Antero Resources (AR) 10-K 12 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 07, 2020	Jun. 28, 2019
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2019
Entity File Number	001-36120
Entity Registrant Name	ANTERO RESOURCES CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0162034
Entity Address, Address Line One	1615 Wynkoop Street
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202
City Area Code	303
Local Phone Number	357-7310
Title of 12(b) Security	Common Stock, par value $0.01
Trading Symbol	AR
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	No
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		286,677,115
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Central Index Key	0001433270
Amendment Flag	false
Entity Voluntary Filers	No
Entity Public Float			$ 1.5

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Accounts receivable	$ 46,419	$ 51,073
Accounts receivable, related parties	125,000
Accrued revenue	317,886	474,827
Derivative instruments	422,849	245,263
Other current assets	10,731	35,450
Total current assets	922,885	806,613
Oil and gas properties, at cost (successful efforts method):
Unproved properties	1,368,854	1,767,600
Proved properties	11,859,817	12,705,672
Water handling and treatment systems		1,013,818
Gathering systems and facilities	5,802	2,470,708
Other property and equipment	71,895	65,842
Property and equipment, gross	13,306,368	18,023,640
Less accumulated depletion, depreciation, and amortization	(3,327,629)	(4,153,725)
Property and equipment, net	9,978,739	13,869,915
Operating leases right-of-use assets	2,886,500
Derivative instruments	333,174	362,169
Investments in unconsolidated affiliates	1,055,177	433,642
Other assets	21,094	47,125
Total assets	15,197,569	15,519,464
Current liabilities:
Accounts payable	14,498	66,289
Accounts payable, related parties	97,883
Accrued liabilities	400,850	465,070
Revenue distributions payable	207,988	310,827
Derivative instruments	6,721	532
Short-term lease liabilities	305,320	2,459
Other current liabilities	6,879	8,363
Total current liabilities	1,040,139	853,540
Long-term liabilities:
Long-term debt	3,758,868	5,461,688
Deferred income tax liability	781,987	650,788
Derivative instruments	3,519
Long-term lease liabilities	2,583,678	2,873
Other liabilities	58,635	63,098
Total liabilities	8,226,826	7,031,987
Commitments and contingencies (Notes 14 and 15)
Equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued
Common stock, $0.01 par value; authorized - 1,000,000 shares; 308,594 shares and 295,941 shares issued and outstanding at December 31, 2018 and 2019, respectively	2,959	3,086
Additional paid-in capital	6,130,365	6,485,174
Accumulated earnings	837,419	1,177,548
Total stockholders' equity	6,970,743	7,665,808
Noncontrolling interests in consolidated subsidiary		821,669
Total equity	6,970,743	8,487,477
Total liabilities and equity	$ 15,197,569	$ 15,519,464

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Consolidated Balance Sheets
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, authorized shares	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized shares	1,000,000,000	1,000,000,000
Common stock, shares issued	295,941,000	308,594,000
Common stock, shares outstanding	295,941,000	308,594,000

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue and other:
Revenues from contracts with customers									$ 3,940,558	$ 4,133,139	$ 3,018,685
Commodity derivative fair value gains (losses)									463,972	(87,594)	658,283
Marketing derivative fair value gains (losses)									0	94,081	(21,394)
Total revenue and other	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	4,408,690	4,139,626	3,655,574
Operating expenses:
Production and ad valorem taxes									125,142	126,474	94,521
Impairment of oil and gas properties									1,300,444	549,437	159,598
Impairment of midstream assets									14,782	9,658	23,431
Depletion, depreciation, and amortization									914,867	972,465	824,610
Loss on sale of assets									951
Accretion of asset retirement obligations									3,762	2,819	2,610
General and administrative (including equity-based compensation expense of $103,445, $70,414 and $23,559 in 2017, 2018 and 2019, respectively)									178,696	240,344	251,196
Contract termination and rig stacking									14,026
Total operating expenses	1,020,194	2,104,759	1,199,668	1,071,114	1,092,279	1,071,728	1,022,107	881,607	5,395,735	4,067,721	2,915,481
Operating income (loss)	(67,456)	(985,878)	99,996	(33,707)	(46,630)	4,804	(32,763)	146,494	(987,045)	71,905	740,093
Other income (expenses):
Water earnout									125,000
Equity in earnings (loss) of unconsolidated affiliates									(143,216)	40,280	20,194
Loss on the sale of equity investment shares									(108,745)
Impairment of equity investments									(467,590)
Gain on deconsolidation of Antero Midstream Partners LP				1,406,042					1,406,042
Interest expense, net									(228,111)	(286,743)	(268,701)
Gain (loss) on early extinguishment of debt									36,419		(1,500)
Total other income (expenses)									619,799	(246,463)	(250,007)
Income (loss) before									(367,246)	(174,558)	490,086
Provision for income tax benefit									74,110	128,857	295,051
Net income (loss) and comprehensive income (loss) including noncontrolling interests	(482,196)	(878,864)	42,168	1,025,756	18,736	(77,972)	(67,275)	80,810	(293,136)	(45,701)	785,137
Net income and comprehensive income attributable to noncontrolling interests				46,993	140,282	76,447	69,110	65,977	46,993	351,816	170,067
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (482,196)	$ (878,864)	$ 42,168	$ 978,763	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	$ (340,129)	$ (397,517)	$ 615,070
Income (loss) per common share-basic (in dollars per share)	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ (1.11)	$ (1.26)	$ 1.95
Income (loss) per common share-assuming dilution (in dollars per share)	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ (1.11)	$ (1.26)	$ 1.94
Weighted average number of shares outstanding:
Basic (in shares)									306,400	316,036	315,426
Diluted (in shares)									306,400	316,036	316,283
Natural gas sales
Revenue and other:
Revenues from contracts with customers									$ 2,247,162	$ 2,287,939	$ 1,769,284
Natural gas liquids sales
Revenue and other:
Revenues from contracts with customers									1,219,162	1,177,777	870,441
Oil sales
Revenue and other:
Revenues from contracts with customers									177,549	187,178	108,195
Gathering, compression, water handling and treatment
Revenue and other:
Revenues from contracts with customers									4,478	21,344	12,720
Operating expenses:
Cost of goods and services sold									2,146,647	1,339,358	1,095,639
Marketing
Revenue and other:
Revenues from contracts with customers									292,207	458,901	258,045
Operating expenses:
Cost of goods and services sold									549,814	686,055	366,281
Other income
Revenue and other:
Revenues from contracts with customers									4,160
Lease operating
Operating expenses:
Cost of goods and services sold									145,720	136,153	89,057
Exploration
Operating expenses:
Cost of goods and services sold									$ 884	$ 4,958	$ 8,538

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Consolidated Statements of Operations and Comprehensive Income (Loss)
Equity-based compensation expense	$ 23,559	$ 70,414	$ 103,445

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional paid-in capital	Accumulated earnings	Noncontrolling Interests	Total
Balances at Dec. 31, 2016	$ 3,149	$ 5,299,481	$ 959,995	$ 1,465,953	$ 7,728,578
Balances (in shares) at Dec. 31, 2016	314,877
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 15	(18,244)			(18,229)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	1,502
Issuance of common units by Antero Midstream Partners LP, net of underwriter discounts and offering costs				248,956	248,956
Issuance of common units by Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		(15,636)		9,691	(5,945)
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation, net of tax		206,486		(19,940)	186,546
Equity-based compensation		93,669		9,776	103,445
Net income (loss) and comprehensive income (loss)			615,070	170,067	785,137
Effects of changes in ownership interests in consolidated subsidiaries		1,005,196		(1,005,196)
Distributions to non-controlling interests				(152,352)	(152,352)
Balance at Dec. 31, 2017	$ 3,164	6,570,952	1,575,065	726,955	8,876,136
Balance (in shares) at Dec. 31, 2017	316,379
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 13	(11,504)			(11,491)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	1,360
Issuance of common units by Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		(16,536)		11,007	(5,529)
Repurchases and retirements of common stock	$ (91)	(128,993)			(129,084)
Repurchases and retirements of common stock (in shares)	(9,145)
Equity-based compensation		62,618		7,796	70,414
Net income (loss) and comprehensive income (loss)			(397,517)	351,816	(45,701)
Effects of changes in ownership interests in consolidated subsidiaries		8,637		(8,637)
Distributions to non-controlling interests				(267,271)	(267,271)
Other				(3)	(3)
Balance at Dec. 31, 2018	$ 3,086	6,485,174	1,177,548	821,669	8,487,477
Balance (in shares) at Dec. 31, 2018	308,594
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 7	(2,371)			(2,364)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	738
Issuance of common units by Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		(85)		56	(29)
Repurchases and retirements of common stock	$ (134)	(38,638)			(38,772)
Repurchases and retirements of common stock (in shares)	(13,391)
Equity-based compensation		22,457		1,102	23,559
Net income (loss) and comprehensive income (loss)			(340,129)	46,993	(293,136)
Distributions to non-controlling interests				(85,076)	(85,076)
Effect of deconsolidation of Antero Midstream Partners LP		(336,172)		$ (784,744)	(1,120,916)
Balance at Dec. 31, 2019	$ 2,959	$ 6,130,365	$ 837,419		$ 6,970,743
Balance (in shares) at Dec. 31, 2019	295,941

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests	$ (293,136)	$ (45,701)	$ 785,137
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	918,629	975,284	827,220
Impairments	1,782,816	559,095	183,029
Commodity derivative fair value (gains) losses	(463,972)	87,594	(658,283)
Gains on settled commodity derivatives	325,090	243,112	213,940
Premium paid on derivative contracts		(13,318)
Proceeds from derivative monetizations		370,365	749,906
Marketing derivative fair value gains	0	(94,081)	21,394
Gains on settled marketing derivatives		72,687
Deferred income tax expense (benefit)	(79,158)	(128,857)	(295,126)
Loss on sale of assets	951
Equity-based compensation expense	23,559	70,414	103,445
Loss (gain) on early extinguishment of debt	(36,419)		1,500
Loss on sale of Antero Midstream Corporation shares	108,745
Equity in earnings (loss) of unconsolidated affiliates	143,216	(40,280)	(20,194)
Water earnout	(125,000)
Distributions/dividends of earnings from unconsolidated affiliates	157,956	46,415	20,195
Gain on deconsolidation of Antero Midstream Partners LP	(1,406,042)
Other	10,681	4,681	(1,907)
Changes in current assets and liabilities:
Accounts receivable	31,631	(15,156)	(5,214)
Accrued revenue	156,941	(174,706)	(38,162)
Other current assets	(1,025)	(5,817)	(2,755)
Accounts payable including related parties	(27,996)	9,307	9,462
Accrued liabilities	(25,762)	63,562	64,862
Revenue distributions payable	(102,839)	101,210	45,628
Other current liabilities	4,592	(3,823)	2,214
Net cash provided by operating activities	1,103,458	2,081,987	2,006,291
Cash flows provided by (used in) investing activities:
Additions to proved properties			(175,650)
Additions to unproved properties	(88,682)	(172,387)	(204,272)
Drilling and completion costs	(1,254,118)	(1,488,573)	(1,281,985)
Additions to water handling and treatment systems	(24,416)	(97,699)	(194,502)
Additions to gathering systems and facilities	(48,239)	(444,413)	(346,217)
Additions to other property and equipment	(6,700)	(7,514)	(14,127)
Investments in unconsolidated affiliates	(25,020)	(136,475)	(235,004)
Proceeds from sale of common stock of Antero Midstream Corporation	100,000
Proceeds from the Antero Midstream Partners LP Transactions	296,611
Change in other assets	7,091	(3,663)	(12,029)
Proceeds from asset sales	1,983		2,156
Net cash used in investing activities	(1,041,490)	(2,350,724)	(2,461,630)
Cash flows provided by (used in) financing activities:
Issuance of common units by Antero Midstream Partners LP			248,956
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation			311,100
Repurchases of common stock	(38,772)	(129,084)
Issuance of senior notes by Antero Midstream Partners LP	650,000
Repayment of senior notes	(191,092)
Borrowings on bank credit facilities, net	232,000	660,379	90,000
Payments of deferred financing costs	(4,547)	(2,169)	(16,377)
Distributions to noncontrolling interests in Antero Midstream Partners LP	(85,076)	(267,271)	(152,352)
Employee tax withholding for settlement of equity compensation awards	(2,389)	(17,020)	(24,174)
Other	(2,560)	(4,539)	(4,983)
Net cash provided by financing activities	557,564	240,296	452,170
Antero Midstream Partners LP cash at deconsolidation	(619,532)
Net decrease in cash and cash equivalents		(28,441)	(3,169)
Cash and cash equivalents, beginning of period		28,441	31,610
Cash and cash equivalents, end of period			28,441
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	224,331	275,769	263,919
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$ (15,897)	$ (47,717)	$ (547)

