 ) (32,546 ) Net obligation recognized $ (36,280 ) $ (34,051 ) Amounts recognized in accumulated other comprehensive loss consist of: Net actuarial loss $ 14,374 $ 13,772 Prior service credit (626 ) (988 ) Net amount recognized (before tax effect) $ 13,748 $ 12,784
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The components of the net periodic benefit cost are as follows: For the Years Ended December 31, 2017 2016 2015 Components of net periodic benefit cost: Service cost $ 375 $ 367 $ 475 Interest cost 1,201 1,250 1,526 Amortization of prior service credits (362 ) (362 ) (362 ) Recognized net actuarial loss 1,525 1,505 2,252 Settlement loss — — 3,132 Net periodic benefit cost $ 2,739 $ 2,760 $ 7,023
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year [Table Text Block]	Amounts included in accumulated other comprehensive loss which are expected to be recognized in 2018 net periodic benefit cost: Pension Benefits Prior service credit recognition $ (362 ) Actuarial loss recognition $ 1,492
Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets [Table Text Block]	The following table provides information related to the pension plan with an accumulated benefit obligation in excess of plan assets: As of December 31, 2017 2016 Projected benefit obligation $ 36,280 $ 34,051 Accumulated benefit obligation $ 35,264 $ 32,838 Fair value of plan assets $ — $ —
Schedule of Assumptions Used [Table Text Block]	The weighted-average assumptions used to determine benefit obligations are as follows: For the Year Ended As of December 31, 2017 2016 Discount rate 3.70 % 4.26 % Rate of compensation increase 4.05 % 3.90 % The discount rates are determined using a Company-specific yield curve model (above-mean) developed with the assistance of an external actuary. The Company-specific yield curve models (above-mean) use a subset of the expanded bond universe to determine the Company-specific discount rate. Bonds used in the yield curve are rated AA by Moody's or Standard & Poor's as of the measurement date. The yield curve models parallel the plans' projected cash flows, and the underlying cash flows of the bonds included in the models exceed the cash flows needed to satisfy the Company plans. The weighted-average assumptions used to determine net periodic benefit cost are as follows: For the Years ended December 31, 2017 2016 2015 Discount rate 4.26 % 4.55 % 4.07 % Rate of compensation increase 3.90 % 3.80 % 3.80 %
Schedule of Health Care Cost Trend Rates [Table Text Block]
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates [Table Text Block]
Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets [Table Text Block]
Schedule of Allocation of Plan Assets [Table Text Block]
Schedule of Expected Benefit Payments [Table Text Block]	The following benefit payments, which reflect expected future service, are expected to be paid: Pension Year ended December 31, Benefits 2018 $ 1,532 2019 $ 1,596 2020 $ 1,679 2021 $ 1,757 2022 $ 1,842 Year 2023-2027 $ 10,456

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation [Abstract]
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	A summary of the status of stock options granted is presented below: Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic Exercise Term (in Value (in Shares Price years) thousands) Balance at December 31, 2016 6,208,813 $43.12 Granted 56,947 $15.69 Exercised (126,221 ) $7.94 Forfeited/Expired (778,413 ) $30.77 Awards granted in conversion, as a result of the separation 831,189 $21.50 Balance at December 31, 2017 6,192,315 $21.51 5.60 $ — Vested 4,332,383 $27.81 4.42 $ — Exercisable at December 31, 2017 4,187,408 $28.38 4.33 $ —
Schedule of Nonvested Restricted Stock Units Activity [Table Text Block]	Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2016 663,003 $31.97 Granted 863,483 $16.59 Vested (408,117 ) $31.38 Forfeited (54,823 ) $20.67 RSUs surrendered as a result of the separation (253,959 ) $21.14 RSUs granted in conversion, as a result of the separation 127,875 $16.02 Nonvested at December 31, 2017 937,462 $16.01
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	he following table represents the nonvested performance share units and their corresponding fair value (based upon the closing share price) on the date of grant: Number of Weighted Average Shares Grant Date Fair Value Nonvested at December 31, 2016 1,424,551 $26.41 Granted 447,691 $21.87 PSUs issued as a result of 200% payout 187,062 $25.80 Vested (560,960 ) $31.46 Forfeited (16,124 ) $20.65 PSUs surrendered as a result of the separation (379,893 ) $24.04 PSUs granted in conversion, as a result of the separation 170,715 $25.53 Nonvested at December 31, 2017 1,273,042 $25.53

Supplemental Cash Flow (Tables)

Supplemental Cash Flow (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	For the Years Ended December 31, 2017 2016 2015 Interest (net of amounts capitalized) $ 152,047 $ 186,924 $ 207,094 Income taxes $ (121,773 ) $ (18,032 ) $ (59,584 )

Fair Value of Financial Instr42

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value, Assets Measured on Recurring Basis [Table Text Block]	The financial instrument measured at fair value on a recurring basis is summarized below: Fair Value Measurements at Fair Value Measurements at Description Level 1 Level 2 Level 3 Level 1 Level 2 Level 3 Gas Derivatives $ — $ 59,949 $ — $ — $ (188,156 ) $ — Put Option $ — $ (3,500 ) $ — $ — $ — $ —

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance [Table Text Block]	For the Years Ended December 31, 2016 2015 Beginning Balance – Accumulated OCI $ 43,470 $ 121,521 Gain Reclassified from Accumulated OCI (Net of tax: $25,011, $45,054) (43,470 ) (78,051 ) Ending Balance – Accumulated OCI $ — $ 43,470

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Long-term Purchase Commitment [Table Text Block]	Amount of Commitment Expiration Per Period Total Amounts Committed Less Than 1 Year 1-3 Years 3-5 Years Beyond 5 Years Letters of Credit: Firm Transportation $ 239,052 $ 231,992 $ 7,060 $ — $ — Other 20 20 — — — Total Letters of Credit 239,072 232,012 7,060 — — Surety Bonds: Employee-Related 1,850 1,850 — — — Environmental 5,438 4,178 1,260 — — Other 12,485 10,823 1,662 — — Total Surety Bonds 19,773 16,851 2,922 — — Guarantees: CONSOL Energy 192,490 59,809 69,059 41,047 22,575 Total Guarantees 192,490 59,809 69,059 41,047 22,575 Total Commitments $ 451,335 $ 308,672 $ 79,041 $ 41,047 $ 22,575
Unrecorded Unconditional Purchase Obligations Disclosure	. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2017 , the purchase obligations for each of the next five years and beyond were as follows: Obligations Due Amount Less than 1 year $ 181,303 1 - 3 years 264,773 3 - 5 years 237,625 More than 5 years 513,744 Total Purchase Obligations $ 1,197,445

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting, Revenue Reconciling Item [Line Items]
Reconciliation of Operating Profit (Loss) from Segments to Consolidated [Table Text Block]	From Continuing Operations Before Income Tax: For the Years Ended December 31, 2017 2016 2015 Segment Income (Loss) Before Income Taxes for Reportable Business Segments $ 191,126 $ (307,797 ) $ (584,337 ) Segment Loss Before Income Taxes for All Other Business Segments (97,036 ) (109,626 ) (140,496 ) Gain on Sale of Assets 188,063 14,270 61,148 Interest Expense (161,443 ) (182,195 ) (199,121 ) Loss on Debt Extinguishment (2,129 ) — (67,751 ) Earnings (Loss) From Continuing Operations Before Income Tax $ 118,581 $ (585,348 ) $ (930,557 )
Reconciliation of Revenue from Segments to Consolidated [Table Text Block]	Revenue and Other Operating Income: For the Years Ended December 31, 2017 2016 2015 Total Segment Sales from External Customers $ 1,179,019 $ 836,504 $ 741,371 Gain (Loss) on Commodity Derivative Instruments 206,930 (141,021 ) 392,942 Other Income 69,182 64,485 64,424 Total Consolidated Revenue and Other Operating Income $ 1,455,131 $ 759,968 $ 1,198,737
Schedule of Revenue from External Customers Attributed to Foreign Countries by Geographic Area [Table Text Block]
Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country [Table Text Block]
Reconciliation of Assets and Liabilities from Segment to Consolidated	December 31, 2017 2016 Segment Assets for Total Reportable Business Segments $ 6,122,746 $ 6,238,156 Segment Assets for All Other Business Segments 268,569 283,917 Items Excluded from Segment Assets: Cash and Other Investments 509,075 46,216 Recoverable Income Taxes 31,523 114,481 Discontinued Operations — 2,496,921 Total Consolidated Assets $ 6,931,913 $ 9,179,691

Supplemental Gas Data (Tables)