Organization

Organization	12 Months Ended
	Dec. 31, 2019
Organization
Organization	(1) Organization Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” the “Company,” “we,” “us” or “our”) are engaged in the exploration, development, and acquisition of natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. The Company’s corporate headquarters are located in Denver, Colorado.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2018 and 2019, and the results of its operations and its cash flows for the years ended December 31, 2017, 2018 and 2019. The Company has items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the year ended December 31, 2019 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs, and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors. (b) Principles of Consolidation The accompanying consolidated financial statements include the accounts of Antero Resources Corporation, its wholly owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. Through March 12, 2019, Antero Midstream Partners LP (“Antero Midstream Partners”), a publicly traded limited partnership, was included in the consolidated financial statements of Antero. Prior to the Closing (defined in Note 3 to the consolidated financial statements), our ownership of Antero Midstream Partners common units represented approximately a limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements. The Transactions (defined in Note 3 to the consolidated financial statements) resulted in the exchange of the limited partner interest we owned in Antero Midstream Partners for common stock of Antero Midstream Corporation representing an approximate interest as of March 13, 2019. As a result, we no longer hold a controlling interest in Antero Midstream Partners and we now have an interest in Antero Midstream Corporation that provides significant influence, but not control, over Antero Midstream Corporation. Thus, effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its consolidated financial statements and accounts for its interest in Antero Midstream Corporation using the equity method of accounting. On December 16, 2019, the Company sold 19,377,592 shares of Antero Midstream Corporation’s common stock to Antero Midstream at a price of $5.1606 per share, which shares were thereafter cancelled by Antero Midstream Corporation, resulting in aggregate proceeds to the Company of $100 million. This reduced Antero’s interest in Antero Midstream Corporation to approximately 28.7% at December 31, 2019. See Note 3 to the consolidated financial statements for further discussion of the Transactions. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. The noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream Partners, which were owned by the public prior to the Transactions, and the incentive distribution rights in Antero Midstream Partners, in both cases during the periods prior to the Transactions. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of equity method investees. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. When Antero records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet. The Company’s equity in earnings of unconsolidated affiliates is adjusted for intercompany transactions and the basis differences recognized due to the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation. The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities). (c) Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates. The Company’s consolidated financial statements are based on a number of significant estimates, including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s consolidated financial statements that involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred and current income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies. (d) Risks and Uncertainties The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities. (e) Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable and revenue distributions payable within its consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its consolidated statements of cash flows. As of December 31, 2019, the book overdraft included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2018, the book overdraft included within accounts payable and revenue distributions payable were (f) Oil and Gas Properties The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells-in- progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred such charges to expense during the years ended December 31, 2017 and 2018. During the year ended December 31, 2019, we recorded an impairment charge of million for design and initial costs related to pads that are no longer planned to be placed into service. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of- production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property-by- property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, commodity price outlooks, and future plans to develop acreage, as well as drilling results, and reservoir performance of wells in the area. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties was The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. During the year ended December 31, 2019, the carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties. As a result, the Company recorded an impairment charge of million related to proved properties in the Utica Shale during the year ended December 31, 2019. The Company did not record any impairment expenses associated with its proved properties during the years ended December 31, 2017 and 2018, nor did it incur any impairment expenses related to proved properties in the Marcellus Shale during the year ended December 31, 2019. At December 31, 2019, the Company did not have capitalized costs related to exploratory wells-in-progress that have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units-of- production method. Depletion expense for oil and gas properties was (g) Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that are not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred. Gathering pipelines and compressor stations are depreciated using the straight-line method over their estimated useful lives of . Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of . Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was 31, 2017, 2018 and 2019, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment. Due to the deconsolidation of Antero Midstream Partners, effective March 13, 2019, gathering pipelines, compressor stations, and water handling and treatment systems owned by Antero Midstream Partners are no longer included in the consolidated financial statements. In December 2019, the Company and Antero Midstream Corporation agreed to extend the initial term of the gathering and compression agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent the Company achieves certain volumetric targets. (h) Impairment of Long-Lived Assets Other than Oil and Gas Properties The Company evaluates its long- lived assets other than oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs, and discount rates typical of third party market participants, which is a Level 3 fair value measurement. Impairment of long-lived assets other than oil and gas properties were $23 million, $10 million and $15 million during the years ended December 31, 2017, 2018 and 2019, respectively, and were associated with midstream assets. (i) Other Property and Equipment Other property and equipment assets are depreciated using the straight-line method over their estimated useful lives, which range from 2 to 20 years . Depreciation expense for other property and equipment was 31, 2017, 2018 and 2019, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment. (j) Deferred Financing Costs Deferred financing costs represent loan origination fees and other initial borrowing costs. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2019, the Company had million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write-off of previously deferred debt issuance costs were (k) Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions. The Company records derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes. (l) Asset Retirement Obligations The Company is obligated to dispose of certain long- lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which is then discounted at the Company’s credit-adjusted, risk- free interest rate. Revisions to estimated AROs often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. (m) Environmental Liabilities Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2018 and 2019, the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows. (n) Natural Gas, NGLs, and Oil Revenues On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. The Company elected the modified retrospective transition method when new standard became effective for the Company on January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on the Company’s financial results. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the sale. Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses. NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor. Under our oil sales contracts, we generally sell oil to purchasers and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to a purchaser. (o) Marketing Revenues and Expenses Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. We have concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser. Fees generated from the sale of excess firm transportation marketed to third parties are included in revenue. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense. (p) Gathering, compression, water handling and treatment revenue Substantially all revenues from the gathering, compression, water handling and treatment operations were derived from transactions for services Antero Midstream Partners provided to our exploration and production operations through March 12, 2019 and were eliminated in consolidation. Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results. See Note 3 to the financial statements for further discussion on the Transactions and Note 18 to the consolidated financial statements for disclosures on the Company’s reportable segments. The portion of such fees shown in our consolidated financial statements prior to March 13, 2019 represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream Partners or usage of Antero Midstream Partners’ gathering and compression systems. For gathering and compression revenue, Antero Midstream Partners satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line. Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream Partners in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream Partners satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility. For services contracted through third-party providers, Antero Midstream Partners’ performance obligation is satisfied when the service performed by the third-party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream Partners in accordance with the water services agreement. (q) Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry. The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables. The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2017, 2018 and 2019 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 ​ ​ 2018 ​ ​ 2019 ​ Company A ​ 4 % ​ 8 % ​ 16 % Company B ​ 14 ​ ​ 6 ​ ​ 15 ​ Company C ​ 20 ​ ​ 13 ​ ​ 9 ​ Company D ​ — ​ ​ 14 ​ ​ 3 ​ All others ​ 62 ​ ​ 59 ​ ​ 57 ​ ​ ​ 100 % ​ 100 % ​ 100 % ​ The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due could have a material adverse effect on the Company’s financial condition and results of operations. The Company has economic hedges in place with different counterparties. The fair value of the Company’s commodity net derivative contracts is approximately million. The estimated fair value of commodity derivative assets has been risk-adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2019 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts. (r) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense. (s) Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long- lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments that are valued using Level 2 inputs include non-exchange traded derivatives such as over-the- counter commodity price swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. (t) Industry Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) marketing and utilization of excess firm transportation capacity, and (3) our equity method investment in Antero Midstream Corporation. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results; however, the Company’s segment disclosures include our equity method investment in Antero Midstream Corporation due to its significance to the Company’s operations. See Note 3 to the consolidated financial statements for further discussion on the Transactions and Note 18 to the consolidated financial statements for disclosures on the Company’s reportable segments. All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who then transport the Company’s production to foreign countries for resale or consumption. (u) Earnings (loss) Per Common Share Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstandi

Deconsolidation of Antero Midst

Deconsolidation of Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2019
Deconsolidation of Antero Midstream Partners LP
Deconsolidation of Antero Midstream Partners LP	(3) Deconsolidation of Antero Midstream Partners LP In 2014, the Company formed Antero Midstream Partners to own, operate, and develop midstream energy assets that service Antero’s production . Antero Midstream Partners’ assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to Antero under long-term, fixed-fee contracts. On March 12, 2019, Antero Midstream GP LP and Antero Midstream Partners completed (the “Closing”) the transactions contemplated by the Simplification Agreement (the “Simplification Agreement”), dated as of October 9, 2018, by and among Antero Midstream GP LP, Antero Midstream Partners and certain of their affiliates, pursuant to which (i) Antero Midstream GP LP was converted from a partnership to a corporation under the laws of the State of Delaware and changed its name to Antero Midstream Corporation, and (ii) an indirect, wholly owned subsidiary of Antero Midstream Corporation was merged with and into Antero Midstream Partners, with Antero Midstream Partners surviving the merger as an indirect, wholly owned subsidiary of Antero Midstream Corporation (together, along with the other transactions contemplated by the Simplification Agreement, the “Transactions”). In connection with the Closing, Antero received Prior to the Closing, the Company’s ownership of Antero Midstream Partners common units represented approximately a 53% limited partner interest in Antero Midstream Partners, and the Company consolidated Antero Midstream Partners’ financial position and results of operations into its consolidated financial statements. The Transactions resulted in the exchange of limited partner interests in Antero Midstream Partners owned by Antero for common stock of Antero Midstream Corporation representing an approximate interest as of March 12, 2019. As a result, the Company no longer held a controlling interest in Antero Midstream Partners and the Company held an interest in Antero Midstream Corporation that provided significant influence, but not control, over Antero Midstream Corporation. Thus, effective March 13, 2019, the Company no longer consolidates Antero Midstream Partners in our consolidated financial statements and accounts for its interest in Antero Midstream Corporation using the equity method of accounting. In addition, the Company recorded a gain on deconsolidation of billion calculated as the sum of (i) the cash proceeds received, (ii) the fair value of the Antero Midstream Corporation common stock received at the Closing, and (iii) the elimination of the noncontrolling interest, less the carrying amount of the investment in Antero Midstream Partners. The fair value of Antero’s retained equity method investment on March 13, 2019 in Antero Midstream Corporation was billion based on the market price of the shares received on March 12, 2019. See Note 5 for further discussion on equity method investments. Antero Midstream Partners’ results of operations are no longer consolidated in the Company’s consolidated statement of operations and comprehensive income (loss) beginning March 13, 2019. Because Antero Midstream Partners does not meet the requirements of a discontinued operation, Antero Midstream Partners’ results of operations continue to be included in the Company’s consolidated statement of operations and comprehensive income (loss) through March 12, 2019. Summarized Financial Information of Antero Midstream Partners The following table presents a summary of assets and liabilities of Antero Midstream Partners as of March 12, 2019, the date of deconsolidation. ​ ​ ​ ​ ​ ​ (in thousands) ​ March 12, 2019 ​ Current assets ​ $ 763,109 ​ Property and equipment, net ​ ​ 3,003,693 ​ Other noncurrent assets ​ ​ 501,208 ​ Total assets ​ $ 4,268,010 ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 123,473 ​ Long-term debt ​ ​ 2,359,084 ​ Other noncurrent liabilities ​ ​ 123,523 ​ Total liabilities ​ $ 2,606,080 ​ ​ ​ ​ ​ ​ Net assets ​ $ 1,661,930 ​ ​

Revenue

Revenue	12 Months Ended
	Dec. 31, 2019
Revenue
Revenue	(4) Revenue (a) Disaggregation of Revenue Revenue is disaggregated by type (in thousands) in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. For more information on reportable segments, see Note 18—Segment Information. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Segment to which ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ revenues relate ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,769,284 ​ $ 2,287,939 ​ ​ 2,247,162 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 93,041 ​ ​ 172,653 ​ ​ 124,563 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 777,400 ​ ​ 1,005,124 ​ ​ 1,094,599 ​ Exploration and production ​ Oil sales ​ ​ 108,195 ​ ​ 187,178 ​ ​ 177,549 ​ Exploration and production ​ Gathering and compression (1) ​ ​ 11,386 ​ ​ 17,817 ​ 3,972 ​ Equity method investment in AMC ​ Water handling and treatment (1) ​ ​ 1,334 ​ ​ 3,527 ​ ​ 506 ​ Equity method investment in AMC ​ Marketing ​ ​ 258,045 ​ ​ 458,901 ​ ​ 292,207 ​ Marketing ​ Total ​ ​ 3,018,685 ​ ​ 4,133,139 ​ 3,940,558 ​ ​ ​ Revenue from derivatives and other sources ​ ​ 636,889 ​ ​ 6,487 ​ ​ 468,132 ​ ​ ​ Total revenue and other ​ $ 3,655,574 ​ $ 4,139,626 ​ ​ 4,408,690 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3 to the consolidated financial statements for further discussion on the Transactions. ​ (b) Transaction Price Allocated to Remaining Performance Obligations For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one (c) Contract Balances Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2018 and 2019, our receivables from contracts with customers were

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2019
Equity Method Investments.
Equity Method Investments	(5) Equity Method Investments At December 31, 2019, Antero owned approximately 28.7% of Antero Midstream Corporation’s common stock, which is reflected in the Company’s consolidated financial statements using the equity method of accounting. See Note 3 to the consolidated financial statements for further discussion on the Transactions. Prior to March 13, 2019, our consolidated results included two equity method investments held by Antero Midstream Partners: a 15% equity interest in Stonewall Gas Gathering LLC (“Stonewall”), which operates a regional gathering pipeline on which the Company is an anchor shipper, and a 50% interest in the joint venture entered into on February 6, 2017 between Antero Midstream Partners and MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, LP, to develop processing and fractionation assets in Appalachia (the “Joint Venture”). Effective March 13, 2019, the equity in earnings of these investments are accounted for in the equity in earnings of Antero Midstream Corporation. At December 31, 2019, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded an impairment of $468 million. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation at December 31, 2019 (Level 1). The following table is a reconciliation of investments in unconsolidated affiliates for the years ending December 31, 2018 and 2019 in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ MarkWest ​ Antero Midstream ​ ​ ​ ​ ​ Stonewall (1) ​ Joint Venture ​ Corporation (2) ​ Total ​ Balance at December 31, 2017 ​ $ 67,128 ​ ​ 236,174 ​ ​ — ​ ​ 303,302 ​ Investments (3) ​ — ​ ​ 136,475 ​ ​ — ​ ​ 136,475 ​ Equity in net income of unconsolidated affiliates ​ ​ 10,740 ​ ​ 29,540 ​ ​ — ​ ​ 40,280 ​ Distributions from unconsolidated affiliates ​ (9,765) ​ ​ (36,650) ​ ​ — ​ ​ (46,415) ​ Balance at December 31, 2018 ​ $ 68,103 ​ ​ 365,539 ​ ​ — ​ ​ 433,642 ​ Investments (3) ​ — ​ ​ 25,020 ​ ​ — ​ ​ 25,020 ​ Equity in net income (loss) of unconsolidated affiliates ​ ​ 1,894 ​ ​ 10,370 ​ ​ (155,480) ​ ​ (143,216) ​ Distributions/dividends from unconsolidated affiliates ​ (3,000) ​ ​ (9,605) ​ ​ (145,351) ​ ​ (157,956) ​ Return of investment (4) ​ ​ — ​ ​ — ​ ​ (208,745) ​ ​ (208,745) ​ Impairment (5) ​ ​ — ​ ​ — ​ ​ (467,590) ​ ​ (467,590) ​ Elimination of intercompany profit ​ ​ — ​ ​ — ​ ​ 44,548 ​ ​ 44,548 ​ Effects of deconsolidation (6) ​ (66,997) ​ ​ (391,324) ​ ​ 1,987,795 ​ ​ 1,529,474 ​ Balance at December 31, 2019 ​ $ — ​ ​ — ​ ​ 1,055,177 ​ ​ 1,055,177 ​ (1) Distributions are net of operating and capital requirements retained by Stonewall. (2) As adjusted for the amortization of the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation and as adjusted for the return of investment. (3) Investments in the Joint Venture during the year ended December 31, 2019 relate to capital contributions for construction of additional processing facilities. (4) In December 2019, Antero Midstream Corporation repurchased $100 million of its shares of common stock from the Company resulting in a return of investment. The Company recorded an $109 million loss on investment due to the carrying value exceeding the fair value of the stock repurchased. (5) Other-than-temporary impairment in Antero Midstream Corporation recorded as of December 31, 2019 to reduce the carrying value to fair value. (6) Effective March 13, 2019, the equity in earnings of Stonewall and the Joint Venture are accounted for in the equity in earnings of Antero Midstream Corporation. ​ Summarized Financial Information of Antero Midstream Corporation ​ The following tables present summarized financial information of Antero Midstream Corporation. Summarized financial information is presented from March 13, 2019. Balance Sheet ​ ​ ​ ​ ​ ​ ​ December 31, ​ (in thousands) ​ 2019 ​ Current assets ​ $ 108,558 ​ Noncurrent assets ​ ​ 6,174,320 ​ Total assets ​ $ 6,282,878 ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 242,084 ​ Noncurrent liabilities ​ ​ 2,897,380 ​ Stockholders' equity ​ ​ 3,143,414 ​ Total liabilities and equity ​ $ 6,282,878 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ For the period ​ ​ ​ March 13, 2019 ​ ​ ​ through ​ (in thousands) ​ December 31, 2019 ​ Revenues ​ $ 792,588 ​ Operating expenses ​ ​ 1,177,610 ​ Loss from operations ​ $ (385,022) ​ Net loss attributable to the equity method investments ​ $ (341,565) ​ ​

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2019
Accrued Liabilities
Accrued Liabilities	(6) Accrued Liabilities Accrued liabilities as of December 31, 2018 and 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2018 2019 ​ Capital expenditures ​ $ 113,237 ​ 105,706 ​ Gathering, compression, processing, and transportation expenses ​ ​ 148,032 ​ ​ 134,153 ​ Marketing expenses ​ ​ 67,082 ​ ​ 52,612 ​ Interest expense, net ​ 43,444 ​ 30,834 ​ Other ​ 93,275 ​ 77,545 ​ Total accrued liabilities ​ $ 465,070 ​ 400,850 ​ ​

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2019
Long-Term Debt.
Long-Term Debt	(7) Long-Term Debt Long-term debt as of December 31, 2018 and 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ 2018 2019 Antero Resources: ​ ​ ​ ​ ​ ​ Credit Facility (a) ​ $ 405,000 ​ 552,000 5.375% senior notes due 2021 (b) ​ 1,000,000 ​ 952,500 5.125% senior notes due 2022 (c) ​ ​ 1,100,000 ​ ​ 923,041 5.625% senior notes due 2023 (d) ​ ​ 750,000 ​ ​ 750,000 5.00% senior notes due 2025 (e) ​ ​ 600,000 ​ ​ 600,000 Net unamortized premium ​ 1,241 ​ 791 Net unamortized debt issuance costs ​ ​ (26,700) ​ ​ (19,464) Long-term debt ​ ​ 3,829,541 ​ ​ 3,758,868 Antero Midstream Partners: (1) ​ ​ ​ ​ ​ ​ Midstream Credit Facility ​ ​ 990,000 ​ ​ — 5.375% senior notes due 2024 ​ ​ 650,000 ​ ​ — Net unamortized debt issuance costs ​ ​ (7,853) ​ ​ — Long-term debt ​ ​ 1,632,147 ​ ​ — Consolidated long-term debt ​ $ 5,461,688 ​ 3,758,868 (1) At December 31, 2018, Antero Midstream Partners’ indebtedness was included in the consolidated financial statements of Antero. At December 31, 2019, following the deconsolidation, Antero Midstream Partners’ outstanding indebtedness is no longer reflected in Antero Resources’ consolidated financial statements. See Note 3 to the consolidated financial statements for further discussion on the Transactions. ​ (a) Senior Secured Revolving Credit Facility Antero Resources has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of bank lenders. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero Resources’ assets and are subject to regular annual redeterminations. The borrowing base and lender commitments were each reaffirmed in the annual redetermination in April 2019. The next redetermination of the borrowing base is scheduled to occur in April 2020. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero Resources’ senior notes then outstanding. In October 2019, lender commitments under the Credit Facility were increased from $2.5 billion to $2.64 billion. At December 31, 2019, the borrowing base under the Credit Facility was $4.5 billion and lender commitments were $2.64 billion. Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero Resources elects to give notice to the Administrative Agent that Antero Resources has received at least one of (i) a BBB- or better rating from Standard & Poor’s and (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at Antero Resources’ election. During any period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of Antero Resources’ properties, Antero Resources’ and Antero Subsidiary Holdings LLC’s ownership interests in Antero Midstream Corporation, Antero Resources’ ownership interests in Antero Subsidiary Holdings LLC and Monroe Pipeline LLC, and guarantees from Antero Resources’ restricted subsidiaries, as applicable. During an Investment Grade Period, the liens securing the obligations under the Credit Facility shall be automatically released (subject to the provisions of the Credit Facility). The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. During any period that is not an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Resources’ election at the time of borrowing, plus an applicable rate based on Antero Resources’ borrowing base utilization which ranges from 25 basis points to 225 basis points. During an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Resources’ election at the time of borrowing, plus an applicable rate based on Antero Resources’ credit rating which ranges from 12.5 basis points to 175 basis points. Antero Resources was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2018 and 2019. As of December 31, 2019, Antero Resources had an outstanding balance under the Credit Facility of $552 million with a weighted average interest rate of 3.28%, and outstanding letters of credit of $623 million. As of December 31, 2018, Antero Resources had an outstanding balance under the Credit Facility of $405 million, with a weighted average interest rate of 3.95%, and outstanding letters of credit of $685 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) 0.300% to 0.375% (during any period that is not an Investment Grade Period) of the unused portion based on utilization and (ii) 0.150% to 0.300% (during an Investment Grade Period) of the unused portion based on Antero Resources’ credit rating. (b) 5.375% Senior Notes Due 2021 On November 5, 2013, Antero Resources issued $1 billion of 5.375% senior notes due November 1, 2021 (the “2021 notes”) at par . The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. Antero Resources may redeem all or part of the 2021 notes at any time at a redemption price of 100.00 %. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2021 notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued and unpaid interest. (c) 5.125% Senior Notes Due 2022 On May 6, 2014, Antero Resources issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 notes”) at par . On September 18, 2014, Antero Resources issued an additional $500 million of the 2022 notes at 100.5 % of par. The 2022 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2022 notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2022 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. Antero Resources may redeem all or part of the 2022 notes at any time at redemption prices ranging from 101.281% currently to 100.00 % on or after June 1, 2020. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2022 notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued and unpaid interest. (d) 5.625% Senior Notes Due 2023 On March 17, 2015, Antero Resources issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 notes”) at par . The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2023 notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2023 notes is payable on June 1 and December 1 of each year. Antero Resources may redeem all or part of the 2023 notes at any time at redemption prices ranging from on or after June 1, 2021. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2023 notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to (e) 5.00% Senior Notes Due 2025 On December 21, 2016, Antero Resources issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 notes”) at par . The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2025 notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2025 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ wholly owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2025 notes is payable on March 1 and September 1 of each year. Antero Resources may redeem all or part of the 2025 notes at any time on or after March 1, 2020 at redemption prices ranging from on or after March 1, 2023. In addition, on or before March 1, 2020, Antero Resources may redeem up to of the principal amount of the 2025 notes, plus accrued and unpaid interest. At any time prior to March 1, 2020, Antero Resources may also redeem the 2025 notes, in whole or in part, at a price equal to of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Resources undergoes a change of control followed by a rating decline, the holders of the 2025 notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to (f) Treasury Management Facility Antero Resources has a revolving note with a lender that is also part of the Credit Facility lending consortium that provides for up to $25 million of cash management obligations in order to facilitate Antero Resources’ daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the revolving note bear interest at the lender’s prime rate plus . The note matures on June 1, 2020. At December 31, 2018, there was (g) Debt Repurchase Program During the fourth quarter of 2019, we repurchased $225 million principal amount of debt at a 17% weighted average discount, including a portion of our 2021 notes and our 2022 notes. The Company recognized a gain of approximately million on the early extinguishment of the debt repurchased.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligations
Asset Retirement Obligations	(8) Asset Retirement Obligations The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 ​ 2019 ​ Asset retirement obligations—December 31, 2018 ​ $ 34,610 ​ ​ 58,979 ​ Obligations settled ​ ​ — ​ ​ (153) ​ Obligations incurred ​ 9,981 ​ ​ 2,312 ​ Revisions to prior estimates ​ ​ 11,569 ​ ​ (2,537) ​ Accretion expense ​ 2,819 ​ ​ 3,762 ​ Effect of deconsolidation of Antero Midstream Partners LP (1) ​ — ​ ​ (7,518) ​ Asset retirement obligations—December 31, 2019 ​ $ 58,979 ​ ​ 54,845 ​ (1) Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero Resources’ results. ​ Revisions to prior estimates in 2019 are primarily due to a decrease in well lives. Revisions to prior estimates in 2018 are primarily due to an increase in estimated abandonment costs for vertical wells. Asset retirement obligations are included in other liabilities on the Company’s consolidated balance sheets.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2019
Equity-Based Compensation
Equity-Based Compensation	(9) Equity-Based Compensation Antero Resources is authorized to grant up to 16,906,500 shares of common stock to employees and directors of the Company under the Antero Resources Corporation Long- Term Incentive Plan (the “Plan”). The Plan allows equity- based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero Resources’ Board of Directors. A total of 6,297,751 shares were available for future grant under the Plan as of December 31, 2019. In January 2020, a total of 4,644,934 shares were granted as restricted stock unit awards to employees and equity awards to directors. Antero Midstream Partner’s general partner was authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream Partners under the Antero Midstream Partners LP Long-Term Incentive Plan (the “AMP Plan”) to non-employee directors of its general partner and certain officers, employees, and consultants of Antero Midstream Partners and its affiliates (which include Antero Resources). As part of the Transactions, each outstanding phantom units awards under the AMP Plan was assumed by Antero Midstream Corporation and converted into 1.8926 restricted stock units under the Antero Midstream Corporation Long Term Incentive Plan (the “AMC Plan”). Each restricted stock unit award under the AMC Plan represents a right to receive one shares of Antero Midstream Corporation’s Common Stock, par value $0.01 per share (“Antero Midstream Corporation Common Stock”). The Company’s equity-based compensation expense, by type of award, was as follows for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ Restricted stock unit awards ​ $ 70,866 ​ ​ 41,505 ​ ​ 10,343 ​ Stock options ​ ​ 2,375 ​ ​ 1,799 ​ ​ 355 ​ Performance share unit awards ​ ​ 10,797 ​ ​ 9,659 ​ ​ 8,069 ​ Antero Midstream Partners phantom unit awards (1) ​ ​ 17,461 ​ ​ 15,351 ​ ​ 3,425 ​ Equity awards issued to directors ​ ​ 1,946 ​ ​ 2,100 ​ ​ 1,367 ​ Total expense ​ $ 103,445 ​ ​ 70,414 ​ ​ 23,559 ​ (1) Antero Resources recognized compensation expense for equity awards granted under both the Plan and the AMP Plan because the awards under the AMP Plan are accounted for as if they are distributed by Antero Midstream Partners to Antero Resources. Antero Resources allocates a portion of equity-based compensation expense related to grants prior to the Transactions to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. Through March 12, 2019, the total amount of equity-based compensation is included in the consolidated financial statements of Antero Resources; and effective March 13, 2019 (date of deconsolidation), the amount allocated to Antero Midstream Partners is no longer reflected in Antero Resources’ consolidated financial statements. See Note 3 to the consolidated financial statements for further discussion on the Transactions. ​ Restricted Stock Unit Awards Restricted stock unit awards vest subject to the satisfaction of service requirements. Expense related to each restricted stock unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero Resources’ common stock on the date of the grant. A summary of restricted stock unit award activity for the year ended December 31, 2019 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ Aggregate ​ ​ ​ Number of ​ grant date ​ intrinsic value ​ ​ shares fair value (in thousands) ​ Total awarded and unvested—December 31, 2018 1,712,485 ​ $ 24.57 ​ $ 16,080 ​ Granted 1,745,784 ​ $ 8.14 ​ ​ ​ ​ Vested (730,343) ​ $ 27.60 ​ ​ ​ ​ Forfeited (357,351) ​ $ 16.09 ​ ​ ​ ​ Total awarded and unvested—December 31, 2019 2,370,575 ​ $ 12.81 ​ $ 6,756 ​ ​ Intrinsic values are based on the closing price of Antero Resources’ common stock on the referenced dates. As of December 31, 2019, there was $21 million of unamortized equity-based compensation expense related to unvested restricted stock units. That expense is expected to be recognized over a weighted average period of approximately 2.4 years. Stock Options Stock options granted under the Plan have a maximum contractual life of 10 years . Expense related to stock options is recognized on a straight- line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Stock options were granted with an exercise price equal to or greater than the market price of Antero Resources’ common stock on the dates of grant. A summary of stock option activity for the year ended December 31, 2019 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ average ​ remaining ​ Intrinsic ​ ​ ​ Stock ​ exercise ​ contractual ​ value ​ ​ options price ​ life (in thousands) Outstanding at December 31, 2018 579,617 ​ $ 50.55 ​ 5.81 ​ $ — ​ Granted — ​ $ — ​ ​ ​ ​ ​ ​ Exercised — ​ $ — ​ ​ ​ ​ ​ ​ Forfeited (4,250) ​ $ 50.18 ​ ​ ​ ​ ​ ​ Expired/Cancelled (107,734) ​ $ — ​ ​ ​ ​ ​ ​ Outstanding at December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​ Vested or expected to vest as of December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​ Exercisable at December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​ ​ Intrinsic values are based on the exercise price of the options and the closing price of Antero Resources’ stock on the referenced dates. A Black-Scholes option- pricing model is used to determine the grant-date fair value of stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies’ stock prices as Antero Resources’ common stock had traded for a relatively short period of time at the dates the options were granted. The risk-free interest rate was determined using the implied yield available for zero- coupon U.S. government issues with a remaining term approximating the expected life of the options. A dividend yield of zero was assumed. As of December 31, 2019, all stock options were fully vested resulting in no unamortized equity-based compensation expense. Performance Share Unit Awards Performance Share Unit Awards Based on Stock Price Targets In 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers that are based on stock price targets. The vesting of these PSUs is conditioned on the closing price of Antero Resources’ common stock achieving specific price thresholds over 10 -day periods, subject to the following vesting restrictions: no PSUs may vest before the first anniversary of the grant date; no more than one-third of the PSUs may vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs may vest before the third anniversary of the grant date. Any PSUs which have not vested by the fifth anniversary of the grant date will expire. Expense related to these PSUs is recognized on a graded basis over three years . Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Performance Share Unit Awards Based on Total Shareholder Return (“TSR”) In 2016 and 2017, the Company granted PSUs to certain of its employees and executive officers that vest based on the TSR of Antero Resources’ common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of shares of common stock which may ultimately be earned ranges from zero to 200 % of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years . Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. In 2019, the Company granted PSUs to certain of its employees and executive officers that vest based on Antero Resources’ absolute TSR, with target payout achieved if the price per share of Antero Resources’ common stock reaches 125% of the beginning price (as defined in the award agreement) at the end of a three-year performance period. The number of shares of common stock which may ultimately be earned ranges from zero to 200 % of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years . Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Performance Share Unit Awards Based on TSR and Return on Capital Employed (“ROCE”) ​ In 2018, the Company granted PSUs to certain of its employees and executive officers, a portion of which vest based on the Company’s absolute TSR, with target payout achieved if the price per share of Antero Resources’ common stock reaches 125% of the beginning price (as defined in the award agreement) at the end of a three-year performance period (“TSR PSUs”). The number of awards actually earned with respect to the TSR PSUs will be subject to further adjustment based on the TSR of Antero Resources’ common stock relative to the TSR of a peer group of companies over the same period. The number of shares of common stock that may ultimately be earned with respect to the TSR PSUs ranges from zero to 200 % of the target number of TSR PSUs originally granted. Expense related to the TSR PSUs is recognized on a straight-line basis over three years . Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The other portion of the PSUs granted in 2018 vest based on the Company’s actual ROCE (as defined in the award agreement) over a three-year period as compared to a targeted ROCE (“ROCE PSUs”). The number of shares of common stock that may ultimately be earned with respect to the ROCE PSUs ranges from zero to 200 % of the target number of ROCE PSUs originally granted. Expense related to the ROCE PSUs is recognized based on the number of shares of common stock that are expected to be issued at the end of the measurement period, and is reversed if the likelihood of achieving the performance condition decreases. As of December 31, 2019, the likelihood of achieving the performance conditions related to the ROCE PSUs decreased to a level below probable and therefore, expense has not been recognized in the current quarter and will not be recognized unless the likelihood of achieving the performance condition becomes probable. Summary Information for Performance Share Unit Awards A summary of PSU activity for the year ended December 31, 2019 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average ​ ​ ​ Number of ​ grant date ​ ​ ​ units ​ fair value ​ Total awarded and unvested—December 31, 2018 1,767,299 ​ $ 26.36 ​ Granted 1,416,378 ​ $ 9.26 ​ Exercised ​ (31,944) ​ $ 27.38 ​ Cancelled - Unearned (326,938) ​ $ 32.97 ​ Forfeited (287,512) ​ $ 19.38 ​ Total awarded and unvested—December 31, 2019 2,537,283 ​ $ 16.74 ​ ​ The grant-date fair values of market-based PSUs were determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair values of the awards. Expected volatilities were derived from the volatility of the historical stock prices of a peer group of similar publicly-traded companies. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs. A dividend yield of zero was assumed. The grant-date fair value for the ROCE-based PSUs is based on the closing price of Antero Resources’ common stock on the date of the grant, assuming the achievement of the performance condition. The following table presents information regarding the weighted average fair values for market-based PSUs granted during the years ended December 31, 2018 and 2019, and the assumptions used to determine the fair values: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2018 ​ ​ 2019 ​ ​ Dividend yield ​ ​ — % ​ ​ — % ​ Volatility ​ ​ 41 % ​ ​ 36 % ​ Risk-free interest rate ​ ​ 2.49 % ​ ​ 2.35 % ​ Weighted average fair value of awards granted ​ $ 24.85 ​ ​ $ 9.26 ​ ​ ​ As of December 31, 2019, there was $17 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 1.8 years. Antero Midstream Partners Phantom Unit Awards and Antero Midstream Corporation Restricted Stock Unit Awards Phantom units granted by Antero Midstream Partners vested subject to the satisfaction of service requirements, upon the completion of which common units in Antero Midstream Partners were delivered to the holder of the phantom units. Phantom units also contained distribution equivalent rights which entitled the holder of vested common units to receive a “catch up” payment equal to common unit distributions paid by Antero Midstream Partners during the vesting period of the phantom unit award. These phantom units were treated, for accounting purposes, as if Antero Midstream Partners distributed the units to Antero Resources. Antero Resources recognized compensation expense as the units were granted to its employees, and a portion of the expense is allocated to Antero Midstream Partners. Expense related to each phantom unit award was recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards were determined based on the closing price of Antero Midstream Partners’ common units on the date of grant. In connection with the closing of the Transactions, the Board of Antero Midstream Corporation adopted the AMC Plan. In accordance with the terms of the Transactions, each outstanding phantom unit under the AMP Plan was assumed by Antero Midstream Corporation and converted into 1.8926 restricted stock units under the AMC Plan. A summary of phantom unit awards and Antero Midstream Corporation restricted stock unit awards resulting from the conversion activity for the year ended December 31, 2019 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ Aggregate ​ ​ ​ Number of ​ average grant ​ intrinsic value ​ ​ ​ units ​ date fair value ​ (in thousands) ​ Total awarded and unvested—December 31, 2018 583,000 ​ $ 27.63 ​ $ 12,470 ​ Granted 5,972 ​ $ 23.44 ​ ​ ​ ​ Vested (3,853) ​ $ 32.44 ​ ​ ​ ​ Forfeited (20,338) ​ $ 26.73 ​ ​ ​ ​ AMP Plan Units awarded and unvested—March 12, 2019 ​ 564,781 ​ $ 27.59 ​ $ 13,476 ​ Effect of conversion (1) 504,119 ​ $ 14.58 ​ ​ ​ ​ Vested (362,191) ​ $ 14.35 ​ ​ ​ ​ Forfeited (48,952) ​ $ 14.51 ​ ​ ​ ​ Total awarded and unvested—December 31, 2019 657,757 ​ $ 14.71 ​ $ 4,992 ​ (1) ​ Intrinsic values are based on the closing price of shares of Antero Midstream Corporation’s common stock or Antero Midstream Partners’ common units, as applicable, on the referenced dates. As of December 31, 2019, there was $6.0 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately 1.7 years.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2019