Supplemental Gas Data (Tables)	12 Months Ended
	Dec. 31, 2017
SUPPLEMENTAL GAS DATA: [Abstract]
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The standardized measure is intended to provide a better means for comparing the value of CNX proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities. December 31, 2017 2016 2015 Future Cash Flows (a) Revenues $ 19,261,578 $ 11,303,409 $ 11,837,732 Production costs (7,234,303 ) (5,850,941 ) (6,584,947 ) Development costs (1,710,585 ) (1,550,294 ) (1,220,010 ) Income tax expense (2,475,981 ) (1,482,826 ) (1,532,454 ) Future Net Cash Flows 7,840,709 2,419,348 2,500,321 Discounted to present value at a 10% annual rate (4,709,311 ) (1,464,231 ) (1,481,017 ) Total standardized measure of discounted net cash flows $ 3,131,398 $ 955,117 $ 1,019,304 (a) For 2017, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2017, adjusted for energy content and a regional price differential. For 2017, this adjusted natural gas price was $2.44 per mcf, the adjusted oil price was $38.65 per barrel and the adjusted NGL price was $23.61 per barrel. For 2016, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2016, adjusted for energy content and a regional price differential. For 2016, this adjusted natural gas price was $1.73 per mcf, the adjusted oil price was $25.04 per barrel and the adjusted NGL price was $15.77 per barrel. For 2015, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2015, adjusted for energy content and a regional price differential. For 2015, this adjusted natural gas price was $2.02 per mcf, the adjusted oil price was $25.29 per barrel and the adjusted NGL price was $15.59 per barrel. The following are the principal sources of change in the standardized measure of discounted future net cash flows for consolidated operations during: December 31, 2017 2016 2015 Balance at beginning of period $ 955,117 $ 1,019,304 $ 2,984,158 Net changes in sales prices and production costs 1,983,475 (172,812 ) (4,151,684 ) Sales net of production costs (831,131 ) (150,819 ) (589,533 ) Net change due to revisions in quantity estimates (145,496 ) (35,502 ) 408,006 Net change due to extensions, discoveries and improved recovery 588,574 (54,628 ) 157,016 Development costs incurred during the period 544,809 138,813 666,315 Difference in previously estimated development costs compared to actual costs incurred during the period (129,427 ) (39,821 ) 8,911 Purchase of Reserves In-Place — 238,819 — Sales of Reserves In-Place (55,277 ) (137,998 ) — Changes in estimated future development costs (233,017 ) (158,000 ) 374,982 Net change in future income taxes (404,582 ) 36,513 1,259,744 Timing and Other 712,764 125,529 (354,778 ) Accretion 145,589 145,719 256,167 Total discounted cash flow at end of period $ 3,131,398 $ 955,117 $ 1,019,304
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	Capitalized Costs: As of December 31, 2017 2016 Intangible drilling costs 3,849,689 3,583,599 Proved gas properties 1,999,891 2,016,916 Gas gathering assets 1,182,234 1,138,299 Unproved gas properties 919,733 1,116,282 Gas wells and related equipment 834,120 800,617 Gas well plugging 181,038 176,961 Total Property, Plant and Equipment $ 8,966,705 $ 8,832,674 Accumulated Depreciation, Depletion and Amortization (3,408,606 ) (3,099,751 ) Net Capitalized Costs $ 5,558,099 $ 5,732,923
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	Costs incurred for property acquisition, exploration and development (*): For the Years Ended December 31, 2017 2016 2015 Property acquisitions Proved properties $ 15,850 $ — $ — Unproved properties 32,038 1,537 76,676 Development 544,809 138,813 666,315 Exploration 48,020 32,259 95,371 Total $ 640,717 $ 172,609 $ 838,362 __________ (*) Includes costs incurred whether capitalized or expensed.
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	Results of Operations for Producing Activities: For the Years Ended December 31, 2017 2016 2015 Natural Gas, NGLs and Oil Sales $ 1,125,224 $ 793,248 $ 726,921 Gain (Loss) on Commodity Derivative Instruments 206,930 (141,021 ) 392,942 Purchased Gas Sales 53,795 43,256 14,450 Total Revenue 1,385,949 695,483 1,134,313 Lease Operating Expense 88,932 96,434 121,847 Production, Ad Valorem, and Other Fees 29,267 31,049 30,438 Transportation, Gathering and Compression 382,865 374,350 343,403 Purchased Gas Costs 52,597 42,717 10,721 Impairment of Exploration and Production Properties 137,865 — 828,905 Exploration Costs 48,074 14,522 10,119 DD&A 412,036 419,939 371,783 Total Costs 1,151,636 979,011 1,717,216 Pre-tax Operating Income / (Loss) 234,313 (283,528 ) (582,903 ) Income Tax Benefit (348,676 ) (69,929 ) (251,490 ) Results of Operations for Producing Activities excluding Corporate and Interest Costs $ 582,989 $ (213,599 ) $ (331,413 )
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure [Table Text Block]	The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production: For the Years Ended December 31, 2017 2016 2015 Production (MMcfe) 407,166 394,387 328,657 Total average sales price before effects of financial settlements (per Mcfe) $ 2.76 $ 2.01 $ 2.22 Average effects of financial settlements (per Mcfe) $ (0.10 ) $ 0.62 $ 0.59 Total average sales price including effects of financial settlements (per Mcfe) $ 2.66 $ 2.63 $ 2.81 Average lifting costs, excluding ad valorem and severance taxes (per Mcfe) $ 0.22 $ 0.24 $ 0.37
Schedule of Gas and Oil Acreage [Table Text Block]	Most of the Company's development wells and proved acreage are located in Virginia, West Virginia, Ohio and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2017 , the number of producing wells, developed acreage and undeveloped acreage: Gross Net(1) Producing Gas Wells (including gob wells) 17,013 12,853 Producing Oil Wells 171 12 Acreage Position: Proved Developed Acreage 551,900 543,937 Proved Undeveloped Acreage 41,066 40,703 Unproved Acreage 4,434,714 3,817,015 Total Acreage 5,027,680 4,401,655 ____________ (1)
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	The gas reserves estimates are as follows: Condensate Consolidated Natural Gas NGLs & Crude Oil Operations (MMcf) (Mbbls) (Mbbls) (MMcfe) Balance December 31, 2014 (a) 6,317,600 77,790 7,213 6,827,616 Revisions (b) 1,055,225 45,711 6,569 1,368,909 Price Changes (2,866,123 ) (45,675 ) (3,208 ) (3,159,421 ) Extensions and Discoveries (c) 840,800 13,916 1,707 934,542 Production (287,287 ) (5,530 ) (1,365 ) (328,657 ) Balance December 31, 2015 (a) 5,060,215 86,212 10,916 5,642,989 Revisions (d) 11,559 (19,078 ) 510 (99,849 ) Price Changes (179,914 ) (1,647 ) (34 ) (190,009 ) Extensions and Discoveries (e) 643,688 10,960 1,783 720,146 Production (348,753 ) (6,710 ) (896 ) (394,387 ) Purchases of Reserves In-Place (f) 1,352,759 13,177 1,970 1,443,642 Sales of Reserves In-Place (f) (711,155 ) (22,382 ) (4,240 ) (870,884 ) Balance December 31, 2016 (a) 5,828,399 60,532 10,009 6,251,648 Revisions (g) (202,735 ) 1,162 (5,834 ) (232,321 ) Price Changes 173,738 1,188 (159 ) 181,470 Extensions and Discoveries (e) 1,769,029 17,887 1,800 1,887,153 Production (364,893 ) (6,456 ) (589 ) (407,166 ) Sales of Reserves In-Place (81,780 ) (2,622 ) (277 ) (99,172 ) Balance December 31, 2017 (a) 7,121,758 71,691 4,950 7,581,612 Proved developed resources: December 31, 2015 3,310,894 59,196 5,180 3,697,152 December 31, 2016 3,478,464 30,666 3,474 3,683,302 December 31, 2017 4,051,526 56,022 3,567 4,409,065 Proved undeveloped resources: December 31, 2015 1,749,320 27,016 5,736 1,945,837 December 31, 2016 2,349,934 29,866 6,536 2,568,346 December 31, 2017 3,070,232 15,669 1,383 3,172,547 __________ (a) Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are reserves expected to be recovered through existing wells, with existing equipment and operating methods. (b) The upward revisions in 2015 of 1,369 Bcfe were due to 611 Bcfe increase in both performance and operating cost reductions for developed properties, a 1,200 Bcfe increase for undeveloped properties due to operating cost reductions and expected increases in well performance. These upward revisions in 2015 were offset by a 442 Bcfe downward revision for undeveloped properties that were removed from our operational plans due to "high-grading" and selecting our highest rate of return properties for future development. (c) Extensions and Discoveries in 2015 are due mainly to the high grading of locations which resulted in the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology. (d) The net downward revision of 99.8 Bcfe was the result of 255 Bcfe downward revision for wells that were removed from both internal and JV partner development plans, 113 Bcfe downward revision related to economics for producing properties offset by 268 Bcfe of improved analog performance. (e) Extensions and Discoveries in 2016 and 2017 are due to the addition of wells on the Company's Marcellus and Utica Shale acreage more than one offset location away with continued use of reliable technology. (f) Purchases and Sales of Reserves In-Place in 2016 is the result of the Company's fourth quarter realignment of the Marcellus Shale properties as part of dissolving our joint venture with Noble Energy.
Schedule of Aging of Capitalized Exploratory Well Costs [Table Text Block]	The following table represents the capitalized exploratory well cost activity as indicated: December 31, 2017 2016 2015 Costs reclassified to wells, equipment and facilities based on the determination of proved reserves $ 40,149 $ 40,917 $ 17,179 Costs expensed due to determination of dry hole or abandonment of project $ — $ — $ —
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block]	December 31, 2017 2016 2015 Costs reclassified to wells, equipment and facilities based on the determination of proved reserves $ 40,149 $ 40,917 $ 17,179 Costs expensed due to determination of dry hole or abandonment of project $ — $ — $ —

Supplemental Quarterly Info (47

Supplemental Quarterly Info (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
SUPPLEMENTAL QUARTER INFORMATION: [Abstract]
Quarterly Financial Information [Table Text Block]	Supplemental Quarterly Information (unaudited): (Dollars in thousands, except per share data) Three Months Ended March 31, June 30, September 30, December 31, 2017 2017 2017 2017 Sales (A) $ 304,278 $ 354,409 $ 267,009 $ 460,253 Costs and Expenses (B) $ 162,148 $ 166,330 $ 171,606 $ 214,020 (Loss) Income from Continuing Operations (C) $ (75,234 ) $ 122,384 $ (34,254 ) $ 282,143 Income (Loss) from Discontinued Operations $ 36,268 $ 47,126 $ 7,813 $ (5,499 ) Net (Loss) Income $ (38,966 ) $ 169,510 $ (26,441 ) $ 276,644 Earnings Per Share Basic: (Loss) Income from Continuing Operations $ (0.33 ) $ 0.53 $ (0.15 ) $ 1.24 Income (Loss) from Discontinued Operations $ 0.16 $ 0.21 $ 0.04 $ (0.04 ) Net (Loss) Income $ (0.17 ) $ 0.74 $ (0.11 ) $ 1.20 Dilutive: (Loss) Income from Continuing Operations $ (0.33 ) $ 0.53 $ (0.15 ) $ 1.23 Income (Loss) from Discontinued Operations $ 0.16 $ 0.20 $ 0.04 $ (0.03 ) Net (Loss) Income $ (0.17 ) $ 0.73 $ (0.11 ) $ 1.20	Three Months Ended March 31, June 30, September 30, December 31, 2016 2016 2016 2016 Sales (A) $ 244,935 $ (23,518 ) $ 416,192 $ 57,874 Costs and Expenses (B) $ 162,910 $ 153,971 $ 160,811 $ 170,134 (Loss) Income from Continuing Operations $ (50,219 ) $ (256,535 ) $ 56,264 $ (300,455 ) Loss from Discontinued Operations $ (47,353 ) $ (213,293 ) $ (30,919 ) $ (5,592 ) Net (Loss) Income $ (97,572 ) $ (469,828 ) $ 25,345 $ (306,047 ) Earnings Per Share Basic: (Loss) Income from Continuing Operations $ (0.22 ) $ (1.12 ) $ 0.25 $ (1.31 ) Loss from Discontinued Operations $ (0.21 ) $ (0.93 ) $ (0.14 ) $ (0.02 ) Net (Loss) Income $ (0.43 ) $ (2.05 ) $ 0.11 $ (1.33 ) Dilutive: (Loss) Income from Continuing Operations $ (0.22 ) $ (1.12 ) $ 0.24 $ (1.30 ) Loss from Discontinued Operations $ (0.21 ) $ (0.93 ) $ (0.13 ) $ (0.03 ) Net (Loss) Income $ (0.43 ) $ (2.05 ) $ 0.11 $ (1.33 )

Significant Accounting Policy A

Significant Accounting Policy Anit-Dilutive Securities (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3,719,289	10,074,946	5,912,996
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2,773,423	6,208,813	3,621,002
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	18,598	663,003	1,375,659
Performance Share Units [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	2,400,326	113,531
Performance Share Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	927,268	802,804	802,804

Significant Accounting Policy E

Significant Accounting Policy Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest									$ 295,039	$ (550,945)	$ (650,198)
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	$ 282,143	$ (34,254)	$ (300,455)	$ 122,384	$ (75,234)	$ 56,264	$ (256,535)	$ (50,219)
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	(5,499)	7,813	(5,592)	47,126	36,268	(30,919)	(213,293)	(47,353)	85,708	(297,157)	275,313
Net Income Attributable to CONSOL Energy Inc Shareholders	$ 276,644	$ (26,441)	$ (306,047)	$ 169,510	$ (38,966)	$ 25,345	$ (469,828)	$ (97,572)		(839,148)	(364,475)
Net Income (Loss)									$ 380,747	$ (848,102)	$ (374,885)
Weighted Average Number of Shares Outstanding, Basic									228,835,112	229,387,403	229,186,125
Effect of stock-based compensation awards									2,116,700	0	0
Weighted Average Number of Shares Outstanding, Diluted									230,951,812	229,387,403	229,186,125
Earnings Per Share, Basic	$ 1.20	$ (0.11)	$ (1.33)	$ 0.74	$ (0.17)	$ 0.11	$ (2.05)	$ (0.43)	$ 1.66	$ (3.70)	$ (1.64)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	(0.04)	0.04	(0.02)	0.21	0.16	(0.14)	(0.93)	(0.21)	0.37	(1.30)	1.20
Income (Loss) from Continuing Operations, Per Basic Share	1.24	(0.15)	(1.31)	0.53	(0.33)	0.25	(1.12)	(0.22)	1.29	(2.40)	(2.84)
Earnings Per Share, Diluted	1.20	(0.11)	(1.33)	0.73	(0.17)	0.11	(2.05)	(0.43)	1.65	(3.70)	(1.64)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	(0.03)	0.04	(0.03)	0.20	0.16	(0.13)	(0.93)	(0.21)	0.37	(1.30)	1.20
Income (Loss) from Continuing Operations, Per Diluted Share	$ 1.23	$ (0.15)	$ (1.30)	$ 0.53	$ (0.33)	$ 0.24	$ (1.12)	$ (0.22)	$ 1.28	$ (2.40)	$ (2.84)