Financial Instruments
Financial Instruments	(10) Financial Instruments The carrying values of accounts receivable and accounts payable at December 31, 2018 and 2019 approximated market values because of their short- term nature. The carrying values of the amounts outstanding under the Credit Facility and Antero Midstream Partners’ credit facility at December 31, 2018 and the Credit Facility at December 31, 2019 approximated fair value because the variable interest rates are reflective of current market conditions. Based on Level 2 market data inputs, the fair value of senior notes was approximately $3.9 billion and $2.8 billion at December 31, 2018 and 2019, respectively. See Note 11 to the consolidated financial statements for information regarding the fair value of derivative financial instruments.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2019
Derivative Instruments.
Derivative Instruments	(11) Derivative Instruments (a) Commodity Derivative Positions The Company periodically enters into natural gas, NGLs, and oil derivative contracts with counterparties to hedge the price risk associated with its production. These derivatives are not entered into for trading purposes. To the extent that changes occur in the market prices of natural gas, NGLs, and oil, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas, NGLs, and oil recognized upon the ultimate sale of the Company’s production. The Company was party to various fixed price commodity swap contracts that settled during the years ended December 31, 2017, 2018 and 2019. The Company enters into these swap contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price. The Company also entered into NGL derivative contracts, which establish a contractual price for the settlement month as a fixed percentage of the West Texas Intermediate Crude Oil index (“WTI”) price for the settlement month. When the percentage of the contractual price is above the contracted percentage, the Company pays the difference to the counterparty. When it is below the contracted percentage, the Company receives the difference from the counterparty. In addition, the Company has historically also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. Under these contracts, the Company pays the difference between the ceiling price and the published index price in the event the published index price is above the ceiling price. When the published index price is below the floor price, the Company receives the difference between the floor price and the published index price. No amounts are paid or received if the index price is between the floor and the ceiling prices. The index prices in our collars are consistent with the index prices used to sell our production. The Company’s derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s statements of operations. As of December 31, 2019, the Company’s fixed price natural gas, oil and NGL swap positions from January 1, 2020 through December 31, 2023 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: NYMEX = Henry Hub; ARA Propane = European Propane CIF ARA; FEI Propane = Propane Far East Asia Index; Mont Belvieu Butane Non-TET = Mont Belvieu Butane; Mont Belvieu Propane Non-TET = Mont Belvieu Propane; NYMEX-WTI = West Texas Intermediate): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural ​ ​ ​ ​ Weighted ​ ​ ​ Natural gas ​ ​ Gas Liquids ​ ​ Oil ​ average index ​ ​ ​ MMBtu/day ​ ​ Bbls/day ​ ​ Bbls/day ​ price ​ Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FEI Propane ($/Gal) ​ — ​ ​ 9,883 ​ ​ — ​ $ 0.81 ​ Mont Belvieu Butane Non-TET ($/Gal) ​ — ​ ​ 6,000 ​ ​ — ​ ​ 0.50 ​ Mont Belvieu Propane Non-TET ($/Gal) ​ — ​ ​ 1,500 ​ ​ — ​ ​ 0.58 ​ Total ​ — ​ ​ 17,383 ​ ​ — ​ ​ ​ ​ Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 2,227,500 ​ ​ — ​ ​ — ​ $ 2.87 ​ ARA Propane ($/Gal) ​ — ​ ​ 10,371 ​ ​ — ​ ​ 0.65 ​ NYMEX-WTI ($/Bbl) ​ — ​ ​ — ​ ​ 26,000 ​ ​ 55.63 ​ Total ​ 2,227,500 ​ ​ 10,371 ​ ​ 26,000 ​ ​ ​ ​ Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 2,400,000 ​ ​ ​ ​ ​ ​ ​ $ 2.80 ​ Year ending December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 90,000 ​ ​ ​ ​ ​ ​ ​ $ 2.91 ​ ​ As of December 31, 2019, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of the Columbia Gas Transmission pipeline (“TCO”) to the NYMEX Henry Hub natural gas price, and NGL basis swap positions, which settle on the pricing index to basis differential of Mont Belvieu Butane to the European Butane CIF ARA natural gas liquids price, were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Weighted ​ ​ Natural Gas ​ Liquids ​ average hedged ​ ​ MMBtu/day ​ Bbls/day ​ differential Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ ​ ARA to Mont Belvieu Non-TET ($/Gal) ​ ​ ​ 2,670 ​ $ 0.24 Three months ending June 30, 2020: ​ ​ ​ ​ ​ ​ ​ ARA to Mont Belvieu Non-TET ($/Gal) ​ ​ ​ 1,602 ​ $ 0.22 Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 60,000 ​ ​ ​ $ 0.35 Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 40,000 ​ — ​ $ 0.41 Year ending December 31, 2022: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 60,000 ​ — ​ $ 0.52 Year ending December 31, 2023: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 50,000 ​ — ​ $ 0.53 Year ending December 31, 2024: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 50,000 ​ — ​ $ 0.53 ​ As of December 31, 2019, the Company had natural gas and NGL contracts for January 1, 2020 through December 31, 2021 that fix the Mont Belvieu index price to percentages of WTI as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Weighted ​ ​ ​ ​ Liquids ​ average payout ​ ​ ​ ​ Bbls/day ​ ratio ​ ​ Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ Mont Belvieu Propane to NYMEX-WTI ​ 500 ​ 50% ​ ​ Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ Mont Belvieu Natural Gasoline to NYMEX-WTI ​ 18,800 ​ 80% ​ ​ Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ Mont Belvieu Natural Gasoline to NYMEX-WTI ​ 18,650 ​ 78% ​ ​ ​ (b) Marketing Derivatives In 2017, due to delay of the in-service date for a pipeline on which the Company is to be an anchor shipper, the Company realized it would not be able to fulfill its delivery obligations under a 2018 natural gas sales contract. In order to acquire gas to fulfill its delivery obligations, the Company entered into several natural gas purchase agreements with index-based pricing to purchase gas for resale under this sales contract. Subsequently, the Company and the counterparty to the sales contract came to an agreement that the Company’s delivery obligations under the contract would not begin until the earlier of (1) the in-service date of the pipeline and (2) January 1, 2019. Consequently, in December 2017, the Company entered into natural gas sales agreements with index-based pricing to resell the purchased gas for delivery during the period from February to October 2018. The natural gas that it had purchased for January was sold on the spot market during January 2018. The Company determined that these gas purchase and sales agreements should be accounted for as derivatives and measured at fair value at the end of each period. The Company recognized a fair value loss for the year ended December 31, 2017 of $21 million. For the year ended December 31, 2018, the Company recognized a fair value gain of $94 million and realized proceeds of $73 million. There were no marketing derivative fair value gains or losses for the year ended December 31, 2019. ​ (c) Summary The following table presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets as of December 31, 2018 and 2019. None ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ December 31, 2019 ​ ​ ​ Balance sheet ​ ​ ​ Balance sheet ​ ​ ​ ​ ​ location ​ Fair value ​ location ​ Fair value ​ ​ ​ ​ ​ (In thousands) ​ ​ ​ (In thousands) ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives - current ​ Derivative instruments ​ $ 245,263 ​ Derivative instruments ​ $ 422,849 ​ Commodity derivatives - noncurrent ​ Derivative instruments ​ ​ 362,169 ​ Derivative instruments ​ ​ 333,174 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives ​ ​ ​ ​ 607,432 ​ ​ ​ ​ 756,023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives - current ​ Derivative instruments ​ ​ 532 ​ Derivative instruments ​ ​ 6,721 ​ Commodity derivatives - noncurrent ​ Derivative instruments ​ ​ — ​ Derivative instruments ​ ​ 3,519 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives ​ ​ ​ ​ 532 ​ ​ ​ ​ 10,240 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives ​ ​ ​ $ 606,900 ​ ​ ​ $ 745,783 ​ ​ ​ The following table presents the gross values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ December 31, 2019 ​ ​ ​ ​ ​ ​ ​ Net amounts ​ ​ ​ ​ ​ Net amounts ​ ​ Gross ​ Gross ​ of assets ​ Gross ​ Gross ​ of assets ​ ​ ​ amounts on ​ amounts offset on ​ (liabilities) on ​ amounts on ​ amounts offset on ​ (liabilities) on ​ ​ ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet Commodity derivative assets ​ $ 658,830 ​ (51,398) ​ 607,432 ​ $ 882,817 ​ (126,794) ​ 756,023 ​ Commodity derivative liabilities ​ $ (51,930) ​ 51,398 ​ (532) ​ $ (137,034) ​ 126,794 ​ (10,240) ​ ​ The following is a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ operations ​ Year ended December 31, ​ ​ ​ location ​ 2017 ​ 2018 ​ 2019 ​ Commodity derivative fair value gains (losses) ​ Revenue ​ $ 658,283 ​ ​ (87,594) ​ ​ 463,972 ​ Marketing derivative fair value gains (losses) ​ Revenue ​ $ (21,394) ​ ​ 94,081 ​ ​ — ​ ​ Commodity derivative fair value gains (losses) for the years ended December 31, 2017 and 2018, include gains of $750 million and $370 million, respectively, related to certain natural gas derivatives that were monetized prior to their contractual settlement dates. Proceeds received from the monetizations are classified as operating cash flows on the Company’s consolidated statement of cash flows for the years ended December 31, 2017 and 2018. There were no commodity derivatives monetizations in the year ended December 31, 2019. The 2017 monetizations were effected by reducing the average fixed index prices on certain natural gas swap contracts maturing from 2018 through 2022 while maintaining the total volumes hedged. The 2018 monetizations were affected by the early settlement of April through December 2019 swaps and reducing the average fixed index prices on certain natural gas swap contracts maturing in 2020 while maintaining the total volumes hedged. The April through December 2019 swaps were replaced with collar agreements for which the Company paid a $13 million premium. The Company’s commodity derivative position presented in Note 11(a) reflects the volume and adjusted fixed price indices after the monetization. The fair value of derivative instruments was determined using Level 2 inputs.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases
Leases	(12) Leases On February 25, 2016, the FASB issued ASU No. 2016-02, Leases The Company is a lessee to both operating and finance lease arrangements. The standard resulted in an increase in assets and liabilities related to our operating leases. The Company leases certain office space, processing plants, drilling rigs and completion services, gas gathering lines, compressor stations, and other office and field equipment. Leases with an initial term of 12 months or less are considered short-term and are not recorded on the balance sheet. Instead, the short-term leases are recognized in expense on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease from one or more. The exercise of the lease renewal options are at the Company’s sole discretion. The depreciable lives of the leased assets are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. Certain of the Company’s lease agreements include minimum payments based on a percentage of produced volumes over contractual levels and others include rental payments adjusted periodically for inflation. The Company has elected the effective date method for adoption of the new leasing standard under Topic 842. This method allows the Company to not make retrospective adjustments for leases that were in effect prior to the adoption date of January 1, 2019 when disclosing comparable prior periods, but instead, account for the prior period leases under Topic 840, which was the guidance in place at the time of the original reporting. The Company considers all contracts that have assets specified in the contract, either explicitly or implicitly, that the Company has substantially all of the capacity of the asset, and has the right to obtain substantially all of the economic benefits of that asset, without the lessor’s ability to have a substantive right to substitute that asset, as leased assets under Topic 842. For any contract deemed to include a leased asset, that asset is capitalized on the balance sheet as a right-of-use asset and a corresponding lease liability is recorded at the present value of the known future minimum payments of the contract using a discount rate on the date of commencement. The leased asset classification is determined at the date of recording as either operating or financing, depending upon certain criteria of the contract. The discount rate used for present value calculations is the discount rate implicit in the contract. If an implicit rate is not determinable, a collateralized incremental borrowing rate is used at the date of commencement. The Company used the collateralized incremental borrowing rate, adjusted for length of lease term, for all of its present value calculations at the initial adoption of Topic 842. Additionally, as new leases commence or previous leases are modified the discount rate used in the present value calculation is the current period applicable discount rate. The Company has made an accounting policy election to adopt the practical expedient for combining lease and non-lease components on an asset class basis. This expedient allows the Company to combine non-lease components such as real estate taxes, insurance, maintenance, and other operating expenses associated with the leased premises with the lease component of a lease agreement on an asset class basis when the non-lease components of the agreement cannot be easily bifurcated from the lease payment. Currently, the Company is only applying this expedient to certain office space agreements. Supplemental Balance Sheet Information Related to Leases ​ The Company’s lease assets as of December 31, 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Right-of-use Assets: ​ ​ ​ ​ ​ ​ ​ Processing plants ​ $ 1,460,770 ​ ​ — ​ Drilling rigs and completion services ​ ​ 71,662 ​ ​ — ​ Gas gathering lines and compressor stations (1) ​ ​ 1,308,428 ​ ​ — ​ Office space ​ ​ 40,491 ​ ​ — ​ Vehicles ​ ​ 4,983 ​ ​ 2,328 ​ Other office and field equipment ​ ​ 166 ​ ​ 170 ​ Total right-of-use assets ​ $ 2,886,500 ​ ​ 2,498 (2) (1) (2) ​ The Company’s lease liabilities as of December 31, 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Location on the balance sheet: ​ ​ ​ ​ ​ ​ ​ Short-term lease ​ $ 304,398 ​ ​ 923 ​ Long-term lease ​ ​ 2,582,102 ​ ​ 1,575 ​ Total lease ​ $ 2,886,500 ​ ​ 2,498 ​ ​ The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC 842 because the Company is the sole customer of the assets and because the Company makes the decisions that most impact the economic performance of the assets. Supplemental Information Related to Leases Costs associated with operating leases were included in the statement of operations and comprehensive income (loss) for the year ended December 31, 2019 (in thousands): ​ ​ ​ ​ ​ Statement of Operations Location ​ Year ended December 31, 2019 ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ General and administrative ​ ​ 11,228 ​ Contract termination and rig stacking ​ ​ 10,692 ​ Total Lease Expense ​ $ 864,360 ​ ​ Costs associated with finance leases of less than $1 million for the year ended December 31, 2019. We capitalized Short-term lease costs that are more than one month but less than 12 months are excluded from the above amounts and total $163 million at December 31, 2019. Supplemental Cash Flow Information Related to Leases The following is the Company’s supplemental cash flow information related to leases for year ended December 31, 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ Operating cash out flows related to operating leases ​ $ 809,667 ​ ​ — ​ Investing cash out flows related to operating leases ​ ​ 178,898 ​ ​ — ​ Financing cash out flows related to financing leases ​ ​ — ​ ​ 2,507 ​ ​ ​ $ 988,565 ​ ​ 2,507 ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ Right of use assets obtained in exchange for operating lease liabilities ​ $ 3,720,945 ​ ​ — ​ Right of use assets obtained in exchange for financing lease liabilities ​ $ — ​ ​ — ​ ​ Maturities of Lease Liabilities The table below is a schedule of future minimum payments for operating and financing lease liabilities as of December 31, 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2020 ​ $ 622,056 ​ ​ 244 ​ ​ 622,300 ​ 2021 ​ ​ 554,000 ​ ​ 1,007 ​ ​ 555,007 ​ 2022 ​ ​ 542,952 ​ ​ 1,205 ​ ​ 544,157 ​ 2023 ​ ​ 538,771 ​ ​ 42 ​ ​ 538,813 ​ 2024 ​ ​ 530,003 ​ ​ — ​ ​ 530,003 ​ Thereafter ​ ​ 1,851,738 ​ ​ — ​ ​ 1,851,738 ​ Total lease payments ​ ​ 4,639,520 ​ ​ 2,498 ​ ​ 4,642,018 ​ Less: imputed interest ​ ​ (1,753,020) ​ ​ — ​ ​ (1,753,020) ​ Total ​ $ 2,886,500 ​ ​ 2,498 ​ ​ 2,888,998 ​ ​ As of December 31, 2019, the following future minimum payments were required for office and equipment leases: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Office Leases ​ Equipment Leases ​ Total ​ 2020 ​ $ 6,145 ​ ​ 3,916 ​ ​ 10,061 ​ 2021 ​ ​ 6,071 ​ ​ 2,931 ​ ​ 9,002 ​ 2022 ​ ​ 6,027 ​ ​ 1,205 ​ ​ 7,232 ​ 2023 ​ ​ 4,761 ​ ​ 42 ​ ​ 4,803 ​ 2024 ​ ​ 4,792 ​ ​ — ​ ​ 4,792 ​ Thereafter ​ ​ 27,258 ​ ​ — ​ ​ 27,258 ​ Total lease payments ​ ​ 55,054 ​ ​ 8,094 ​ ​ 63,148 ​ Less: imputed interest ​ ​ (14,562) ​ ​ (447) ​ ​ (15,009) ​ Total ​ $ 40,492 ​ ​ 7,647 ​ ​ 48,139 ​ ​ Lease Term and Discount Rate The table below is the Company’s weighted-average remaining lease term and discount rate as of December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Weighted-average remaining lease term: ​ ​ 8.7 years ​ ​ 2.1 years ​ Weighted-average discount rate: ​ ​ 11.5 % ​ 6.0 % ​ As of December 31, 2019, the Company had requested additional processing capacity that will be accounted for as lease modifications when the processing capacity becomes available in 2020. Related party lease disclosure The Company has a gathering and compression agreement with Antero Midstream Corporation, whereby Antero Midstream Corporation receives a low-pressure gathering fee per Mcf, a high-pressure gathering fee per Mcf, and a compression fee per Mcf, in each case subject to adjustments based on the consumer price index. If and to the extent we request that Antero Midstream Corporation construct new high pressure lines and compressor stations, the gathering and compression agreement contains minimum volume commitments that require Antero Resources to utilize or pay for . For the year ended December 31, 2019, gathering and compression fees paid by Antero Resources related to this agreement were million. As of December 31, 2019,

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Taxes
Income Taxes	(13) Income Taxes For the years ended December 31, 2017, 2018 and 2019, income tax expense (benefit) consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ 2017 2018 2019 Current income tax expense (benefit) ​ $ 75 ​ ​ — ​ ​ 5,048 ​ Deferred income tax benefit ​ (295,126) ​ (128,857) ​ (79,158) ​ Total income tax benefit ​ $ (295,051) ​ ​ (128,857) ​ ​ (74,110) ​ ​ Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to the year ended December 31, 2017 and 21% to the years ended December 31, 2018 and 2019 to income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ 2017 2018 2019 Federal income tax expense (benefit) ​ $ 171,530 ​ ​ (36,657) ​ ​ (77,122) ​ State income tax expense (benefit), net of federal benefit ​ 10,779 ​ (12,627) ​ (8,826) ​ Change in Federal tax rate, net of state benefit (1) ​ ​ (427,962) ​ ​ — ​ ​ — ​ Change in State tax rate, net of federal effect ​ ​ — ​ ​ (40,415) ​ ​ 24,041 ​ Nondeductible equity-based compensation ​ 12,098 ​ 6,079 ​ 6,920 ​ Dividends received deduction ​ ​ — ​ ​ — ​ ​ (4,201) ​ Noncontrolling interest in Antero Midstream Partners ​ ​ (59,523) ​ ​ (73,881) ​ ​ (10,998) ​ Deconsolidation adjustment ​ ​ — ​ ​ — ​ ​ (6,626) ​ Change in valuation allowance ​ (2,073) ​ 28,116 ​ 1,325 ​ Other ​ 100 ​ 528 ​ 1,377 ​ Total income tax benefit ​ $ (295,051) ​ ​ (128,857) ​ ​ (74,110) ​ (1) The change in the Federal tax rate was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. The passage of this legislation resulted in the Company generating a deferred tax benefit in 2017 primarily due to the reduction in the U.S. statutory rate from 35% to 21% . ​ Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2018 and 2019 is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2019 Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ Net operating loss carryforwards ​ $ 734,255 ​ ​ 560,136 ​ Equity-based compensation ​ ​ 10,633 ​ ​ 7,669 ​ Investment in Antero Midstream ​ ​ — ​ ​ 172,460 ​ Other ​ ​ 15,726 ​ ​ 15,754 ​ Total deferred tax assets ​ ​ 760,614 ​ ​ 756,019 ​ Valuation allowance ​ ​ (45,477) ​ ​ (46,802) ​ Net deferred tax assets ​ ​ 715,137 ​ ​ 709,217 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 271,747 ​ ​ 206,677 ​ Oil and gas properties ​ ​ 1,055,850 ​ ​ 1,284,528 ​ Investment in Antero Midstream Partners ​ ​ 11,258 ​ ​ — ​ Other ​ ​ 27,070 ​ ​ — ​ Total deferred tax liabilities ​ ​ 1,365,925 ​ ​ 1,491,205 ​ Net deferred tax liabilities ​ $ (650,788) ​ ​ (781,987) ​ ​ In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the projections of future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of certain of these deductible differences and has recorded a valuation allowance of approximately $45 million and 31, 2018 and 2019, respectively, related to state net operating loss (“NOL”) carryforwards. The increase in the valuation allowance from $45 million at December 31, 2018 to $47 million at December 31, 2019, is due to an increase in Colorado NOLs, resulting from tax return amendments, against which a full valuation allowance has been previously established. The amount of the deferred tax asset considered realizable could be further reduced in the near term if estimates of future taxable income during the carryforward period are revised. The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than- not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The Company monitors potential uncertain tax positions but does not anticipate any changes within the next year. The Company has no unrecognized tax benefit balances through December 31, 2019. As of December 31, 2019, the Company has U.S. federal and state NOL carryforwards of $2.2 billion and $2.0 billion, respectively. The federal, Colorado, and West Virginia NOL carryforwards generated in tax years prior to 2018 expire between 2032 and 2037. The 2018 NOL carryforwards generated in these jurisdictions have no expiration date. The Pennsylvania NOL carryforwards expire between 2037 and 2038. Tax years 2016 through 2019 remain open to examination by the U.S. Internal Revenue Service. The Company and its subsidiaries file tax returns with various state taxing authorities and those returns remain open to examination for tax years 2015 through 2019.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2019
Commitments
Commitments	(14) Commitments The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, which include leases that have remaining lease terms in excess of one year as of December 31, 2019 (in thousands). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Firm ​ gathering and ​ Land payment ​ Operating and ​ Imputed Interest ​ ​ ​ ​ ​ transportation ​ compression ​ obligations ​ Financing Leases ​ for Leases ​ ​ ​ ​ ​ (a) ​ (b) ​ (c) ​ (d) ​ (d) ​ Total ​ 2020 ​ $ 1,105,062 ​ ​ 55,338 ​ ​ 5,240 ​ ​ 304,441 ​ ​ 317,859 ​ ​ 1,787,940 ​ 2021 ​ ​ 1,076,832 ​ ​ 54,154 ​ ​ 2,859 ​ ​ 265,838 ​ ​ 289,169 ​ ​ 1,688,852 ​ 2022 ​ ​ 1,034,009 ​ ​ 53,606 ​ ​ 328 ​ ​ 285,209 ​ ​ 258,948 ​ ​ 1,632,100 ​ 2023 ​ ​ 1,056,902 ​ ​ 58,565 ​ ​ — ​ ​ 313,510 ​ ​ 225,303 ​ ​ 1,654,280 ​ 2024 ​ ​ 1,016,856 ​ ​ 58,687 ​ ​ — ​ ​ 342,348 ​ ​ 187,655 ​ ​ 1,605,546 ​ Thereafter ​ ​ 7,907,583 ​ ​ 152,523 ​ ​ — ​ ​ 1,377,652 ​ ​ 474,086 ​ ​ 9,911,844 ​ Total ​ $ 13,197,244 ​ ​ 432,873 ​ ​ 8,427 ​ ​ 2,888,998 ​ ​ 1,753,020 ​ ​ 18,280,562 ​ ​ (a) Firm Transportation The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of its production to market. These contracts commit the Company to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates. The amounts in this table are based on the Company’s minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. (b) Processing, Gathering, and Compression Service Commitments The Company has entered into various long term gas processing, gathering and compression service agreements. Certain of these agreements were determined to be leases. The minimum payment obligations under the agreements that are not leases are presented in this column. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. (c) Land Payment Obligations The Company has entered into various land acquisition agreements. Certain of these agreements contain minimum payment obligations over various terms. The values in the table represent the minimum payments due under these arrangements. None of these agreements were determined to be leases. (d) Leases, including imputed interest The Company has obligations under contracts for services provided by drilling rigs and completion fleets, processing, gathering, and compression services agreements, and office and equipment leases. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests. Refer to Note 12 to the consolidated financial statements for more information on the Company’s operating and finance leases.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2019
Contingencies
Contingencies	(15) Contingencies Environmental In June 2018, following site inspections conducted in September 2017 at certain of our facilities located in Doddridge County, Tyler County, and Ritchie County, West Virginia, we received a Notice of Violation (“NOV”) from the U.S. Environmental Protection Agency (“EPA”) Region III for alleged violations of the federal Clean Air Act and the West Virginia State Implementation Plan relating to permitting and control requirements for emissions of regulated pollutants at several of our natural gas production facilities. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, we received an information request from EPA Region III pursuant to Section 114(a) of the Clean Air Act relating to the facilities that were inspected in September 2017 as well as additional Antero Resources facilities for the purpose of determining if the additional facilities have the same alleged compliance issues that were identified during the September 2017 inspections. We have separately received an NOV from West Virginia Department of Environmental Protection (“WVDEP”) alleging violations relating to the same issues being investigated by the EPA. We continue to negotiate with EPA and WVDEP to resolve the issues alleged in the NOVs and the information request; however, we believe that there is a reasonable possibility that these actions may result in monetary sanctions exceeding $100,000 . Our operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows. SJGC In March 2015 and December 2017, the Company filed lawsuits against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) in United States District Court in Colorado seeking relief for breach of contracts and damages for amounts that SJGC short paid the Company. The contractual price for gas was based on specified indices in the contracts and SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero Resources’ positions in the initial lawsuit against SJGC and the Tenth Circuit Court of Appeals affirmed the judgment of the trial court. SJGC declined further appeal and stipulated to the liability in the second suit. During the year ended December 31, 2019, the Company and our royalty owners received a gross settlement of $82 million from SJGC, which was in full satisfaction and discharge of judgments entered in favor of the Company in the above described lawsuits. WGL The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017 and from December 2017 through January 2018, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day from August through November 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017. In March of 2017, WGL filed a second legal proceeding against the Company in Colorado district court alleging breach of contract and seeking damages of more than $30 million. In this lawsuit, WGL claimed that the Company breached its contractual obligations under the Contracts by failing to deliver “TCO pool” gas. In subsequent filings, WGL explained that its claims were based on an alleged obligation that the Company must deliver gas to the Columbia IPP Pool (“IPP Pool”). WGL asserted this exact same issue in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific geographic point in Braxton County, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its new lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court dismissed WGL’s lawsuit because WGL had not adequately pled a claim against Antero Resources for the alleged failure to deliver “TCO pool” gas under the Contracts. WGL has appealed this decision to the Colorado Court of Appeals and on October 11, 2018 the Colorado Court of Appeals reversed the Colorado district court’s decision finding that WGL had adequately pled a claim for relief and remanded the case back to the district court for further proceedings. The Company is also actively engaged in pursuing cover damages against WGL based on WGL’s failure to take receipt of all of the agreed quantities of gas required under the Contracts. WGL’s failure to take the gas volumes specified in the Contracts is directly related to WGL’s lack of primary firm transportation rights at the Delivery Point. The failures by WGL to take the full contracted volumes of gas began in April 2017 and continued each month through December 2017 in varying quantities. In defense of its conduct, WGL asserted to the Company that their failure to receive gas is excused by (1) the Company’s failure to deliver gas to the IPP Pool or (2) alleged instances of Force Majeure under the Contracts. However, as stated above, the alleged obligation that the Company must deliver gas to the IPP Pool was already rejected by the arbitration panel. Further, the Contracts expressly prohibit a Force Majeure claim in circumstances in which the gas purchaser does not have primary firm transportation agreements in place to transport the purchased gas. In each instance that WGL failed to receive the quantity of gas required under the Contracts, the Company resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL refused to pay for the invoiced cover damages as required by the Contracts and also short paid the Company for, among other things, certain amounts of gas received by WGL. The Company filed a lawsuit against WGL in Colorado district court on October 24, 2017 to recover its cover damages, other unpaid amounts, and interest. WGL’s claims have been consolidated with Antero Resources’ claims in the same district court and trial began on June 10, 2019. WGL quantified its damages claim for the alleged failure to deliver TCO Pool gas and sought approximately $40 million from Antero Resources. On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages after the jury found that WGL breached the Contracts with the Company. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts by allegedly failing to deliver TCO Pool gas and awarding no damages in favor of WGL. On August 16, 2019, WGL filed a notice of appeal of the judgment. Effective February 1, 2018, as a result of a recent amendment to its firm gas sales contract with WGL Midstream, Inc. that was executed on December 28, 2017, the total aggregate volumes to be delivered to WGL at the Braxton delivery point were reduced from 500,000 MMBtu/day to 200,000 MMBtu/day and in November 2018, the total aggregate contract volumes to be delivered to WGL at a delivery point in Loudoun County, Virginia increased by 330,000 MMBtu/day. This increase of 330,000 MMBtu/day is in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes are subject to NYMEX-based pricing. Following this increase, the aggregate contract volumes delivered to WGL total 530,000 MMBtu/day. Other The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