Significant Accounting Policy C

Significant Accounting Policy Common Stock Rollforward (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Common Stock [Roll Forward]
Common Stock, Shares, Outstanding	229,443,008	229,054,236	230,265,463
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	711,214	388,772	1,001,873
Common Stock, Shares, Outstanding	223,743,322	229,443,008	229,054,236
Stock Repurchased and Retired During Period, Shares	(6,410,900)	0	(2,213,100)

Significant Accounting Policy O

Significant Accounting Policy Other (Details) - USD ($) $ in Thousands	Jan. 01, 2016	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay			6.00%	6.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay, Additional Contribution Contingent Upon Hire Date					3.00%
Impairment of Long-Lived Assets to be Disposed of			$ 137,865	$ 0	$ 828,905
Defined Contribution Plan, Employer Discretionary Contribution Amount				2,761
Impairment of Oil and Gas Properties		$ 137,865	137,865	0	828,905
Exploration and Production Costs			48,074	14,522	10,119
Defined Contribution Plan, Cost Recognized			$ 2,866	$ 5,858	$ 6,329
Minimum [Member]
Property, Plant and Equipment [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Percent	1.00%		1.00%
Maximum [Member]
Property, Plant and Equipment [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Percent	4.00%		6.00%
Proved Developed [Member]
Property, Plant and Equipment [Line Items]
Impairment of Oil and Gas Properties			$ 824,742
proved undeveloped [Member]
Property, Plant and Equipment [Line Items]
Impairment of Oil and Gas Properties			$ 4,163
Building and Building Improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			10 years
Building and Building Improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			45 years
Machinery and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			3 years
Machinery and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life			25 years
Knox and Coalfield [Member]
Property, Plant and Equipment [Line Items]
Impairment of Long-Lived Assets to be Disposed of			$ 137,865

Significant Accounting Policy52

Significant Accounting Policy Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (8,476)	$ (392,556)
Other Comprehensive Income (Loss), Net of Tax	12,228	(76,696)	$ (164,498)
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	(8,476)	$ (392,556)
Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(541)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 12,769

Significant Accounting Policy53

Significant Accounting Policy Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	$ (8,476)	$ (392,556)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	0	(68,481)	$ (123,105)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax	0	25,011	45,054
Defined Benefit Plan, Actuarial Net (Gains) Losses	23,043	23,857	119,222
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	5
Defined Benefit Plan, Net Periodic Benefit Cost	0	22,196	19,053
Net periodic (benefit) cost	20,268	45,463	(198,713)
Actuarially Determined Long-Term Liability Tax Expense	(7,499)	(16,959)	74,687
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(2,775)	(590)	(336,993)
Actuarially Long-Term Liabilities Net of Tax	12,769	28,504	(124,026)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(8,476)	(392,556)
Other Comprehensive Income (Loss), Disposition During Period, Net of Tax	371,852
Commodity Contract [Member] | Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0	$ (43,470)	$ (78,051)
Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(541)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$ 12,769

Discontinued Operations (Detail

Discontinued Operations (Details)	12 Months Ended
	Dec. 31, 2017USD ($)T	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Impairment of Long-Lived Assets to be Disposed of	$ 137,865,000	$ 0	$ 828,905,000
Fola/Miller Creek [Member]
Cash Paid to Close Deal	28,271,000
Escrow Deposits Related to Property Sales	13,700,000
Gain (Loss) on Sale of Assets and Asset Impairment Charges	53,130,000
Impairment of Long-Lived Assets to be Disposed of	$ 355,681,000
Buchanan and Other Assets [Member]
Royalty Per Ton - Year 1 | T	75
Royalty Per Ton - Year 2 | T	78.75
Royalty Per Ton - Year 3 | T	82.69
Royalty Per Ton - Year 4 | T	86.82
Royalty Per Ton - Year 5 | T	91.16
Royalty Income, Nonoperating	$ 10,073,000	$ 9,575,000
Proceeds from Sale of Property Held-for-sale	402,799,000
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	$ (38,364,000)

Discontinued Operations Income

Discontinued Operations Income Statement (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impairment of Long-Lived Assets to be Disposed of	$ 137,865	$ 0	$ 828,905
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Noncontrolling Interest	10,903	8,954	10,410
Buchanan and Other Assets [Member]
Disposal group, including discontinued operations, coal sales	1,127,907	1,199,950	1,687,237
Disposal Group, Including Discontinued Operations, Cargo and Freight Revenue	66,297	47,790	25,597
Disposal Group, Including Discontinued Operation, Other Income	73,645	74,382	67,969
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax	0	269,124	13,362
Disposal Group, Including Discontinued Operation, Revenue	1,267,849	1,591,246	1,794,165
Disposal Group, Including Discontinued Operation, Operating Expense	1,147,254	1,652,921	1,362,508
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	120,595	(61,675)	431,657
Impairment of Long-Lived Assets to be Disposed of	0	355,681	0
Discontinued Operation, Tax Effect of Discontinued Operation	23,984	(129,153)	145,934
Disposal Group, Including Discontinued Operation, Operating Income (Loss)	$ 85,708	$ (297,157)	$ 275,313

Discontinued Operations Balance

Discontinued Operations Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents		$ 14,176
Disposal Group, Including Discontinued Operation, Other Receivables, Net		18,756
Disposal Group, Including Discontinued Operation, Assets, Current	$ 0	198,823
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment	0	2,171,464
Disposal Group, Including Discontinued Operation, Liabilities, Current	0	385,347
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent	0	1,065,315
Disposal Group, Including Discontinued Operation, Postretirement Plan Benefit Obligation, Noncurrent		659,474
Disposal Group, Including Discontinued Operations, Gas Well Closing, Non-Current		27,648
Disposal Group, Including Discontinued Operations, Workers Compensation, Noncurrent		65,932
Disposal Group, Including Discontinued Operations, Salary Retirement, Non-Current		79,997
Disposal Group, Including Discontinued Operation, Liabilities	$ 0	313,639
Buchanan and Other Assets [Member]
Disposal Group, Including Discontinued Operation, Accounts, Notes and Loans Receivable, Net		95,790
Disposal Group, Including Discontinued Operation, Inventory		50,160
Disposal Group, Including Discontinued Operation, Prepaid and Other Assets		17,571
Disposal Group, Including Discontinued Operation, Prepaid and Other Assets, Current		2,370
Disposal Group, Including Discontinued Operation, Assets, Current		198,823
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment		2,171,464
Disposal Group, Including Discontinued Operation, Other Assets, Noncurrent		126,634
Disposal Group, Including Discontinued Operation, Assets		2,496,921
Disposal Group, Including Discontinued Operation, Accounts Payable		84,550
Disposal Group, Including Discontinued Operation, Liabilities, Current		300,797
Disposal Group, Including Discontinued Operation, Liabilities, Noncurrent		313,639
Disposal Group, including discontinued operations, Pneumoconiosis Benefits		108,073
Disposal Group, including discontinued operations, Mine Closing non current		218,631
Disposal Group, Including Discontinued Operation, Other Liabilities, Noncurrent		(94,440)
Disposal Group, Including Discontinued Operation, Liabilities		$ 1,764,301

Dispositions (Details)

Dispositions (Details) a in Thousands, $ in Thousands	1 Months Ended				3 Months Ended	12 Months Ended
	Sep. 30, 2017USD ($)a	Jun. 30, 2017USD ($)awellsproducing_wells	May 31, 2017USD ($)a	Apr. 30, 2017USD ($)	Sep. 30, 2017USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets						$ 188,063	$ 14,270	$ 61,148
Impairment of Long-Lived Assets to be Disposed of						$ 137,865	0	$ 828,905
Productive Gas Wells, Number of Wells, Gross		12				17,013,000
Wells Drilled, Uncompleted | wells		15
Western Allegheny Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets						$ 48,468
Equity Method Investment, Ownership Percentage									49.00%
Business Acquisition, Cost of Acquired Entity, Transaction Costs							76,297
Certain Loans Acquired in Transfer, Nonaccretable Difference							2,136
Accumulated Distributions in Excess of Net Income							$ 10,780
Surface Land, Colorado [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land | a	22				22
Proceeds from Sale of Property, Plant, and Equipment	$ 23,703
Gain (Loss) on Disposition of Assets	$ 18,758
Marcellus and Utica Acres, Doddridge and Wetzel Counties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land | a		11
Proceeds from Sale of Property, Plant, and Equipment		$ 125,507
Gain (Loss) on Disposition of Assets		$ 9,430
Utica-Point Pleasant Shale Acres, Jefferson, Belmont and Guernsey Counties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land | a			6
Proceeds from Sale of Property, Plant, and Equipment			$ 76,585
Gain (Loss) on Disposition of Assets			$ 72,346
Undeveloped Acres, Marcellus Shale, Allegheny and Westmoreland County [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land | a	8				8
Proceeds from Sale of Property, Plant, and Equipment					$ 36,649
Gain (Loss) on Disposition of Assets					$ 15,251
Marcellus and Utica Shale, Allegheny, Washington, and Westmoreland Counties [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Area of Land | a		11
Proceeds from Sale of Property, Plant, and Equipment		$ 83,500
Gain (Loss) on Disposition of Assets		$ 58,541
Knox and Coalfield [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (Loss) on Disposition of Assets						606
Impairment of Long-Lived Assets to be Disposed of						$ 137,865
Discontinued Operations, Disposed of by Sale [Member] | Knox and Coalfield [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Interest in Consolidated Subsidiaries				$ 19,055

Income Taxes Income Tax Compone

Income Taxes Income Tax Components (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 9,088	$ 10,591
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	31,792
Unrecognized Tax Benefits	$ 29,376	$ 666
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, State and Local, Amount	$ (430)	$ 18,999	$ 39,492
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion, Amount	$ 27,359	$ 1,351	$ 0