Contract Termination and Rig St

Contract Termination and Rig Stacking	12 Months Ended
	Dec. 31, 2019
Contract Termination and Rig Stacking
Contract Termination and Rig Stacking	(16) Contract Termination and Rig Stacking During the year ended December 31, 2019, the Company incurred $14 million of costs for the delay or cancellation of drilling and completion contracts with third-party contractors.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2019
Related Parties
Related Parties	(17) Related Parties Antero Midstream Partners’ operations comprised substantially all of the operations reflected in the gathering and processing, and water handling and treatment, results through March 12, 2019. Effective March 13, 2019, Antero Resources accounts for Antero Midstream Corporation as an equity method investment. See Note 3 to the consolidated financial statements for more discussion on the Transactions. Substantially all of the revenues for Antero Midstream Partners or Antero Midstream Corporation were and are derived from transactions with Antero Resources. See Note 18 to the consolidated financial statements for the operating results of the Company’s reportable segments.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2019
Segment Information
Segment Information	(18) Segment Information See Note 2(t) to the consolidated financial statements for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations were primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations prior to the closing of the Transactions. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero Resources. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero Resources’ result; however, the Company’s segment disclosures include the results of our unconsolidated affiliates due to their significance to the Company’s operations. See Note 3 to the consolidated financial statements for further discussion on the Transactions. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. Operating segments are evaluated based on their contribution to consolidated results, which is primarily determined by the respective operating income (loss) of each segment. General and administrative expenses were allocated to the midstream segment based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures, and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes, and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales were transacted at prices which approximate market. Accounting policies for each segment are the same as the Company’s accounting policies described in Note 2 to the consolidated financial statements. The operating results and assets of the Company’s reportable segments were as follows for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ and ​ ​ ​ ​ ​ intersegment ​ Consolidated ​ ​ production ​ Marketing ​ Midstream ​ transactions ​ total Year ended December 31, 2017: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,406,203 ​ ​ 236,651 ​ ​ 12,720 ​ ​ — ​ 3,655,574 ​ Intersegment ​ 17,358 ​ ​ — ​ ​ 759,777 ​ ​ (777,135) ​ — ​ Total ​ $ 3,423,561 ​ 236,651 ​ 772,497 ​ (777,135) ​ 3,655,574 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 93,758 ​ ​ — ​ ​ 189,702 ​ ​ (194,403) ​ ​ 89,057 ​ Gathering, compression, processing, and transportation ​ ​ 1,441,129 ​ ​ — ​ ​ 39,147 ​ ​ (384,637) ​ 1,095,639 ​ Impairment of oil and gas properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Depletion, depreciation, and amortization ​ ​ 704,152 ​ ​ — ​ ​ 120,458 ​ ​ — ​ 824,610 ​ General and administrative ​ ​ 195,153 ​ ​ — ​ ​ 58,812 ​ ​ (2,769) ​ ​ 251,196 ​ Other ​ ​ 101,980 ​ ​ 366,281 ​ ​ 17,165 ​ ​ (13,476) ​ ​ 471,950 ​ Total ​ ​ 2,695,770 ​ ​ 366,281 ​ ​ 448,715 ​ ​ (595,285) ​ ​ 2,915,481 ​ Operating income (loss) ​ $ 727,791 ​ (129,630) ​ 323,782 ​ (181,850) ​ ​ 740,093 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 20,194 ​ ​ — ​ ​ 20,194 ​ Segment assets ​ $ 13,074,027 ​ ​ 36,701 ​ ​ 3,057,459 ​ ​ (906,697) ​ ​ 15,261,490 ​ Capital expenditures for segment assets ​ $ 1,859,481 ​ ​ — ​ ​ 540,719 ​ ​ (183,447) ​ ​ 2,216,753 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ ​ ​ intersegment ​ Consolidated ​ ​ production ​ Marketing ​ Midstream ​ transactions ​ total ​ Year ended December 31, 2018: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,565,300 ​ ​ 552,982 ​ ​ 21,344 ​ ​ — ​ 4,139,626 ​ Intersegment ​ (87,472) ​ ​ — ​ ​ 1,007,178 ​ ​ (919,706) ​ — ​ Total ​ $ 3,477,828 ​ 552,982 ​ 1,028,522 ​ (919,706) ​ 4,139,626 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 142,234 ​ ​ — ​ ​ 262,704 ​ ​ (268,785) ​ ​ 136,153 ​ Gathering, compression, processing, and transportation ​ ​ 1,792,898 ​ ​ — ​ ​ 49,550 ​ ​ (503,090) ​ 1,339,358 ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 9,658 ​ ​ — ​ ​ 9,658 ​ Depletion, depreciation, and amortization ​ ​ 841,645 ​ ​ — ​ ​ 130,820 ​ ​ — ​ 972,465 ​ General and administrative ​ ​ 181,305 ​ ​ — ​ ​ 61,629 ​ ​ (2,590) ​ ​ 240,344 ​ Other ​ ​ 129,947 ​ ​ 686,055 ​ ​ (88,715) ​ ​ 93,019 ​ ​ 820,306 ​ Total ​ ​ 3,637,466 ​ ​ 686,055 ​ ​ 425,646 ​ ​ (681,446) ​ ​ 4,067,721 ​ Operating income (loss) ​ $ (159,638) ​ (133,073) ​ 602,876 ​ (238,260) ​ ​ 71,905 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 40,280 ​ ​ — ​ ​ 40,280 ​ Segment assets ​ $ 12,986,945 ​ ​ 34,499 ​ ​ 3,542,862 ​ ​ (1,044,842) ​ ​ 15,519,464 ​ Capital expenditures for segment assets ​ $ 1,923,488 ​ ​ — ​ ​ 542,112 ​ ​ (255,014) ​ ​ 2,210,586 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ intersegment ​ ​ ​ ​ ​ ​ ​ ​ ​ Antero ​ transactions and ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ Midstream ​ unconsolidated ​ Consolidated ​ ​ and production ​ Marketing ​ Corporation ​ affiliates ​ total Year ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,107,845 ​ ​ 292,207 ​ ​ 50 ​ ​ — ​ 4,400,102 Intersegment ​ 5,812 ​ ​ — ​ ​ 792,538 ​ ​ (789,762) ​ 8,588 Total ​ $ 4,113,657 ​ 292,207 ​ 792,588 ​ (789,762) ​ 4,408,690 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 146,990 ​ ​ — ​ ​ 162,376 ​ ​ (163,646) ​ ​ 145,720 Gathering, compression, processing, and transportation ​ ​ 2,257,099 ​ ​ — ​ ​ 41,013 ​ ​ (151,465) ​ 2,146,647 Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 776,832 ​ ​ (762,050) ​ ​ 14,782 Depletion, depreciation, and amortization ​ ​ 893,161 ​ ​ — ​ ​ 95,526 ​ ​ (73,820) ​ 914,867 General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 118,113 ​ ​ (99,819) ​ ​ 178,696 Other ​ ​ 143,762 ​ ​ 549,814 ​ ​ 12,093 ​ ​ (11,090) ​ ​ 694,579 Total ​ ​ 4,901,858 ​ ​ 549,814 ​ ​ 1,205,953 ​ ​ (1,261,890) ​ ​ 5,395,735 Operating income (loss) ​ $ (788,201) ​ (257,607) ​ (413,365) ​ 472,128 ​ ​ (987,045) Equity in earnings (loss) of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 51,315 ​ ​ (194,531) ​ ​ (143,216) Investments in unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 709,639 ​ ​ 345,538 ​ ​ 1,055,177 Segment assets ​ $ 14,121,523 ​ ​ 20,869 ​ ​ 6,282,878 ​ ​ (5,227,701) ​ ​ 15,197,569 Capital expenditures for segment assets ​ $ 1,369,003 ​ ​ — ​ ​ 391,990 ​ ​ (338,838) ​ ​ 1,422,155 ​