Income Taxes Effective Tax Rate

Income Taxes Effective Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Tax Rate Reconciliation [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ 41,503	$ (204,872)	$ (325,695)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion, Amount	$ 27,359	$ 1,351	$ 0
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depletion, Percent	23.10%	(0.20%)	0.00%
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Amount	$ 131,784	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Deduction, Qualified Production Activity, Percent	111.10%	(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Tax Contingency, Amount	$ (1,147)	$ (4,564)	$ (6,312)
Effective Income Tax Rate Reconciliation, Tax Contingency, Percent	(1.00%)	0.80%	0.70%
Effective Income Tax Rate Reconciliation, Tax Settlement, Amount	$ 0	$ (13,463)	$ (36)
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	0.00%	2.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, State and Local, Amount	$ 15,538	$ (20,954)	$ (15,400)
Effective Income Tax Rate Reconciliation, Tax Settlement, State and Local, Percent	13.10%	3.60%	1.70%
Effective Income Tax Rate Reconciliation, Tax Settlement, State and Local, Amount	$ (430)	$ 18,999	$ 39,492
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	(0.40%)	(3.20%)	(4.20%)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	$ (145,772)	$ 184,227	$ 25,903
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	(122.90%)	(32.00%)	(2.80%)
Effective Income Tax Rate Reconciliation, Tax Credit, Foreign, Amount	$ 7,616	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Tax Credit, Foreign, Percent	6.40%	(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Other, Amount	$ 4,798	$ 4,873	$ 1,689
Effective Income Tax Rate Reconciliation, Deduction, Other, Percent	4.00%	0.80%	0.20%
Income Tax Expense (Benefit)	$ (176,458)	$ (34,403)	$ (280,359)
Effective Income Tax Rate Reconciliation, Percent	(148.90%)	6.00%	30.20%
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Amount	$ 24,942	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	21.00%	0.00%	0.00%

Income Taxes Income Taxes (Deta

Income Taxes Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Valuation Allowance [Line Items]
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 28,710
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	44,402	$ 39,850
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	188,080	219,872
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	644	306
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	337	253
Deferred Tax Assets, Valuation Allowance, Noncurrent	61,560	60,488
Deferred Tax Assets, Operating Loss Carryforwards, Federal	99,524	144,450
Deferred Tax Asset, Net Operating Loss, Increase (Decrease), Amount	24,942
Valuation Allowance, Deferred Tax Asset, Change in Amount	9,088	10,591
Current Federal Tax Expense (Benefit)	(31,791)	(101,596)	$ 839
Current State and Local Tax Expense (Benefit)	(1,838)	(8,699)	(5,657)
Current Income Tax Expense (Benefit)	(33,629)	(110,295)	(4,818)
Deferred Federal Income Tax Expense (Benefit)	(166,112)	80,207	(308,797)
Deferred State and Local Income Tax Expense (Benefit)	23,283	(4,315)	33,256
Deferred Income Tax Expense (Benefit)	(142,829)	75,892	(275,541)
Income Tax Expense (Benefit)	(176,458)	(34,403)	$ (280,359)
Tax Cuts and Jobs Act Of 2017, Complete Accounting, Change In Tax Rate, Deferred Tax Asset, Provisional Income Tax Expense (Benefit)	115,291
Tax Cuts and Jobs Act of 2017, AMT Tax Credit, Income Tax Expense (Benefit)	154,385
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	29,376	666
Charitable Contributions [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance, Noncurrent	3,156	$ 5,051
Alternative Minimum tax credit [Member]
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance, Noncurrent	12,413
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 154,384

Income Taxes Net Deferred Tax a

Income Taxes Net Deferred Tax assets/Liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	$ 99,524,000	$ 144,450,000
Deferred Tax Assets, Property, Plant and Equipment	2,020,000	3,210,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	188,080,000	219,872,000
deferred tax assets - gas well closing	16,648,000	20,512,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Pensions	9,404,000	16,928,000
Deferred Tax Assets, Operating Loss Carryforwards	107,756,000	74,310,000
Deferred Tax Assets, Hedging Transactions	0	72,105,000
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	44,402,000	39,850,000
Deferred Tax Assets, Other	33,697,000	48,961,000
Deferred Tax Assets, Gross	501,531,000	640,198,000
Deferred Tax Assets, Valuation Allowance	(136,576,000)	(282,778,000)
Deferred Tax Assets	364,955,000	357,420,000
Deferred Tax Liabilities, Property, Plant and Equipment	(385,366,000)	(450,695,000)
Deferred Tax Liabilities, Investment in Noncontrolled Affiliates	(1,251,000)	(2,237,000)
Deferred Tax Liabilities, Derivatives	(15,248,000)	0
Deferred Tax Liabilities, Leasing Arrangements	(3,648,000)	(5,824,000)
Deferred Tax Liabilities, Other	(3,815,000)	(3,760,000)
Deferred Tax Liabilities, Gross	(409,328,000)	(462,516,000)
Deferred Tax Liabilities, Net	(44,373,000)	(105,096,000)
Deferred Federal Income Tax Expense (Benefit)	107,756	74,310
Deferred Tax Assets, Valuation Allowance, Noncurrent	61,560,000	60,488,000
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 9,088,000	$ 10,591,000

Income Taxes Unrecognized tax b

Income Taxes Unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits	$ 37,813	$ 9,103	$ 12,702
Increase in Unrecognized Tax Benefits is Reasonably Possible	21,902
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	644	306
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions		666
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	7,474	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	(666)	0
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	(4,265)
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	$ 337	$ 253

Stock Repurchase (Details)

Stock Repurchase (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Oct. 30, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Stock Repurchase Program, Authorized Amount		$ 450,000,000	$ 200,000,000
Stock Repurchased During Period, Shares	6,410,900
Treasury Stock Acquired, Average Cost Per Share	$ 16.08
Stock Repurchased and Retired During Period, Value	$ 103,209,000

Mine Closing, Reclamation, an64

Mine Closing, Reclamation, and Gas Well Closing (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Beginning of Period	$ 201,006	$ 145,778
Asset Retirement Obligation, Cash Paid to Settle	(6,875)	(4,241)
Accretion Expense	5,760	3,755
Asset Retirement Obligation, End of Period	204,070	201,006
Asset Retirement Obligation, Other Change	(1,177)	(684)
Asset Retirement Obligation, Revision of Estimate	$ 5,356	$ 56,398

Property, Plant and Equipment65

Property, Plant and Equipment PROPERTY PLANT AND EQUIPMENT (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impairment of Oil and Gas Properties	$ 137,865	$ 137,865	$ 0	$ 828,905
Proved Oil and Gas Property, Successful Effort Method		1,999,891	2,016,916
Drilling Cost		3,849,689	3,583,599
Unproved Oil and Gas Property, Successful Effort Method		919,733	1,116,282
Gas Gathering Systems Net		1,182,234
Surface Land And Other Equipment		309,602	323,908
Property, Plant and Equipment, Gross		9,316,495	9,183,959
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		3,526,742	3,214,984
Total Property, Plant and Equipment-Net		5,789,753	8,140,439
Gas Segment [Member]
Proved Oil and Gas Property, Successful Effort Method			2,016,916
Drilling Cost		3,849,689	3,583,599
Gas Gathering Systems Net			1,138,299
Gas wells and related equipment		834,120	800,617
Other gas assets		221,226	204,338
Property, Plant and Equipment, Gross		9,316,495	9,183,959
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		3,526,742	3,214,984
Total Property, Plant and Equipment-Net		5,789,753	$ 5,968,975
Proved Developed [Member]
Impairment of Oil and Gas Properties		824,742
proved undeveloped [Member]
Impairment of Oil and Gas Properties		$ 4,163

Property, Plant and Equipment A

Property, Plant and Equipment Assets Amortized by Units of Production (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Gas Gathering Systems Net	$ 1,182,234
Unproved Oil and Gas Property, Successful Effort Method	919,733	$ 1,116,282
Property, Plant and Equipment, Gross	9,316,495	9,183,959
Assets amortized by units of production [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	932,953	1,130,044
Gas Segment [Member]
Property, Plant and Equipment [Line Items]
Gas Gathering Systems Net		1,138,299
Property, Plant and Equipment, Gross	9,316,495	9,183,959
Gas Segment [Member] | Assets amortized by units of production [Member]
Property, Plant and Equipment [Line Items]
Unproved Oil and Gas Property, Successful Effort Method	919,733	1,116,282
Advances for Gas Exploration, Development and Production Amount	$ 13,220	$ 13,762

Property, Plant and Equipment C

Property, Plant and Equipment Capital Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capital Leased Assets [Line Items]
Capital Lease Obligations	$ 73,688	$ 73,892
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	54,431	48,814
jewell ridge pipeline [Member]
Capital Leased Assets [Line Items]
Capital Lease Obligations	66,919
Gas Segment [Member]
Capital Leased Assets [Line Items]
Capital Lease Obligations	$ 6,769	$ 6,973

Property, Plant and Equipment J

Property, Plant and Equipment Joint Participation Agreements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Proceeds from Divestiture of Interest in Joint Venture	$ 0	$ 213,295	$ 0
Hess [Member]
Drilling commitment carry	$ 335,000

Short-Term Notes Payable (Detai

Short-Term Notes Payable (Details)	12 Months Ended
	Dec. 31, 2017USD ($)Rate	Dec. 31, 2016USD ($)
Short-term Debt [Line Items]
Terms of Credit Facility	$ 150,000,000
minimum current ratio per credit facility | Rate	1
Interest coverage ratio | Rate	4.78
Senior Secured Credit Facility April122016 Member [Member]
Short-term Debt [Line Items]
Credit facility, face amount	$ 1,500,000,000	$ 2,000,000,000
letters of credit sub limit	650,000
Additional Capacity Available On Credit Lines At Request	$ 500,000,000
Minimum interest coverage ratio | Rate	2.50
Interest coverage ratio	4.01
Letters of credit outstanding	$ 239,072,000	325,676,000
Borrowings and issuance of letters of credit remaining capacity	$ 1,260,928,000	$ 1,674,324,000

Other Accrued Liabilities (Deta

Other Accrued Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Liabilities Disclosure [Abstract]
Derivative Instruments and Hedges, Liabilities	$ 41,291	$ 231,573
Accrued Royalties	60,008	42,425
Interest Payable, Current	32,172	35,127
Accrued Transportation Charges	13,004	9,856
Accrual for Taxes Other than Income Taxes, Current	9,779	9,261
Accrued Bonuses, Current	12,062	13,424
Deferred Revenue	11,559	7,691
Employee-related Liabilities	6,615	7,322
Accrued Liabilities and Other Liabilities	30,083	26,155
Defined Benefit Pension Plan Liabilities, Current	1,532	1,505
Gas well closing liability, current	5,302	5,302
Other Accrued Liabilities	$ 223,407	$ 389,641

Long-Term Debt (Details)

Long-Term Debt (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)call_price	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2017USD ($)
Debt Instrument [Line Items]
Proceeds from Issuance of Private Placement	$ 74,470,000
Unamortized Debt Issuance Expense		$ 17,536,000	$ 23,356,000
Less amounts due in one year		(263,000)	(1,304,000)
Long-term Debt, Excluding Current Maturities		2,187,026,000	2,421,168,000
Debt and Capital Lease Obligations		6,848,000	6,620,000
Gain (Loss) on Extinguishment of Debt		2,129,000	$ 0	$ 67,751,000
Senior Notes Due April 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Fixed Interest, Amount		$ 0.0825
Debt Instrument, Call Price | call_price		101.375
Debt Instrument, Repurchase Amount				940,330,000
Senior Notes due April 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount		$ 20,611,000
Senior Notes 8.25 Percent Due April 2020 Amount Purchased [Member]
Debt Instrument [Line Items]
Gain (Loss) on Extinguishment of Debt		2,129,000
Debt Instrument, Repurchase Amount					$ 144,318,000
Senior notes due April 2020 at 8.25%
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Fixed Interest, Amount		0.0588
Senior Notes Due March 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Percentage Bearing Fixed Interest, Amount		$ 0.06375
Debt Instrument, Call Price | call_price		102.125
Debt Instrument, Repurchase Amount				$ 229,389,000

Long-Term Debt Debt Maturity Sc

Long-Term Debt Debt Maturity Schedule (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 2,187,289	$ 2,422,472
Unamortized Debt Issuance Expense	17,536	23,356
Less amounts due in one year	(263)	(1,304)
Long-term Debt, Excluding Current Maturities	2,187,026	2,421,168
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	358
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	1,705,682
Long-term Debt, Maturities, Repayments of Principal after Year Five	500,000
Long-term Debt	2,206,040
Senior Secured Notes due April 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt	1,709,226
Senior notes due April 2020 at 8.25%
Debt Instrument [Line Items]
Long-term Debt	0	74,470
Senior notes due March 2021 at 6.375%
Debt Instrument [Line Items]
Long-term Debt	0	20,611
Senior Secured Notes Due April 2022 Par Value [Member]
Debt Instrument [Line Items]
Long-term Debt		1,854,731
Senior Notes due April 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt	495,249	494,344
Note due through December 2012 at 6.10%
Debt Instrument [Line Items]
Long-term Debt	$ 350	$ 1,672

Leases Operating Leases (Detail

Leases Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 16,797	$ 20,772	$ 26,360
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Leases, Future Minimum Payments Due, Current	7,497
Operating Leases, Future Minimum Payments, Due in Two Years	6,334
Operating Leases, Future Minimum Payments, Due in Three Years	5,565
Operating Leases, Future Minimum Payments, Due in Four Years	5,438
Operating Leases, Future Minimum Payments, Due in Five Years	5,378
Operating Leases, Future Minimum Payments, Due Thereafter	41,433
Operating Leases, Future Minimum Payments Due	$ 71,645

Leases Capital Leases (Details)

Leases Capital Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments, Interest Included in Payments	$ 3,974
Capital Lease Obligations	20,347	$ 27,262
Capital Leases, Future Minimum Payments Due	31,169
Operating Leases, Future Minimum Payments Due	71,645
Capital Leases, Future Minimum Payments, Net Minimum Payments, Fiscal Year Maturity [Abstract]
Capital Leases, Future Minimum Payments Due, Current	8,562
Operating Leases, Future Minimum Payments Due, Current	7,497
Capital Leases, Future Minimum Payments Due in Two Years	8,362
Operating Leases, Future Minimum Payments, Due in Two Years	6,334
Capital Leases, Future Minimum Payments Due in Three Years	7,539
Operating Leases, Future Minimum Payments, Due in Three Years	5,565
Capital Leases, Future Minimum Payments Due in Four Years	6,706
Operating Leases, Future Minimum Payments, Due in Four Years	5,438
Capital Leases, Future Minimum Payments Due in Five Years	0
Operating Leases, Future Minimum Payments, Due in Five Years	5,378
Capital Leases, Future Minimum Payments Due Thereafter	0
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	27,195
Operating Leases, Future Minimum Payments, Due Thereafter	41,433
Capital Lease Obligations, Current	$ 6,848

Pension and OPEB Pension and OP

Pension and OPEB Pension and OPEB Liability Disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Pension Contributions	$ 1,500
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(2,775)	$ (590)	$ (336,993)
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Curtailments	0	0	5
Defined Benefit Plan, Net Periodic Benefit Cost	0	22,196	19,053
Net periodic (benefit) cost	20,268	45,463	(198,713)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Actuarial Net (Gains) Losses	(23,043)	(23,857)	(119,222)
Pension Plan [Member]
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Service Cost	375	367	475
Defined Benefit Plan, Interest Cost	1,201	1,250	1,526
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(362)	(362)	(362)
Amortization of actuarial gain	1,525	1,505	2,252
Defined Benefit Plan, Net Periodic Benefit Cost	0	0	3,132
Net periodic (benefit) cost	2,739	2,760	7,023
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation	36,280	34,051	33,196
service cost - prior year		367
Defined Benefit Plan, Benefits Paid	(1,474)	(1,413)
Defined Benefit Plan, Actuarial Net (Gains) Losses	2,127	651
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Fair Value of Plan Assets	0	0	$ 0
Defined Benefit Plan, Contributions by Employer	1,474	1,413
Pension and Other Postretirement Defined Benefit Plans, Liabilities, Noncurrent	(34,748)	(32,546)
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	(1,532)	(1,505)
Defined Benefit Plan, Amounts Recognized in Balance Sheet	(36,280)	(34,051)
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), before Tax	14,374	13,772
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Prior Service Cost (Credit), before Tax	(626)	(988)
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax	13,748	12,784
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	(362)
Defined Benefit Plan, Amortization of Net Gains (Losses)	1,492
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Accumulated Benefit Obligation	35,264	32,838
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Projected Benefit Obligation	36,280	34,051
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets, Aggregate Fair Value of Plan Assets	$ 0	$ 0
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.70%	4.26%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Rate of Compensation Increase	4.05%	3.90%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.90%	3.80%	3.80%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.26%	4.55%	4.07%
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract]
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	$ 1,596
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,679
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,757
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,842
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	10,456
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 1,532

Pension and OPEB Pension Plan A

Pension and OPEB Pension Plan Assets Fair Value (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 0	$ 22,196	$ 19,053
Defined Benefit Plan, Actuarial Net (Gains) Losses	(23,043)	(23,857)	(119,222)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation	36,280	34,051	33,196
Defined Benefit Plan, Net Periodic Benefit Cost	0	0	3,132
Defined Benefit Plan, Fair Value of Plan Assets	0	0	0
Defined Benefit Plan, Service Cost	375	367	475
service cost - prior year		367
Defined Benefit Plan, Interest Cost	1,201	1,250	$ 1,526
Defined Benefit Plan, Actuarial Net (Gains) Losses	2,127	651
Defined Benefit Plan, Benefits Paid	$ 1,474	$ 1,413

Stock Based Compensation (Detai

Stock Based Compensation (Details)	12 Months Ended
	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Financing Activities	$ 0	$ 0	$ 208,000
Income Tax Expense (Benefit) Recognized, Additional	4,867
Proceeds from Sale of Treasury Stock	$ (6,681,000)	(1,649,000)	(12,181,000)
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | shares	48,915,944
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 28,712,000
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant | shares	7,411,143
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	$ 6,114,000	7,272,000	5,210,000
Allocated Share-based Compensation Expense	$ 16,983,000	19,316,000	14,314,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.15504
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	$ 17,646,000	0	20,083,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stockholders' Equity Note, Stock Split, Conversion Ratio	0.71890
Board Approved Share Increase [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized | shares	10,550,000
Performance Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	$ 2.42
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	4.42
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Financing Activities	205,000	0	208,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	1,067,000	0	2,744,000
Proceeds from Stock Options Exercised	$ 1,002,000	0	$ 8,281,000
Stockholders' Equity Note, Stock Split, Conversion Ratio	1.15504
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Granted, Value, Share-based Compensation, Net of Forfeitures	$ 353,000	$ 19,305,000

Stock Based Compensation Weight

Stock Based Compensation Weighted Average Fair Value of Grants (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 6.19	$ 5.73
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Te	$ 4.33
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	4.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual TER	$ 5.60
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	6,192,315	6,208,813

Stock Based Compensation Stock

Stock Based Compensation Stock Option Rollforward (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	$ 2.75
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Financing Activities	$ 0	$ 0	$ 208,000
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	711,214	388,772	1,001,873
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures	$ 14,328,000	$ 493,000	$ 26,550,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 12,805,000	$ 19,095,000	20,793,000
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	1,273,042	1,424,551
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 25.53	$ 26.41
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	447,691
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 21.87
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Issued In Period, Result of Payout	187,062
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Issued In Period, Result of Payout, Weighted Average Grant Date Fair Value	$ 25.80
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(560,960)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 31.46
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(16,124)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 20.65
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered, Result of Separation	(379,893)
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered Due to Separation, Weighted Average Exercise Price	$ 24.04
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion, Result of Separation	170,715
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion Due to Separation, Weighted Average Exercise Price	$ 25.53
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Proceeds from Stock Options Exercised	$ 1,002,000	$ 0	8,281,000
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Financing Activities	$ 205,000	$ 0	208,000
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	6,192,315	6,208,813
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 1,067,000	$ 0	$ 2,744,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 21.51	$ 43.12
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	56,947
Share-based comp Options Granted Weighted average exercise price	$ 15.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(126,221)
Share Based Comp, Exercises, Weighted Average Exercise Price	$ 7.94
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(778,413)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 30.77
Share-based Compensation Arrangement by Share-based Payment Award, Options, Granted In Conversion, Result of Separation	(831,189)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Granted In Conversion Due to Separation, Weighted Average Exercise Price	$ 21.50
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	4,332,383
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$ 27.81
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	4,187,408
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 28.38
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual TER	$ 5.60
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	4.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Te	$ 4.33
Performance Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	927,268	802,804
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price	$ 39	$ 45.05
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures	0
Share-based comp Options Granted Weighted average exercise price	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0
Share Based Comp, Exercises, Weighted Average Exercise Price	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Granted In Conversion, Result of Separation	124,464
Share-based Compensation Arrangement by Share-based Payment Award, Options, Granted In Conversion Due to Separation, Weighted Average Exercise Price	$ 39
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number	927,268
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Exercise Price	$ 39
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	927,268
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 39
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual TER	$ 2.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	2.42
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Te	$ 2.42
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	937,462	663,003
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 16.01	$ 31.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	863,483
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 16.59
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(408,117)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 31.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	54,823
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 20.67
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered, Result of Separation	(253,959)
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered Due to Separation, Weighted Average Exercise Price	$ 21.14
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion, Result of Separation	(127,875)
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion Due to Separation, Weighted Average Exercise Price	$ 16.02
Directors - thirty three percent per year [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	436,241
thirty three percent per year [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	5,756,074

Stock Based Compensation Restri

Stock Based Compensation Restricted and Performance Stock Unit Rollforward (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	7,411,143
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 6.19	$ 5.73
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range, Number of Outstanding Options	6,192,315	6,208,813
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures in Period	(778,413)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$ 30.77
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	$ 4.42
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock Issued During Period, Value, Restricted Stock Award, Net of Forfeitures	9,789,000	$ 24,283,000	$ 18,771,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Te	$ 17,646,000	$ 0	$ 20,083,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	937,462	663,003
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 16.01	$ 31.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	863,483
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 16.59
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(408,117)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 31.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 20.67
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered, Result of Separation	(253,959)
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Surrendered Due to Separation, Weighted Average Exercise Price	$ 21.14
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion, Result of Separation	127,875
Share-based Compensation Arrangement by Share-based Payment Award, Other Than Options, Granted In Conversion Due to Separation, Weighted Average Exercise Price	$ 16.02

Stock Based Compensation Option

Stock Based Compensation Option Assumptions and Weighted Average Fair Values (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 6.19	$ 5.73
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	2.00%	1.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%	0.00%
Share Based Comp expected forfeiture rate	0.00%	2.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	51.00%	61.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term, Simplified Method	3.71	4.90

Supplemental Cash Flow Suppleme

Supplemental Cash Flow Supplemental Cash Flow (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Income Taxes Paid			$ (59,584,000)
Interest Paid, Net	$ 152,047,000	$ 186,924,000	207,094,000
Proceeds from Income Tax Refunds	(121,773,000)	(18,032,000)
Capital Lease Obligations [Member]
Other Significant Noncash Transactions [Line Items]
Noncash or Part Noncash Acquisition, Value of Liabilities Assumed			4,241,000
Notes Received from Property Sales [Member]
Other Significant Noncash Transactions [Line Items]
Other Significant Noncash Transaction, Value of Consideration Received	$ 2,379,000	$ 5,501,000	$ 25,827,000