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2019
Condensed Consolidating Financial Information
Condensed Consolidating Financial Information	(19) Condensed Consolidating Financial Information Each of the Company’s wholly owned subsidiaries has fully and unconditionally guaranteed Antero Resources’ senior notes. In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a “Subsidiary” of the Company (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease)) and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person that is not the Company or a restricted subsidiary of the Company, such subsidiary guarantor will be released from its obligations under its subsidiary guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the notes. In addition, a subsidiary guarantor will be released from its obligations under the indentures and its guarantee, upon the release or discharge of the guarantee of other Indebtedness (as defined in the indentures governing the notes) that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if the Company designates such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indentures governing the notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes. The following Condensed Consolidating Balance Sheets at December 31, 2018 and 2019, and the related Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2017, 2018 and 2019, present financial information for Antero Resources on a stand-alone basis (carrying its investment in subsidiaries using the equity method), financial information for the subsidiary guarantors, financial information for the non-guarantor subsidiaries, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company. Condensed Consolidating Balance Sheet December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts receivable, net ​ $ 49,529 ​ ​ — ​ ​ 1,544 ​ ​ — ​ ​ 51,073 ​ Intercompany receivables ​ ​ 383 ​ ​ — ​ ​ 115,378 ​ ​ (115,761) ​ ​ — ​ Accrued revenue ​ ​ 474,827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 474,827 ​ Derivative instruments ​ ​ 245,263 ​ ​ — ​ ​ — ​ ​ — ​ ​ 245,263 ​ Other current assets ​ ​ 13,937 ​ ​ — ​ ​ 21,513 ​ ​ — ​ ​ 35,450 ​ Total current assets ​ ​ 783,939 ​ ​ — ​ ​ 138,435 ​ ​ (115,761) ​ ​ 806,613 ​ Property and equipment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and gas properties, at cost (successful efforts method): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved properties ​ ​ 1,767,600 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,767,600 ​ Proved properties ​ ​ 13,306,585 ​ ​ — ​ ​ — ​ ​ (600,913) ​ ​ 12,705,672 ​ Water handling and treatment systems ​ ​ — ​ ​ — ​ ​ 1,004,793 ​ ​ 9,025 ​ ​ 1,013,818 ​ Gathering systems and facilities ​ ​ 17,825 ​ ​ — ​ ​ 2,452,883 ​ ​ — ​ ​ 2,470,708 ​ Other property and equipment ​ ​ 65,770 ​ ​ — ​ ​ 72 ​ ​ — ​ ​ 65,842 ​ ​ ​ ​ 15,157,780 ​ ​ — ​ ​ 3,457,748 ​ ​ (591,888) ​ ​ 18,023,640 ​ Less accumulated depletion, depreciation, and amortization ​ ​ (3,654,392) ​ ​ — ​ ​ (499,333) ​ ​ — ​ ​ (4,153,725) ​ Property and equipment, net ​ ​ 11,503,388 ​ ​ — ​ ​ 2,958,415 ​ ​ (591,888) ​ ​ 13,869,915 ​ Derivative instruments ​ ​ 362,169 ​ ​ — ​ ​ — ​ ​ — ​ ​ 362,169 ​ Investment in Antero Midstream Partners ​ ​ (740,031) ​ ​ — ​ ​ — ​ ​ 740,031 ​ ​ — ​ Contingent acquisition consideration ​ ​ 114,995 ​ ​ — ​ ​ — ​ ​ (114,995) ​ ​ — ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 433,642 ​ ​ — ​ ​ 433,642 ​ Other assets ​ ​ 31,200 ​ ​ — ​ ​ 15,925 ​ ​ — ​ ​ 47,125 ​ Total assets ​ $ 12,055,660 ​ ​ — ​ ​ 3,546,417 ​ ​ (82,613) ​ ​ 15,519,464 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities and Equity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable ​ $ 44,917 ​ ​ — ​ ​ 21,372 ​ ​ — ​ ​ 66,289 ​ Intercompany payable ​ ​ 111,620 ​ ​ — ​ ​ 4,141 ​ ​ (115,761) ​ ​ — ​ Accrued liabilities ​ ​ 392,949 ​ ​ — ​ ​ 72,121 ​ ​ — ​ ​ 465,070 ​ Revenue distributions payable ​ ​ 310,827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 310,827 ​ Derivative instruments ​ ​ 532 ​ ​ — ​ ​ — ​ ​ — ​ ​ 532 ​ Short-term lease liabilities ​ ​ 2,459 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,459 ​ Other current liabilities ​ ​ 2,162 ​ ​ — ​ ​ 2,052 ​ ​ 4,149 ​ ​ 8,363 ​ Total current liabilities ​ ​ 865,466 ​ ​ — ​ ​ 99,686 ​ ​ (111,612) ​ ​ 853,540 ​ Long-term liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt ​ ​ 3,829,541 ​ ​ — ​ ​ 1,632,147 ​ ​ — ​ ​ 5,461,688 ​ Deferred income tax liability ​ ​ 650,788 ​ ​ — ​ ​ — ​ ​ — ​ ​ 650,788 ​ Contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 114,995 ​ ​ (114,995) ​ ​ — ​ Long-term lease liabilities ​ ​ 2,873 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,873 ​ Other liabilities ​ ​ 55,017 ​ ​ — ​ ​ 8,081 ​ ​ — ​ ​ 63,098 ​ Total liabilities ​ ​ 5,403,685 ​ ​ — ​ ​ 1,854,909 ​ ​ (226,607) ​ ​ 7,031,987 ​ Equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stockholders' equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Partners' capital ​ ​ — ​ ​ — ​ ​ 1,691,508 ​ ​ (1,691,508) ​ ​ — ​ Common stock ​ ​ 3,086 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,086 ​ Additional paid-in capital ​ ​ 5,471,341 ​ ​ — ​ ​ — ​ ​ 1,013,833 ​ ​ 6,485,174 ​ Accumulated earnings ​ ​ 1,177,548 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,177,548 ​ Total stockholders' equity ​ ​ 6,651,975 ​ ​ — ​ ​ 1,691,508 ​ ​ (677,675) ​ ​ 7,665,808 ​ Noncontrolling interests in consolidated subsidiary ​ ​ — ​ ​ — ​ ​ — ​ ​ 821,669 ​ ​ 821,669 ​ Total equity ​ ​ 6,651,975 ​ ​ — ​ ​ 1,691,508 ​ ​ 143,994 ​ ​ 8,487,477 ​ Total liabilities and equity ​ $ 12,055,660 ​ ​ — ​ ​ 3,546,417 ​ ​ (82,613) ​ ​ 15,519,464 ​ ​ Condensed Consolidating Balance Sheet December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts receivable, net ​ ​ 46,419 ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,419 ​ Accounts receivable, related parties ​ ​ 125,000 ​ ​ 299,450 ​ ​ — ​ ​ (299,450) ​ ​ 125,000 ​ Accrued revenue ​ ​ 317,886 ​ ​ — ​ ​ — ​ ​ — ​ ​ 317,886 ​ Derivative instruments ​ ​ 422,849 ​ ​ — ​ ​ — ​ ​ — ​ ​ 422,849 ​ Other current assets ​ ​ 10,731 ​ ​ — ​ ​ — ​ ​ — ​ ​ 10,731 ​ Total current assets ​ ​ 922,885 ​ ​ 299,450 ​ ​ — ​ ​ (299,450) ​ ​ 922,885 ​ Property and equipment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and gas properties, at cost (successful efforts method): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved properties ​ ​ 1,368,854 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,368,854 ​ Proved properties ​ ​ 11,859,817 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,859,817 ​ Gathering systems and facilities ​ ​ 5,802 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,802 ​ Other property and equipment ​ ​ 71,895 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,895 ​ ​ ​ ​ 13,306,368 ​ ​ — ​ ​ — ​ ​ — ​ ​ 13,306,368 ​ Less accumulated depletion, depreciation, and amortization ​ ​ (3,327,629) ​ ​ — ​ ​ ​ ​ ​ — ​ ​ (3,327,629) ​ Property and equipment, net ​ ​ 9,978,739 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,978,739 ​ Operating leases right-of-use assets ​ ​ 2,886,500 ​ ​ — ​ ​ ​ ​ ​ — ​ ​ 2,886,500 ​ Derivative instruments ​ ​ 333,174 ​ ​ — ​ ​ — ​ ​ — ​ ​ 333,174 ​ Investments in unconsolidated affiliates ​ ​ 243,048 ​ ​ 812,129 ​ ​ — ​ ​ — ​ ​ 1,055,177 ​ Investments in consolidated affiliates ​ ​ 812,129 ​ ​ — ​ ​ — ​ ​ (812,129) ​ ​ — ​ Other assets ​ ​ 21,094 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,094 ​ Total assets ​ $ 15,197,569 ​ ​ 1,111,579 ​ ​ — ​ ​ (1,111,579) ​ ​ 15,197,569 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities and Equity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable ​ $ 14,498 ​ ​ — ​ ​ — ​ ​ — ​ ​ 14,498 ​ Accounts payable, related parties ​ ​ 397,333 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 97,883 ​ Accrued liabilities ​ ​ 400,850 ​ ​ — ​ ​ — ​ ​ — ​ ​ 400,850 ​ Revenue distributions payable ​ ​ 207,988 ​ ​ — ​ ​ — ​ ​ — ​ ​ 207,988 ​ Derivative instruments ​ ​ 6,721 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,721 ​ Short-term lease liabilities ​ ​ 305,320 ​ ​ — ​ ​ — ​ ​ — ​ ​ 305,320 ​ Other current liabilities ​ ​ 6,879 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,879 ​ Total current liabilities ​ ​ 1,339,589 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 1,040,139 ​ Long-term liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt ​ ​ 3,758,868 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,758,868 ​ Deferred income tax liability ​ ​ 781,987 ​ ​ — ​ ​ — ​ ​ — ​ ​ 781,987 ​ Derivative instruments ​ ​ 3,519 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,519 ​ Long-term lease liabilities ​ ​ 2,583,678 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,583,678 ​ Other liabilities ​ ​ 58,635 ​ ​ — ​ ​ — ​ ​ — ​ ​ 58,635 ​ Total liabilities ​ ​ 8,526,276 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 8,226,826 ​ Equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stockholders' equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Common stock ​ ​ 2,959 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,959 ​ Additional paid-in capital ​ ​ 5,600,714 ​ ​ 1,341,780 ​ ​ — ​ ​ (812,129) ​ ​ 6,130,365 ​ Accumulated earnings ​ ​ 1,067,620 ​ ​ (230,201) ​ ​ — ​ ​ — ​ ​ 837,419 ​ Total stockholders' equity ​ ​ 6,671,293 ​ ​ 1,111,579 ​ ​ — ​ ​ (812,129) ​ ​ 6,970,743 ​ Total liabilities and equity ​ $ 15,197,569 ​ ​ 1,111,579 ​ ​ — ​ ​ (1,111,579) ​ ​ 15,197,569 ​ ​ Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2017 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,769,975 ​ ​ — ​ ​ — ​ ​ (691) ​ ​ 1,769,284 ​ Natural gas liquids sales ​ 870,441 ​ ​ — ​ ​ — ​ ​ — ​ 870,441 ​ Oil sales ​ ​ 108,195 ​ ​ — ​ ​ — ​ ​ — ​ ​ 108,195 ​ Commodity derivative fair value gains ​ ​ 658,283 ​ ​ — ​ ​ — ​ ​ — ​ ​ 658,283 ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 772,497 ​ ​ (759,777) ​ ​ 12,720 ​ Marketing ​ ​ 258,045 ​ ​ — ​ ​ — ​ ​ — ​ ​ 258,045 ​ Marketing derivative loss ​ ​ (21,394) ​ ​ — ​ ​ — ​ ​ — ​ ​ (21,394) ​ Other income ​ ​ 16,667 ​ ​ — ​ ​ — ​ ​ (16,667) ​ ​ — ​ Total revenue and other ​ ​ 3,660,212 ​ ​ — ​ ​ 772,497 ​ ​ (777,135) ​ ​ 3,655,574 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 93,758 ​ ​ — ​ ​ 189,702 ​ ​ (194,403) ​ ​ 89,057 ​ Gathering, compression, processing, and transportation ​ ​ 1,441,129 ​ ​ — ​ ​ 39,147 ​ ​ (384,637) ​ ​ 1,095,639 ​ Production and ad valorem taxes ​ ​ 90,832 ​ ​ — ​ ​ 3,689 ​ ​ — ​ ​ 94,521 ​ Marketing ​ ​ 366,281 ​ ​ — ​ ​ — ​ ​ — ​ ​ 366,281 ​ Exploration ​ ​ 8,538 ​ ​ — ​ ​ — ​ ​ — ​ ​ 8,538 ​ Impairment of unproved properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of gathering systems and facilities ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Depletion, depreciation, and amortization ​ ​ 705,048 ​ ​ — ​ ​ 119,562 ​ ​ — ​ ​ 824,610 ​ Accretion of asset retirement obligations ​ ​ 2,610 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,610 ​ General and administrative ​ ​ 195,153 ​ ​ — ​ ​ 58,812 ​ ​ (2,769) ​ ​ 251,196 ​ Change in fair value of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 13,476 ​ ​ (13,476) ​ ​ — ​ Total operating expenses ​ ​ 3,062,947 ​ ​ — ​ ​ 447,819 ​ ​ (595,285) ​ ​ 2,915,481 ​ Operating income ​ ​ 597,265 ​ ​ — ​ ​ 324,678 ​ ​ (181,850) ​ ​ 740,093 ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 20,194 ​ ​ — ​ ​ 20,194 ​ Interest ​ ​ (232,331) ​ ​ — ​ ​ (37,262) ​ ​ 892 ​ ​ (268,701) ​ Loss on early extinguishment of debt ​ ​ (1,205) ​ ​ — ​ ​ (295) ​ ​ — ​ ​ (1,500) ​ Equity in earnings (loss) of Antero Midstream ​ ​ (43,710) ​ ​ — ​ ​ — ​ ​ 43,710 ​ ​ — ​ Total other expenses ​ ​ (277,246) ​ ​ — ​ ​ (17,363) ​ ​ 44,602 ​ ​ (250,007) ​ Income before income taxes ​ ​ 320,019 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 490,086 ​ Provision for income tax benefit ​ ​ 295,051 ​ ​ — ​ ​ — ​ ​ — ​ ​ 295,051 ​ Net income and comprehensive income including noncontrolling interests ​ ​ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 785,137 ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 170,067 ​ ​ 170,067 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ $ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (307,315) ​ ​ 615,070 ​ ​ Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,287,939 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,287,939 ​ Natural gas liquids sales ​ 1,177,777 ​ — ​ — ​ — ​ 1,177,777 ​ Oil sales ​ ​ 187,178 ​ ​ — ​ ​ — ​ ​ — ​ ​ 187,178 ​ Commodity derivative fair value losses ​ ​ (87,594) ​ ​ — ​ ​ — ​ ​ — ​ ​ (87,594) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 1,027,939 ​ ​ (1,006,595) ​ ​ 21,344 ​ Marketing ​ ​ 458,901 ​ ​ — ​ ​ — ​ ​ — ​ ​ 458,901 ​ Marketing derivative fair value gains ​ ​ 94,081 ​ ​ — ​ ​ — ​ ​ — ​ ​ 94,081 ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ 583 ​ ​ (583) ​ ​ — ​ Other income ​ ​ (87,217) ​ ​ — ​ ​ — ​ ​ 87,217 ​ ​ — ​ Total revenue and other ​ ​ 4,031,065 ​ ​ — ​ ​ 1,028,522 ​ ​ (919,961) ​ ​ 4,139,626 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 142,234 ​ ​ — ​ ​ 262,704 ​ ​ (268,785) ​ ​ 136,153 ​ Gathering, compression, processing, and transportation ​ ​ 1,792,898 ​ ​ — ​ ​ 49,550 ​ ​ (503,090) ​ ​ 1,339,358 ​ Production and ad valorem taxes ​ ​ 122,305 ​ ​ — ​ ​ 4,169 ​ ​ — ​ ​ 126,474 ​ Marketing ​ ​ 686,055 ​ ​ — ​ ​ — ​ ​ — ​ ​ 686,055 ​ Exploration ​ ​ 4,958 ​ ​ — ​ ​ — ​ ​ — ​ ​ 4,958 ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ 4,470 ​ ​ — ​ ​ 5,771 ​ ​ (583) ​ ​ 9,658 ​ Depletion, depreciation, and amortization ​ ​ 842,452 ​ ​ — ​ ​ 130,013 ​ ​ — ​ ​ 972,465 ​ Accretion of asset retirement obligations ​ ​ 2,684 ​ ​ — ​ ​ 135 ​ ​ — ​ ​ 2,819 ​ General and administrative ​ ​ 181,305 ​ ​ — ​ ​ 61,629 ​ ​ (2,590) ​ ​ 240,344 ​ Accretion of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ (93,019) ​ ​ 93,019 ​ ​ — ​ Total operating expenses ​ ​ 4,328,798 ​ ​ — ​ ​ 420,952 ​ ​ (682,029) ​ ​ 4,067,721 ​ Operating income (loss) ​ ​ (297,733) ​ ​ — ​ ​ 607,570 ​ ​ (237,932) ​ ​ 71,905 ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 40,280 ​ ​ — ​ ​ 40,280 ​ Interest expense, net ​ ​ (224,977) ​ ​ — ​ ​ (61,906) ​ ​ 140 ​ ​ (286,743) ​ Equity in earnings (loss) of consolidated subsidiaries ​ ​ (3,664) ​ ​ — ​ ​ — ​ ​ 3,664 ​ ​ — ​ Total other expenses ​ ​ (228,641) ​ ​ — ​ ​ (21,626) ​ ​ 3,804 ​ ​ (246,463) ​ Income (loss) before income taxes ​ ​ (526,374) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (174,558) ​ Provision for income tax benefit ​ ​ 128,857 ​ ​ — ​ ​ — ​ ​ — ​ ​ 128,857 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interests ​ ​ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (45,701) ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 351,816 ​ ​ 351,816 ​ Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation ​ $ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (585,944) ​ ​ (397,517) ​ ​ Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,247,162 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,247,162 ​ Natural gas liquids sales ​ 1,219,162 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,219,162 ​ Oil sales ​ ​ 177,549 ​ ​ — ​ ​ — ​ ​ — ​ ​ 177,549 ​ Commodity derivative fair value gains ​ ​ 463,972 ​ ​ — ​ ​ — ​ ​ — ​ ​ 463,972 ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 218,360 ​ ​ (213,882) ​ ​ 4,478 ​ Marketing ​ ​ 292,207 ​ ​ — ​ ​ — ​ ​ — ​ ​ 292,207 ​ Other income ​ ​ 5,810 ​ ​ — ​ ​ — ​ ​ (1,650) ​ ​ 4,160 ​ Total revenue and other ​ ​ 4,405,862 ​ ​ — ​ ​ 218,360 ​ ​ (215,532) ​ ​ 4,408,690 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 146,957 ​ ​ — ​ ​ 64,818 ​ ​ (66,055) ​ ​ 145,720 ​ Gathering, compression, processing, and transportation ​ ​ 2,257,133 ​ ​ — ​ ​ — ​ ​ (110,486) ​ ​ 2,146,647 ​ Production and ad valorem taxes ​ ​ 124,202 ​ ​ — ​ ​ — ​ ​ 940 ​ ​ 125,142 ​ Marketing ​ ​ 549,814 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,814 ​ Exploration ​ ​ 884 ​ ​ — ​ ​ — ​ ​ — ​ ​ 884 ​ Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 ​ Impairment of midstream assets ​ ​ 7,800 ​ ​ — ​ ​ 6,982 ​ ​ — ​ ​ 14,782 ​ Depletion, depreciation, and amortization ​ ​ 893,160 ​ ​ — ​ ​ 21,707 ​ ​ — ​ ​ 914,867 ​ Loss on sale of assets ​ ​ 951 ​ ​ — ​ ​ — ​ ​ — ​ ​ 951 ​ Accretion of asset retirement obligations ​ ​ 3,699 ​ ​ — ​ ​ 63 ​ ​ — ​ ​ 3,762 ​ General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 18,793 ​ ​ (499) ​ ​ 178,696 ​ Contract termination and rig stacking ​ ​ 14,026 ​ ​ — ​ ​ — ​ ​ — ​ ​ 14,026 ​ Accretion of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 