Concentrations of Credit Risk (

Concentrations of Credit Risk (Details) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sales Revenue, Goods, Net [Member] | Direct Energy Business Marketing LLC [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	153,565
Sales Revenue, Goods, Net [Member] | NJR Energy Services Company [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	147,595	106,280	131,299
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	156,817	124,514
Accounts Receivable [Member] | Gas Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	126,387	95,826
Accounts Receivable [Member] | Steel and Coke Producers [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	29,841	27,468
Accounts Receivable [Member] | All Other [Member]
Concentration Risk [Line Items]
Concentration Risk, Customer	589	1,220

Financial Instruments Measured

Financial Instruments Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 509,167	$ 46,299	$ 65,074	$ 175,919
Long-term Debt	2,187,289	2,422,472
Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	59,949	(188,156)
Significant Unobservable Inputs (Level 3)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Put Option [Member] | Quoted Prices in Active Markets for Identical Liabilities (Level 1)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	0	0
Put Option [Member] | Significant Other Observable Inputs (Level 2)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	(3,500)	0
Put Option [Member] | Significant Unobservable Inputs (Level 3)
Fair Value, Assets Measured on Recurring Basis, Financial Statement Captions [Line Items]
Derivative Asset	$ 0	$ 0

Carrying Amounts and Fair Value

Carrying Amounts and Fair Values of Financial Instruments for Which the Fair Value Option Was Not Elected (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents	$ 509,167		$ 46,299	$ 65,074	$ 175,919
Long-term debt	$ (2,187,289)		(2,422,472)
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt		$ (2,204,825)	(2,445,828)
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents		509,167
Long-term debt		$ (2,281,282)	$ (2,422,247)

Derivatives Derivates Impact on

Derivatives Derivates Impact on Income (Details) MMcf in Billions	12 Months Ended
	Dec. 31, 2017USD ($)MMcf	Dec. 31, 2016USD ($)MMcf	Dec. 31, 2015USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	$ (41,174,000)	$ 245,212,000	$ 196,348,000
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	248,104,000	(386,233,000)	196,594,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	(43,470,000)	(78,051,000)
Accumulated Other Comprehensive Income (Loss), Net of Tax	(8,476,000)	(392,556,000)
Accumulated Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Roll Forward]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net		43,470,000	121,521,000
Gain (Loss) on Hedging Activity	$ 206,930,000	$ (141,021,000)	392,942,000
Commodity Member [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMcf	0	744.7
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	$ 0	$ 68,481,000	123,105,000
Accumulated Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Roll Forward]
Gain (Loss) on Hedging Activity	0	68,481,000	123,105,000
Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	34,928,000	(225,797,000)	(193,976,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	319,605,000	(520,170,000)	81,142,000
Accumulated Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Roll Forward]
Gain (Loss) on Hedging Activity	284,677,000	(294,373,000)	275,118,000
Natural Gas Liquids [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	1,216,000	650,000	0
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	1,147,000	(1,148,000)	0
Accumulated Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Roll Forward]
Gain (Loss) on Hedging Activity	(69,000)	(1,798,000)	0
Basis Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	5,030,000	(20,065,000)	(2,372,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(72,648,000)	66,604,000	(7,653,000)
Accumulated Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Roll Forward]
Gain (Loss) on Hedging Activity	$ (77,678,000)	$ 86,669,000	(5,281,000)
Basis Member [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMcf	688.1	482
Propane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMcf	0	126
Natural Gas [Member] | Swap [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax		$ 0	43,470,000
Revenue Mineral Sales [Member] | Natural Gas [Member] | Swap [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		$ (43,470,000)	$ (78,051,000)

Derivatives Derivatives by Bala

Derivatives Derivatives by Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity Member [Member]
Derivative [Line Items]
Derivative Asset, Current	$ 62,369	$ 16
Derivative Liability	48,404	277,119
Derivative Liability, Current	42,419	67,139
Derivative Asset	121,650	29,612
Derivative Liability, Noncurrent	5,985	209,980
Derivative Asset, Noncurrent	59,281	29,596
Basis Swap [Member]
Derivative [Line Items]
Derivative Asset, Current	14,965	56,916
Derivative Liability	52,485	33,168
Derivative Liability, Current	17,179	11,575
Derivative Asset	39,188	92,519
Derivative Liability, Noncurrent	35,306	21,593
Derivative Asset, Noncurrent	$ 24,223	$ 35,603

Maximum Potential Total of Futu

Maximum Potential Total of Future Payments Under Commitment Instruments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	$ 451,335
Surety Bond [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	239,072
Surety Bond [Member] | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	239,052
Surety Bond [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	20
Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	19,773
Surety Bonds: | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	1,850
Surety Bonds: | Environmental
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	5,438
Surety Bonds: | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	12,485
Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	192,490
Guarantees [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	192,490
Balance on First Anniversary [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	308,672
Balance on First Anniversary [Member] | Surety Bond [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	232,012
Balance on First Anniversary [Member] | Surety Bond [Member] | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	231,992
Balance on First Anniversary [Member] | Surety Bond [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	20
Balance on First Anniversary [Member] | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	16,851
Balance on First Anniversary [Member] | Surety Bonds: | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	1,850
Balance on First Anniversary [Member] | Surety Bonds: | Environmental
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	4,178
Balance on First Anniversary [Member] | Surety Bonds: | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	10,823
Balance on First Anniversary [Member] | Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	59,809
Balance on First Anniversary [Member] | Guarantees [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	59,809
More Than One And Within Three Years From Balance Sheet Date [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	79,041
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bond [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	7,060
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bond [Member] | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	7,060
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bond [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	2,922
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bonds: | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bonds: | Environmental
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	1,260
More Than One And Within Three Years From Balance Sheet Date [Member] | Surety Bonds: | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	1,662
More Than One And Within Three Years From Balance Sheet Date [Member] | Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	69,059
More Than One And Within Three Years From Balance Sheet Date [Member] | Guarantees [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	69,059
More Than Three And Within Five Years From Balance Sheet Date [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	41,047
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bond [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bond [Member] | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bond [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bonds: | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bonds: | Environmental
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Surety Bonds: | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
More Than Three And Within Five Years From Balance Sheet Date [Member] | Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	41,047
More Than Three And Within Five Years From Balance Sheet Date [Member] | Guarantees [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	41,047
Beyond Five Years of Balance Sheet Date [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	22,575
Beyond Five Years of Balance Sheet Date [Member] | Surety Bond [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bond [Member] | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bond [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bonds:
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bonds: | Employee-Related
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bonds: | Environmental
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Surety Bonds: | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	0
Beyond Five Years of Balance Sheet Date [Member] | Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	22,575
Beyond Five Years of Balance Sheet Date [Member] | Guarantees [Member] | Other Commitments
Loss Contingencies [Line Items]
Maximum potential total of future payments under commitments	$ 22,575

Unrecorded Unconditional Purcha

Unrecorded Unconditional Purchase Obligation (Details) - Purchase Commitment [Member] $ in Thousands	Dec. 31, 2017USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Less than 1 year	$ 181,303
1 - 3 years	264,773
3 - 5 years	237,625
More than 5 years	513,744
Total Purchase Obligations	$ 1,197,445

Segment Information Industry Se

Segment Information Industry Segment Results (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	$ 1,125,224	$ 793,248	$ 726,921
Sales-Outside	1,125,224	793,248	726,921
Gain (Loss) on Hedging Activity	206,930	(141,021)	392,942
Sales-Purchased Gas	53,795	43,256	14,450
Freight-Outside	69,182	64,485	64,424
Segment Reporting - Intersegment Transfers		0	0
Total Revenue and Other Income	1,455,131	759,968	1,198,737
Sales Revenue, Services, Net	1,455,131	759,968	1,198,737
Income (Loss) from Continuing Operations before Income Taxes, Domestic	118,581	(585,348)	(930,557)
Total Assets	6,931,913	9,179,691	10,929,902
Depreciation, Depletion and Amortization	412,036	419,939	371,783
Segment Reporting - Capital Expenditures	632,846	172,739	840,349
Equity in Earnings of Affiliates	(49,830)	(53,078)	(54,897)
Investments in Unconsolidated Equity Affiliates	197,921	190,964	237,330
Total Reportable Business Segments
Segment Reporting Information [Line Items]
Income (Loss) from Continuing Operations before Income Taxes, Domestic	191,126	(307,797)	(584,337)
Total Assets	6,122,746	6,238,156
Gas Segment [Member]
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	1,125,224	793,248	726,921
Gain (Loss) on Hedging Activity	206,930	(141,021)	392,942
Sales-Purchased Gas	53,795	43,256	14,450
Freight-Outside	69,182	64,485	64,424
Segment Reporting - Intersegment Transfers		0	0
Total Revenue and Other Income	1,455,131	759,968	1,198,737
Income (Loss) from Continuing Operations before Income Taxes, Domestic	191,126	(307,797)	(584,337)
Total Assets	6,122,746	6,238,156	6,894,810
Depreciation, Depletion and Amortization	412,036	419,939	371,783
Segment Reporting - Capital Expenditures	632,846	172,739	840,349
Other Segments [Member]
Segment Reporting Information [Line Items]
Sales-Outside	0	0	0
Gain (Loss) on Hedging Activity	0	0	0
Sales-Purchased Gas	0	0	0
Freight-Outside	0	0	0
Segment Reporting - Intersegment Transfers		0	0
Total Revenue and Other Income	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Domestic	(72,545)	(277,551)	(346,220)
Total Assets	809,167	2,941,535	4,035,092
Depreciation, Depletion and Amortization	0	0	0
Segment Reporting - Capital Expenditures	0	0	0
Coalbed Methane | Gas Segment [Member]
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	208,677	174,323	200,645
Gain (Loss) on Hedging Activity	(9,589)	52,396	67,281
Sales-Purchased Gas	0	0	0
Freight-Outside	0	0	0
Segment Reporting - Intersegment Transfers		424	1,538
Total Revenue and Other Income	199,088	227,143	269,464
Income (Loss) from Continuing Operations before Income Taxes, Domestic	20,346	37,999	59,662
Marcellus Shale | Gas Segment [Member]
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	646,188	414,484	379,453
Gain (Loss) on Hedging Activity	(30,336)	147,282	100,785
Sales-Purchased Gas	0	0	0
Freight-Outside	0	0	0
Segment Reporting - Intersegment Transfers		0	0
Total Revenue and Other Income	615,852	561,766	480,238
Income (Loss) from Continuing Operations before Income Taxes, Domestic	91,436	72,141	56,116
Utica Shale [Member] | Gas Segment [Member]
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	217,020	163,112	92,223
Gain (Loss) on Hedging Activity	1,367	29,285	6,430
Sales-Purchased Gas	0	0	0
Freight-Outside	0	0	0
Segment Reporting - Intersegment Transfers		0	0
Total Revenue and Other Income	218,387	192,397	98,653
Income (Loss) from Continuing Operations before Income Taxes, Domestic	64,741	28,390	(19,428)
Other Gas | Gas Segment [Member]
Segment Reporting Information [Line Items]
Oil and Gas Sales Revenue	53,339	41,329	54,600
Gain (Loss) on Hedging Activity	245,488	(369,984)	218,446
Sales-Purchased Gas	53,795	43,256	14,450
Freight-Outside	69,182	64,485	64,424
Segment Reporting - Intersegment Transfers		(424)	(1,538)
Total Revenue and Other Income	421,804	(221,338)	350,382
Income (Loss) from Continuing Operations before Income Taxes, Domestic	$ 14,603	$ (446,327)	$ (680,687)
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | Direct Energy Business Marketing LLC [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Customer	153,565
Sales Revenue, Goods, Net [Member] | Customer Concentration Risk [Member] | NJR Energy Services Company [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Customer	147,595	106,280	131,299

Reconciliation of Segment Infor

Reconciliation of Segment Information, Revenue and Other Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue From External Customers									$ 1,179,019	$ 836,504	$ 741,371
Gain (Loss) on Hedging Activity									206,930	(141,021)	392,942
Earnings Before Income Taxes:
Income (Loss) from Continuing Operations before Income Taxes, Domestic									118,581	(585,348)	(930,557)
Other Income									69,182	64,485	64,424
Gain (Loss) on Disposition of Assets									188,063	14,270	61,148
Sales	$ 460,253	$ 267,009	$ 57,874	$ 354,409	$ 304,278	$ 416,192	$ (23,518)	$ 244,935	1,455,131	759,968	1,198,737
Total Reportable Business Segments
Earnings Before Income Taxes:
Income (Loss) from Continuing Operations before Income Taxes, Domestic									191,126	(307,797)	(584,337)
Gas Segment [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Gain (Loss) on Hedging Activity									206,930	(141,021)	392,942
Earnings Before Income Taxes:
Income (Loss) from Continuing Operations before Income Taxes, Domestic									191,126	(307,797)	(584,337)
Corporate and Other [Member]
Earnings Before Income Taxes:
Income (Loss) from Continuing Operations before Income Taxes, Domestic									(97,036)	(109,626)	(140,496)
Other Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Gain (Loss) on Hedging Activity									0	0	0
Earnings Before Income Taxes:
Income (Loss) from Continuing Operations before Income Taxes, Domestic									(72,545)	(277,551)	(346,220)
Excludes Gas Segment [Member]
Earnings Before Income Taxes:
Interest Income (Expense), Net and Other Non-operating Activity									(161,443)	(182,195)	(199,121)
Corporate Adjustments And Eliminations [Member]
Earnings Before Income Taxes:
Gain (Loss) Estimates on Extinguishment of Debt									$ (2,129)	$ 0	$ (67,751)

Reconciliation of Segment Inf92

Reconciliation of Segment Information, Total Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Assets:
Total Assets	$ 6,931,913	$ 9,179,691	$ 10,929,902
Items excluded from segment assets:
Income Taxes Receivable, Current	31,523	114,481
Total Property, Plant and Equipment-Net	5,789,753	8,140,439
Deferred Tax Assets	364,955	357,420
Unamortized Debt Issuance Expense	17,536	23,356
Total Reportable Business Segments
Assets:
Total Assets	6,122,746	6,238,156
Gas Segment [Member]
Assets:
Total Assets	6,122,746	6,238,156	6,894,810
Items excluded from segment assets:
Total Property, Plant and Equipment-Net	5,789,753	5,968,975
Corporate and Other [Member]
Assets:
Total Assets	268,569	283,917
Other Segments [Member]
Assets:
Total Assets	809,167	2,941,535	$ 4,035,092
Excludes Gas Segment [Member]
Items excluded from segment assets:
Cash and Other Investments	509,075	46,216
Intersegment Eliminations [Member]
Items excluded from segment assets:
Income Taxes Receivable, Current	31,523	114,481
Disposal Group, Including Discontinued Operation, Assets	$ 0	$ 2,496,921

Segment Information Reconciliat

Segment Information Reconciliation of Earnings Before Income Tax (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Excludes Gas Segment [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Interest Income (Expense), Net and Other Non-operating Activity	$ (161,443)	$ (182,195)	$ (199,121)
Corporate, Adjustments and Eliminations
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Gain (Loss) Estimates on Extinguishment of Debt	$ (2,129)	$ 0	$ (67,751)

Related Party (Details)

Related Party (Details) - USD ($)	1 Months Ended	12 Months Ended
	Nov. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures		$ 197,921,000	$ 190,964,000
Additional Paid in Capital		2,450,323,000	2,460,864,000
Income (Loss) from Equity Method Investments		(49,830,000)	(53,078,000)	$ (54,897,000)
Long-term Debt		2,187,289,000	2,422,472,000
CNX Midstream DevCo I LP [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
CONE Gathering [Member]
Related Party Transaction [Line Items]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures		141,117,000	151,075,000	202,570,000
Limited Partners' Contributed Capital		$ 9,823,000	17,112,000
Additional Paid in Capital			4,621,000
Equity Method Investment, Ownership Percentage		50.00%
Distribution Made to Limited Partner, Cash Distributions Paid		$ (17,254,000)	(8,224,000)
Proceeds from Sale of Equity Method Investments			(70,000,000)
Equity Method Investment, Change in Basis			4,996,000
Equity Method Investment, Asset Transfer		$ (2,527,000)
CNX Midstream DevCo II LP [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage		95.00%
CONE Midstream [Member]
Related Party Transaction [Line Items]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures		$ 34,254,000	18,133,000	11,047,000
Limited Partners' Contributed Capital		38,523,000	31,148,000
Additional Paid in Capital			0
Total Purchase Consideration of Drop		248,000,000
Equity Method Investment, Cash Consideration for Drop		$ 140,000,000
Equity Method Investment, Stock Issued on Drop		2,600,000
Related Party Transaction, Expenses from Transactions with Related Party		$ 136,068	122,256	104,291
Income (Loss) from Equity Method Investments		38,523,000	31,148,000	22,883,000
Distribution Made to Limited Partner, Cash Distributions Paid		(24,929,000)	(19,066,000)
Proceeds from Sale of Equity Method Investments			0
Equity Method Investment, Change in Basis			(4,996,000)
Equity Method Investment, Asset Transfer		$ 2,527,000
CNX Midstream Partners LP [Member]
Related Party Transaction [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		200.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest		33.50%
CONE Gathering [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party		$ 914,000	706,000	1,077
Income (Loss) from Equity Method Investments		9,823,000	17,112,000	20,916,000
CONE [Member]
Related Party Transaction [Line Items]
Due from Related Parties		9,982,000	5,815,000
CNX Coal Resources LP [Member]
Related Party Transaction [Line Items]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures		175,371,000	169,208,000	$ 213,617,000
Limited Partners' Contributed Capital		48,346,000	48,260,000
Additional Paid in Capital			4,621,000
Distribution Made to Limited Partner, Cash Distributions Paid		(42,183,000)	(27,290,000)
Proceeds from Sale of Equity Method Investments			(70,000,000)
Equity Method Investment, Change in Basis			$ 0
Equity Method Investment, Asset Transfer		0
CONSOL Energy [Member]
Related Party Transaction [Line Items]
One-time Transaction Cost, Spin-off		40,545
Due from Related Parties, Current		12,540
Due to Related Parties, Current		15,415
Current Liabilities [Member] | CONSOL Energy [Member]
Related Party Transaction [Line Items]
Due to Related Parties, Current		4,500
Other Liabilities [Member] | CONSOL Energy [Member]
Related Party Transaction [Line Items]
Due to Related Parties, Current		$ 10,915
Subordinated Units [Member]
Related Party Transaction [Line Items]
Conversion of Stock, Shares Converted	29,163,121

Supplemental Gas Data Capitaliz

Supplemental Gas Data Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Drilling Cost	$ 3,849,689	$ 3,583,599
Proved Oil and Gas Property, Successful Effort Method	1,999,891	2,016,916
Gathering assets	1,182,234	1,138,299
Unproved Oil and Gas Property, Successful Effort Method	919,733	1,116,282
Wells and related equipment	834,120	800,617
Gas well plugging	181,038	176,961
Total Property, Plant and Equipment	8,966,705	8,832,674
Accumulated Depreciation, Depletion and Amortization	(3,408,606)	(3,099,751)
Net Capitalized Costs	5,558,099	5,732,923
Gas Segment [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Drilling Cost	$ 3,849,689	3,583,599
Proved Oil and Gas Property, Successful Effort Method		$ 2,016,916

Supplemental Gas Data Oil and G

Supplemental Gas Data Oil and Gas Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proven properties	$ 15,850	$ 0	$ 0
Unproven properties	32,038	1,537	76,676
Development	544,809	138,813	666,315
Exploration	48,020	32,259	95,371
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 640,717	$ 172,609	$ 838,362

Supplemental Gas Data Results o

Supplemental Gas Data Results of Operations (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)wells	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Exploratory Wells Drilled, Net Productive		4	0	3
Development Wells Drilled, Net Nonproductive | wells		4
Production Revenue		$ 1,125,224	$ 793,248	$ 726,921
Gain (Loss) on Hedging Activity		206,930	(141,021)	392,942
Gas Royalty Interests and Purchased Gas Sales		53,795	43,256	14,450
Total Revenue		1,385,949	695,483	1,134,313
Lifting Costs		88,932	96,434	121,847
Production Tax Expense		29,267	31,049	30,438
Gathering Costs		382,865	374,350	343,403
E&P Direct Administration and Selling		48,074	14,522	10,119
Other Costs			419,939	371,783
Impairment of Oil and Gas Properties	$ 137,865	137,865	0	828,905
DD&A		1,151,636	979,011	1,717,216
Total Costs		234,313	(283,528)	(582,903)
Pre-tax Operating Income		(348,676)	(69,929)	(251,490)
Income Taxes		$ 582,989	$ (213,599)	$ (331,413)
Development Wells Drilled, Net Productive		90	36	133
Exploratory Wells Drilled, Net Nonproductive | wells		2
Cnx Gas Guarantor [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Gain (Loss) on Sale of Assets		$ 52,597	$ 42,717	$ 10,721
Other Costs		412,036
Impairment of Oil and Gas Properties		$ 137,865	$ 0	$ 828,905

Supplemental Gas Data Average U

Supplemental Gas Data Average Unit Prices (Details) MBbls in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcfMBbls	Dec. 31, 2016USD ($)MMcfMBbls	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014MMcf
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	99,172,000	870,884,000
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume	712.3
Proved Developed and Undeveloped Reserves, Production	407,166,000	394,387,000	328,657,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		(1,443,642,000)
Consolidated Oil and Gas Production Costs Per Unit of Production | $	$ 88,932,000	$ 96,434,000	$ 121,847,000
Beginning reserves	7,581,612,000	6,251,648,000	5,642,989,000	6,827,616,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(232,321,000)	(99,849,000)	1,368,909,000
Proved Developed and Undeveloped Reserves, Improved Recovery	(181,470,000)	(190,009,000)	(3,159,421,000)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,887,153,000	720,146,000	934,542,000
Plan and Other Revisions [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	107,421,000
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	81,780,000	711,155,000
Proved Developed and Undeveloped Reserves, Production	364,893,000	348,753,000	287,287,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		1,352,759,000
Beginning reserves	7,121,758,000	5,828,399,000	5,060,215,000	6,317,600,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(202,735,000)	11,559,000	1,055,225,000
Proved Developed and Undeveloped Reserves, Improved Recovery	(173,738,000)	(179,914,000)	(2,866,123,000)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,769,029,000	643,688,000
Natural Gas [Member] | Plan and Other Revisions [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			840,800,000
Natural Gas, Per Thousand Cubic Feet [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Average Gas Sales Price before effects of financial settlements | $	$ 2.76	$ 2.01	$ 2.22
Average effects of financial settlements (per thousand cubic feet) | $	(0.10)	0.62	0.59
Average gas sales price including effects of financial settlements (per thousand cubic feet) | $	2.66	2.63	2.81
Consolidated Oil and Gas Production Costs Per Unit of Production | $	$ 0.22	$ 0.24	$ 0.37
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MBbls	2,622	22,382
Proved Developed and Undeveloped Reserves, Production	6,456,000	6,710,000	5,530,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MBbls		(13,177)
Beginning reserves	71,691,000	60,532,000	86,212,000	77,790,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1,162,000	(19,078,000)	45,711,000
Proved Developed and Undeveloped Reserves, Improved Recovery	(1,188,000)	(1,647,000)	(45,675,000)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	17,887,000	10,960,000
Natural Gas Liquids [Member] | Plan and Other Revisions [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			13,916,000
Crude Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MBbls	277	4,240
Proved Developed and Undeveloped Reserves, Production	589,000	896,000	1,365,000
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		(1,970,000)
Beginning reserves	4,950,000	10,009,000	10,916,000	7,213,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(5,834,000)	510,000	6,569,000
Proved Developed and Undeveloped Reserves, Improved Recovery	159,000	(34,000)	(3,208,000)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,800,000	1,783,000
Crude Oil [Member] | Plan and Other Revisions [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			1,707,000

Supplemental Gas Data Acreages

Supplemental Gas Data Acreages (Details) number in Thousands, a in Thousands, $ in Thousands	Dec. 31, 2017USD ($)a	Jun. 30, 2017producing_wells	Dec. 31, 2016USD ($)
Gas and Oil Acreage [Line Items]
Unproved Oil and Gas Property, Successful Effort Method | $	$ 919,733		$ 1,116,282
Proved Oil and Gas Property, Successful Effort Method | $	$ 1,999,891		$ 2,016,916
Productive Gas Wells, Number of Wells, Gross	17,013	12
Gas and Oil Acreage, Undeveloped, Net	40,703
unproved acreage gross	4,434,714
Gas and Oil Acreage, Unproved, Net	3,817,015
Total Acreage - Gross	5,027,680
Total Acreage - Net	4,401,655
Productive Gas Wells, Number of Wells, Net	12,853
Productive Oil Wells, Number of Wells, Gross	171
Productive Oil Wells, Number of Wells, Net	12
Gas and Oil Area, Developed, Gross	551,900
Gas and Oil Area, Developed, Net	543,937
Gas and Oil Area, Undeveloped, Gross	41,066

Supplemental Gas Data Explorata

Supplemental Gas Data Exploratary Wells (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Development Wells Drilled, Net Productive	90	36	133
Costs expensed due to determination of dry hole or abandonment of project	$ 0	$ 0	$ 0
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$ 40,149	$ 40,917	$ 17,179
Exploratory Wells Drilled, Net Productive	4	0	3

Supplemental Gas Data PV-10 (De

Supplemental Gas Data PV-10 (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Revenues	$ 19,261,578	$ 11,303,409	$ 11,837,732
Production costs	7,234,303	5,850,941	6,584,947
Development costs	1,710,585	1,550,294	1,220,010
Income tax expense	2,475,981	1,482,826	1,532,454
Future Net Cash Flows	7,840,709	2,419,348	2,500,321
Discounted to present value at a 10% annual rate	4,709,311	1,464,231	1,481,017
Total standardized measure of discounted net cash flows	$ 3,131,398	$ 955,117	$ 1,019,304	$ 2,984,158

Supplemental Gas Data PV-10 Rec

Supplemental Gas Data PV-10 Reconciliation (Details) MMcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcf	Dec. 31, 2016USD ($)MMcf	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014USD ($)MMcf
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning reserves | MMcf	7,581,612	6,251,648	5,642,989	6,827,616
Revenues	$ 19,261,578	$ 11,303,409	$ 11,837,732
Net changes in sales prices and production costs	1,983,475	(172,812)	(4,151,684)
Net changes in sales prices and production costs	(831,131)	(150,819)	(589,533)
Net change due to revisions in quantity estimates	(145,496)	(35,502)	408,006
Net change due to extensions, discoveries and improved recovery	588,574	(54,628)	157,016
Development costs incurred during the period	544,809	138,813	666,315
Difference in previously estimated development costs compared to actual costs incurred during the period	(129,427)	(39,821)	8,911
Increase Due to Purchases of Minerals in Place	0	238,819	0
Decrease Due to Sales of Minerals in Place	(55,277)	(137,998)	0
Changes in estimated future development costs	(233,017)	(158,000)	374,982
Net change in future income taxes	(404,582)	36,513	1,259,744
Standardized Measure of Discounted Future Net Cash Flow of Proved Oil and Gas Reserves, Timing and Other	712,764	125,529	(354,778)
Accretion of discount and other	145,589	145,719	256,167
Total standardized measure of discounted net cash flows	3,131,398	955,117	1,019,304	$ 2,984,158
Production costs	(7,234,303)	(5,850,941)	(6,584,947)
Development costs	(1,710,585)	(1,550,294)	(1,220,010)
Income tax expense	(2,475,981)	(1,482,826)	(1,532,454)
Future Net Cash Flows	7,840,709	2,419,348	2,500,321
Discounted to present value at a 10% annual rate	$ (4,709,311)	$ (1,464,231)	$ (1,481,017)
Natural Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Beginning reserves | MMcf	7,121,758	5,828,399	5,060,215	6,317,600

Supplemental Gas Data Proved Un

Supplemental Gas Data Proved Undeveloped Reserves (Details) MMcf in Thousands, MBbls in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcfMBbls	Dec. 31, 2016USD ($)MMcfMBbls	Dec. 31, 2015USD ($)MMcf	Dec. 31, 2014MMcf	Jan. 02, 2013MMcf
Reserve Quantities [Line Items]
Payments to Acquire Property, Plant, and Equipment | $	$ 632,846,000	$ 172,739,000	$ 840,349,000
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(99,172)	(870,884)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		(1,443,642)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,887,153	720,146	934,542
Proved Developed and Undeveloped Reserves, Production	407,166	394,387	328,657
Beginning reserves	7,581,612	6,251,648	5,642,989	6,827,616
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(232,321)	(99,849)	1,368,909
Proved Developed and Undeveloped Reserves, Improved Recovery	(181,470)	(190,009)	(3,159,421)
proved undeveloped [Member]
Reserve Quantities [Line Items]
Payments to Acquire Property, Plant, and Equipment | $	$ 247,459
Proved Undeveloped Reserve (Volume)	3,172,547				2,568,346
undeveloped reserves transferred to developed	(735,076)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,698,908
Beginning reserves	3,172,547	2,568,346	1,945,837
Price Changes [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	(5,066)
Plan Changes [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	(472,118)
Plan and Other Revisions [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	107,421
Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning reserves	4,409,065	3,683,302	3,697,152
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place	(81,780)	(711,155)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		1,352,759
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,769,029	643,688
Proved Developed and Undeveloped Reserves, Production	364,893	348,753	287,287
Beginning reserves	7,121,758	5,828,399	5,060,215	6,317,600
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(202,735)	11,559	1,055,225
Proved Developed and Undeveloped Reserves, Improved Recovery	(173,738)	(179,914)	(2,866,123)
Natural Gas [Member] | proved undeveloped [Member]
Reserve Quantities [Line Items]
Beginning reserves	3,070,232	2,349,934	1,749,320
Natural Gas [Member] | Plan and Other Revisions [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			840,800
Natural Gas [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning reserves	4,051,526	3,478,464	3,310,894
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MBbls	(2,622)	(22,382)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place | MBbls		(13,177)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	17,887	10,960
Proved Developed and Undeveloped Reserves, Production	6,456	6,710	5,530
Beginning reserves	71,691	60,532	86,212	77,790
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1,162	(19,078)	45,711
Proved Developed and Undeveloped Reserves, Improved Recovery	(1,188)	(1,647)	(45,675)
Natural Gas Liquids [Member] | proved undeveloped [Member]
Reserve Quantities [Line Items]
Beginning reserves	15,669	29,866	27,016
Natural Gas Liquids [Member] | Plan and Other Revisions [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			13,916
Natural Gas Liquids [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning reserves	56,022	30,666	59,196
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Sales of Minerals in Place | MBbls	(277)	(4,240)
Proved Developed and Undeveloped Reserves, Purchases of Minerals in Place		(1,970)
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions	1,800	1,783
Proved Developed and Undeveloped Reserves, Production	589	896	1,365
Beginning reserves	4,950	10,009	10,916	7,213
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(5,834)	510	6,569
Proved Developed and Undeveloped Reserves, Improved Recovery	159	(34)	(3,208)
Crude Oil [Member] | proved undeveloped [Member]
Reserve Quantities [Line Items]
Beginning reserves	1,383	6,536	5,736
Crude Oil [Member] | Plan and Other Revisions [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions			1,707
Crude Oil [Member] | Proved Developed [Member]
Reserve Quantities [Line Items]
Beginning reserves	3,567	3,474	5,180

Supplemental Quarterly Info 104

Supplemental Quarterly Info (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Impairment of Oil and Gas Properties			$ 137,865							$ 137,865	$ 0	$ 828,905
Sales	$ 460,253	$ 267,009		$ 57,874	$ 354,409	$ 304,278	$ 416,192	$ (23,518)	$ 244,935	1,455,131	759,968	1,198,737
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)	214,020	171,606		170,134	166,330	162,148	160,811	153,971	162,910
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	(5,499)	7,813		(5,592)	47,126	36,268	(30,919)	(213,293)	(47,353)	$ 85,708	(297,157)	275,313
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	282,143	(34,254)		(300,455)	122,384	(75,234)	56,264	(256,535)	(50,219)
Net Income Attributable to CONSOL Energy Inc Shareholders	$ 276,644	$ (26,441)		$ (306,047)	$ 169,510	$ (38,966)	$ 25,345	$ (469,828)	$ (97,572)		$ (839,148)	$ (364,475)
Basic	$ 1.20	$ (0.11)		$ (1.33)	$ 0.74	$ (0.17)	$ 0.11	$ (2.05)	$ (0.43)	$ 1.66	$ (3.70)	$ (1.64)
Income (Loss) from Continuing Operations, Per Diluted Share	1.23	(0.15)		(1.30)	0.53	(0.33)	0.24	(1.12)	(0.22)	1.28	(2.40)	(2.84)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Diluted Share	(0.03)	0.04		(0.03)	0.20	0.16	(0.13)	(0.93)	(0.21)	0.37	(1.30)	1.20
Income (Loss) from Continuing Operations, Per Basic Share	1.24	(0.15)		(1.31)	0.53	(0.33)	0.25	(1.12)	(0.22)	1.29	(2.40)	(2.84)
Diluted	1.20	(0.11)		(1.33)	0.73	(0.17)	0.11	(2.05)	(0.43)	1.65	(3.70)	(1.64)
Income (Loss) from Discontinued Operations and Disposal of Discontinued Operations, Net of Tax, Per Basic Share	$ (0.04)	$ 0.04		$ (0.02)	$ 0.21	$ 0.16	$ (0.14)	$ (0.93)	$ (0.21)	$ 0.37	$ (1.30)	$ 1.20

Subsequent Event (Details)

Subsequent Event (Details)	Jan. 03, 2018USD ($)	Jan. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Subsequent Event [Line Items]
Equity Method Investment, Ownership Percentage	50.00%
Long-term Debt, Gross			$ 2,206,040,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Equity Method Investment, Payment To Purchase	$ 305,000,000
5.875 Percent Senior Noted Due In April 2022 [Member] | Senior Notes [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.875%
Extinguishment of Debt, Amount		$ 384,707,000
Extinguishment Of Debt, Weighted Average Repurchase Price		1.0378