1,928 ​ ​ (1,928) ​ ​ — ​ Total operating expenses ​ ​ 5,459,472 ​ ​ — ​ ​ 114,291 ​ ​ (178,028) ​ ​ 5,395,735 ​ Operating income (loss) ​ ​ (1,053,610) ​ ​ — ​ ​ 104,069 ​ ​ (37,504) ​ ​ (987,045) ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Water earnout ​ ​ 125,000 ​ ​ ​ ​ ​ ​ ​ ​ — ​ ​ 125,000 ​ Equity in earnings (loss) of unconsolidated affiliates ​ ​ (49,442) ​ ​ (106,038) ​ ​ 12,264 ​ ​ — ​ ​ (143,216) ​ Equity in earnings of affiliates ​ ​ 15,021 ​ ​ — ​ ​ — ​ ​ (15,021) ​ ​ — ​ Loss on the sale of equity investment shares ​ ​ (108,745) ​ ​ — ​ ​ — ​ ​ — ​ ​ (108,745) ​ Impairment of equity investments ​ ​ (143,090) ​ ​ (324,500) ​ ​ — ​ ​ — ​ ​ (467,590) ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ 1,205,705 ​ ​ 200,337 ​ ​ — ​ ​ — ​ ​ 1,406,042 ​ Interest expense, net ​ ​ (211,296) ​ ​ — ​ ​ (16,815) ​ ​ — ​ ​ (228,111) ​ Gain on early extinguishment of debt ​ ​ 36,419 ​ ​ — ​ ​ — ​ ​ — ​ ​ 36,419 ​ Total other income (expenses) ​ ​ 869,572 ​ ​ (230,201) ​ ​ (4,551) ​ ​ (15,021) ​ ​ 619,799 ​ Income before income taxes ​ ​ (184,038) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (367,246) ​ Provision for income tax expense ​ ​ 74,110 ​ ​ — ​ ​ — ​ ​ — ​ ​ 74,110 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interests ​ ​ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (293,136) ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,993 ​ ​ 46,993 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ $ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (99,518) ​ ​ (340,129) ​ ​ Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ (Antero ​ ​ ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income including noncontrolling interests ​ $ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 785,137 ​ Adjustment to reconcile net income to net cash ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 707,658 ​ ​ — ​ ​ 119,562 ​ ​ — ​ ​ 827,220 ​ Change in fair value of contingent acquisition consideration ​ ​ (13,476) ​ ​ — ​ ​ 13,476 ​ ​ — ​ ​ — ​ Impairment of oil and gas properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Commodity derivative fair value gains ​ ​ (658,283) ​ ​ — ​ ​ — ​ ​ — ​ ​ (658,283) ​ Gains on settled commodity derivatives ​ ​ 213,940 ​ ​ — ​ ​ — ​ ​ — ​ ​ 213,940 ​ Proceeds from derivative monetizations ​ ​ 749,906 ​ ​ — ​ ​ — ​ ​ — ​ ​ 749,906 ​ Marketing derivative losses ​ ​ 21,394 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,394 ​ Deferred income tax benefit ​ ​ (295,126) ​ ​ — ​ ​ — ​ ​ — ​ ​ (295,126) ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Equity-based compensation expense ​ ​ 76,162 ​ ​ — ​ ​ 27,283 ​ ​ — ​ ​ 103,445 ​ Loss on early extinguishment of debt ​ ​ 1,205 ​ ​ — ​ ​ 295 ​ ​ — ​ ​ 1,500 ​ Equity in earnings of Antero Midstream ​ ​ 43,710 ​ ​ — ​ ​ — ​ ​ (43,710) ​ ​ — ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (20,194) ​ ​ — ​ ​ (20,194) ​ Distributions of earnings from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 20,195 ​ ​ — ​ ​ 20,195 ​ Other ​ ​ (4,500) ​ ​ — ​ ​ 2,593 ​ ​ — ​ ​ (1,907) ​ Distributions from subsidiaries ​ ​ 131,598 ​ ​ — ​ ​ — ​ ​ (131,598) ​ ​ — ​ Changes in current assets and liabilities ​ ​ 87,466 ​ ​ — ​ ​ (18,160) ​ ​ 6,729 ​ ​ 76,035 ​ Net cash provided by operating activities ​ ​ 1,836,322 ​ ​ — ​ ​ 475,796 ​ ​ (305,827) ​ ​ 2,006,291 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to proved properties ​ ​ (175,650) ​ ​ — ​ ​ — ​ ​ — ​ ​ (175,650) ​ Additions to unproved properties ​ ​ (204,272) ​ ​ — ​ ​ — ​ ​ — ​ ​ (204,272) ​ Drilling and completion costs ​ ​ (1,455,554) ​ ​ — ​ ​ — ​ ​ 173,569 ​ ​ (1,281,985) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (195,162) ​ ​ 660 ​ ​ (194,502) ​ Additions to gathering systems and facilities ​ ​ — ​ ​ — ​ ​ (346,217) ​ ​ — ​ ​ (346,217) ​ Additions to other property and equipment ​ ​ (14,127) ​ ​ — ​ ​ — ​ ​ — ​ ​ (14,127) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (235,004) ​ ​ — ​ ​ (235,004) ​ Change in other assets ​ ​ (8,594) ​ ​ — ​ ​ (3,435) ​ ​ — ​ ​ (12,029) ​ Other ​ ​ 2,156 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,156 ​ Net cash used in investing activities ​ ​ (1,856,041) ​ ​ — ​ ​ (779,818) ​ ​ 174,229 ​ ​ (2,461,630) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Issuance of common units by Antero Midstream ​ ​ — ​ ​ — ​ ​ 248,956 ​ ​ — ​ ​ 248,956 ​ Sale of common units in Antero Midstream by Antero Resources Corporation ​ ​ 311,100 ​ ​ — ​ ​ — ​ ​ — ​ ​ 311,100 ​ Borrowings (repayments) on bank credit facility, net ​ ​ (255,000) ​ ​ — ​ ​ 345,000 ​ ​ — ​ ​ 90,000 ​ Payments of deferred financing costs ​ ​ (10,857) ​ ​ — ​ ​ (5,520) ​ ​ — ​ ​ (16,377) ​ Distributions ​ ​ — ​ ​ — ​ ​ (283,950) ​ ​ 131,598 ​ ​ (152,352) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (18,229) ​ ​ — ​ ​ (5,945) ​ ​ — ​ ​ (24,174) ​ Other ​ ​ (4,785) ​ ​ — ​ ​ (198) ​ ​ — ​ ​ (4,983) ​ Net cash provided by financing activities ​ ​ 22,229 ​ ​ — ​ ​ 298,343 ​ ​ 131,598 ​ ​ 452,170 ​ Net increase (decrease) in cash and cash equivalents ​ ​ 2,510 ​ ​ — ​ ​ (5,679) ​ ​ — ​ ​ (3,169) ​ Cash and cash equivalents, beginning of period ​ ​ 17,568 ​ ​ — ​ ​ 14,042 ​ ​ — ​ ​ 31,610 ​ Cash and cash equivalents, end of period ​ $ 20,078 ​ ​ — ​ ​ 8,363 ​ ​ — ​ ​ 28,441 ​ Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ (Antero Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) including noncontrolling interests ​ $ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (45,701) ​ Adjustment to reconcile net income (loss) to net cash provided by operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 845,136 ​ ​ — ​ ​ 130,148 ​ ​ — ​ ​ 975,284 ​ Changes in fair value of contingent acquisition consideration ​ ​ 93,019 ​ ​ — ​ ​ (93,019) ​ ​ — ​ ​ — ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ 4,470 ​ ​ — ​ ​ 5,771 ​ ​ (583) ​ ​ 9,658 ​ Commodity derivative fair value losses ​ ​ 87,594 ​ ​ — ​ ​ — ​ ​ — ​ ​ 87,594 ​ Gains on settled commodity derivatives ​ ​ 243,112 ​ ​ — ​ ​ — ​ ​ — ​ ​ 243,112 ​ Premium paid on derivative contracts ​ ​ (13,318) ​ ​ — ​ ​ — ​ ​ — ​ ​ (13,318) ​ Proceeds from derivative monetizations ​ ​ 370,365 ​ ​ — ​ ​ — ​ ​ — ​ ​ 370,365 ​ Marketing derivative fair value gains ​ ​ (94,081) ​ ​ — ​ ​ — ​ ​ — ​ ​ (94,081) ​ Gains on settled marketing derivatives ​ ​ 72,687 ​ ​ — ​ ​ — ​ ​ — ​ ​ 72,687 ​ Deferred income tax benefit ​ ​ (128,857) ​ ​ — ​ ​ — ​ ​ — ​ ​ (128,857) ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ (583) ​ ​ 583 ​ ​ — ​ Equity-based compensation expense ​ ​ 49,341 ​ ​ — ​ ​ 21,073 ​ ​ — ​ ​ 70,414 ​ Equity in earnings (loss) of consolidated subsidiaries ​ ​ 3,664 ​ ​ — ​ ​ — ​ ​ (3,664) ​ ​ — ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (40,280) ​ ​ — ​ ​ (40,280) ​ Distributions of earnings from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 46,415 ​ ​ — ​ ​ 46,415 ​ Distributions from Antero Midstream ​ ​ 159,181 ​ ​ — ​ ​ — ​ ​ (159,181) ​ ​ — ​ Other ​ ​ 4,681 ​ ​ — ​ ​ 2,879 ​ ​ (2,879) ​ ​ 4,681 ​ Changes in current assets and liabilities ​ ​ (26,059) ​ ​ — ​ ​ (788) ​ ​ 1,424 ​ ​ (25,423) ​ Net cash provided by operating activities ​ ​ 1,822,855 ​ ​ — ​ ​ 657,560 ​ ​ (398,428) ​ ​ 2,081,987 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to unproved properties ​ ​ (172,387) ​ ​ — ​ ​ — ​ ​ — ​ ​ (172,387) ​ Drilling and completion costs ​ ​ (1,743,587) ​ ​ — ​ ​ — ​ ​ 255,014 ​ ​ (1,488,573) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (88,674) ​ ​ (9,025) ​ ​ (97,699) ​ Additions to gathering systems and facilities ​ ​ 103 ​ ​ — ​ ​ (446,270) ​ ​ 1,754 ​ ​ (444,413) ​ Additions to other property and equipment ​ ​ (7,441) ​ ​ — ​ ​ — ​ ​ (73) ​ ​ (7,514) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (136,475) ​ ​ — ​ ​ (136,475) ​ Change in other assets ​ ​ (72) ​ ​ — ​ ​ (3,591) ​ ​ — ​ ​ (3,663) ​ Change in other liabilities ​ ​ — ​ ​ — ​ ​ 2,273 ​ ​ (2,273) ​ ​ — ​ Other ​ ​ — ​ ​ — ​ ​ 6,150 ​ ​ (6,150) ​ ​ — ​ Net cash used in investing activities ​ ​ (1,923,384) ​ ​ — ​ ​ (666,587) ​ ​ 239,247 ​ ​ (2,350,724) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repurchases of common stock ​ ​ (129,084) ​ ​ — ​ ​ — ​ ​ — ​ ​ (129,084) ​ Borrowings (repayments) on bank credit facility, net ​ ​ 225,379 ​ ​ — ​ ​ 435,000 ​ ​ — ​ ​ 660,379 ​ Payments of deferred financing costs ​ ​ — ​ ​ — ​ ​ (2,169) ​ ​ — ​ ​ (2,169) ​ Distributions ​ ​ — ​ ​ — ​ ​ (426,452) ​ ​ 159,181 ​ ​ (267,271) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (11,491) ​ ​ — ​ ​ (5,529) ​ ​ — ​ ​ (17,020) ​ Other ​ ​ (4,353) ​ ​ — ​ ​ (186) ​ ​ — ​ ​ (4,539) ​ Net cash provided by financing activities ​ ​ 80,451 ​ ​ — ​ ​ 664 ​ ​ 159,181 ​ ​ 240,296 ​ Net decrease in cash and cash equivalents ​ ​ (20,078) ​ ​ — ​ ​ (8,363) ​ ​ — ​ ​ (28,441) ​ Cash and cash equivalents, beginning of period ​ ​ 20,078 ​ ​ — ​ ​ 8,363 ​ ​ — ​ ​ 28,441 ​ Cash and cash equivalents, end of period ​ $ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ (Antero Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) including noncontrolling interests ​ $ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (293,136) ​ Adjustment to reconcile net income (loss) to net cash provided by operating activities: ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 896,859 ​ ​ — ​ ​ 21,770 ​ ​ — ​ ​ 918,629 ​ Impairments ​ ​ 1,451,334 ​ ​ 324,500 ​ ​ 6,982 ​ ​ — ​ ​ 1,782,816 ​ Commodity derivative fair value gains ​ ​ (463,972) ​ ​ — ​ ​ — ​ ​ — ​ ​ (463,972) ​ Gains on settled commodity derivatives ​ ​ 325,090 ​ ​ — ​ ​ — ​ ​ — ​ ​ 325,090 ​ Deferred income tax benefit ​ ​ (79,158) ​ ​ — ​ ​ — ​ ​ — ​ ​ (79,158) ​ Loss on sale of assets ​ ​ 951 ​ ​ — ​ ​ — ​ ​ — ​ ​ 951 ​ Equity-based compensation expense ​ ​ 21,082 ​ ​ — ​ ​ 2,477 ​ ​ — ​ ​ 23,559 ​ Gain on early extinguishment of debt ​ ​ (36,419) ​ ​ — ​ ​ — ​ ​ — ​ ​ (36,419) ​ Loss on sale of equity investment shares ​ ​ 108,745 ​ ​ — ​ ​ — ​ ​ — ​ ​ 108,745 ​ Equity in earnings of affiliates ​ ​ (15,021) ​ ​ — ​ ​ — ​ ​ 15,021 ​ ​ — ​ Equity in (earnings) loss of unconsolidated affiliates ​ ​ 49,442 ​ ​ 106,038 ​ ​ (12,264) ​ ​ — ​ ​ 143,216 ​ Water earnout ​ ​ (125,000) ​ ​ — ​ ​ — ​ ​ — ​ ​ (125,000) ​ Distributions/dividends of earnings from unconsolidated affiliates ​ ​ 145,351 ​ ​ — ​ ​ 12,605 ​ ​ — ​ ​ 157,956 ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ (1,205,705) ​ ​ (200,337) ​ ​ — ​ ​ — ​ ​ (1,406,042) ​ Distributions from Antero Midstream Partners LP ​ ​ 94,391 ​ ​ — ​ ​ — ​ ​ (94,391) ​ ​ — ​ Other ​ ​ (37,991) ​ ​ — ​ ​ 750 ​ ​ 47,922 ​ ​ 10,681 ​ Changes in current assets and liabilities ​ ​ 29,307 ​ ​ — ​ ​ (10,573) ​ ​ 16,808 ​ ​ 35,542 ​ Net cash provided by operating activities ​ ​ 1,049,358 ​ ​ — ​ ​ 121,265 ​ ​ (67,165) ​ ​ 1,103,458 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to unproved properties ​ ​ (88,682) ​ ​ — ​ ​ — ​ ​ — ​ ​ (88,682) ​ Drilling and completion costs ​ ​ (1,274,683) ​ ​ — ​ ​ — ​ ​ 20,565 ​ ​ (1,254,118) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (24,547) ​ ​ 131 ​ ​ (24,416) ​ Additions to gathering systems and facilities ​ ​ — ​ ​ — ​ ​ (48,239) ​ ​ — ​ ​ (48,239) ​ Additions to other property and equipment ​ ​ (5,638) ​ ​ — ​ ​ (1,062) ​ ​ — ​ ​ (6,700) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (25,020) ​ ​ — ​ ​ (25,020) ​ Proceeds from sale of common stock of Antero Midstream Corporation ​ ​ 100,000 ​ ​ — ​ ​ — ​ ​ — ​ ​ 100,000 ​ Proceeds from the Antero Midstream Partners LP Transactions ​ ​ 296,611 ​ ​ — ​ ​ — ​ ​ — ​ ​ 296,611 ​ Change in other assets ​ ​ 10,448 ​ ​ — ​ ​ (3,357) ​ ​ — ​ ​ 7,091 ​ Proceeds from sale of assets ​ ​ 1,983 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,983 ​ Net cash investing activities ​ ​ (959,961) ​ ​ — ​ ​ (102,225) ​ ​ 20,696 ​ ​ (1,041,490) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ — ​ Repurchases of common stock ​ ​ (38,772) ​ ​ — ​ ​ — ​ ​ — ​ ​ (38,772) ​ Issuance of senior notes ​ ​ — ​ ​ — ​ ​ 650,000 ​ ​ — ​ ​ 650,000 ​ Repayment of senior notes ​ ​ (191,092) ​ ​ — ​ ​ — ​ ​ — ​ ​ (191,092) ​ Borrowings (repayments) on bank credit facilities, net ​ ​ 141,621 ​ ​ — ​ ​ 90,379 ​ ​ — ​ ​ 232,000 ​ Payments of deferred financing costs ​ ​ 2,921 ​ ​ — ​ ​ (7,468) ​ ​ — ​ ​ (4,547) ​ Distributions to noncontrolling interests in Antero Midstream Partners LP ​ ​ — ​ ​ — ​ ​ (131,545) ​ ​ 46,469 ​ ​ (85,076) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (2,360) ​ ​ — ​ ​ (29) ​ ​ — ​ ​ (2,389) ​ Other ​ ​ (1,715) ​ ​ — ​ ​ (845) ​ ​ — ​ ​ (2,560) ​ Net cash provided by (used in) financing activities ​ ​ (89,397) ​ ​ — ​ ​ 600,492 ​ ​ 46,469 ​ ​ 557,564 ​ Antero Midstream Partners LP cash at deconsolidation ​ ​ — ​ ​ — ​ ​ (619,532) ​ ​ — ​ ​ (619,532) ​ Net increase in cash and cash equivalents ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Cash and cash equivalents, beginning of period ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Cash and cash equivalents, end of period ​ $ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information (Unaudited)
Quarterly Financial Information (Unaudited)	(20) Quarterly Financial Information (Unaudited) The Company’s quarterly consolidated financial information for the years ended December 31, 2018 and 2019 is summarized in the tables below (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ quarter ​ quarter ​ quarter ​ quarter ​ Year Ended December 31, 2018: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,028,101 ​ 989,344 ​ 1,076,532 ​ 1,045,649 ​ Total operating expenses ​ 881,607 ​ 1,022,107 ​ 1,071,728 ​ 1,092,279 ​ Operating income (loss) ​ 146,494 ​ (32,763) ​ 4,804 ​ (46,630) ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ 80,810 ​ (67,275) ​ (77,972) ​ 18,736 ​ Net income attributable to noncontrolling interest ​ ​ 65,977 ​ 69,110 ​ 76,447 ​ 140,282 ​ Net income (loss) attributable to Antero Resources Corporation ​ 14,833 ​ (136,385) ​ (154,419) ​ (121,546) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share—basic ​ $ 0.05 ​ (0.43) ​ (0.49) ​ (0.39) ​ Earnings (loss) per common share—assuming dilution ​ $ 0.05 ​ (0.43) ​ (0.49) ​ (0.39) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ quarter ​ quarter ​ quarter ​ quarter Year Ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,037,407 ​ ​ 1,299,664 ​ ​ 1,118,881 ​ 952,738 ​ Total operating expenses ​ 1,071,114 ​ ​ 1,199,668 ​ ​ 2,104,759 ​ 1,020,194 ​ Operating income (loss) ​ (33,707) ​ 99,996 ​ (985,878) ​ (67,456) ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ 1,406,042 ​ ​ — ​ ​ — ​ ​ — ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ 1,025,756 ​ ​ 42,168 ​ ​ (878,864) ​ (482,196) ​ Net income attributable to noncontrolling interest ​ ​ 46,993 ​ ​ — ​ ​ — ​ — ​ Net income (loss) attributable to Antero Resources Corporation ​ 978,763 ​ 42,168 ​ (878,864) ​ (482,196) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ Earnings (loss) per common share—diluted ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ ​ Operating income is calculated as operating revenues minus operating expenses. During the third and fourth quarters of 2019, operating expenses were impacted by impairments for proved properties, unproved properties and equity investments that were material to the quarters as presented. See Note 2 to the consolidated financial statement for more information

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2019
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	(21) Supplemental Information on Oil and Gas Producing Activities (Unaudited) The following is supplemental information regarding the Company’s consolidated oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties. (a) Capitalized Costs Relating to Oil and Gas Producing Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, (In thousands) ​ 2018 ​ 2019 ​ Proved properties ​ $ 12,705,672 ​ ​ 11,859,817 ​ Unproved properties ​ 1,767,600 ​ 1,368,854 ​ ​ ​ 14,473,272 ​ 13,228,671 ​ Accumulated depletion and depreciation ​ (3,615,680) ​ (3,284,330) ​ Net capitalized costs ​ $ 10,857,592 ​ ​ 9,944,341 ​ ​ (b) Costs Incurred in Certain Oil and Gas Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (In thousands) ​ 2017 ​ 2018 ​ 2019 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ 175,650 ​ ​ — ​ ​ — ​ Unproved property ​ 204,272 ​ ​ 172,387 ​ ​ 88,682 ​ Development costs ​ 897,287 ​ ​ 1,164,800 ​ ​ 1,104,336 ​ Exploration costs ​ 384,698 ​ ​ 323,773 ​ ​ 149,782 ​ Total costs incurred ​ $ 1,661,907 ​ ​ 1,660,960 ​ ​ 1,342,800 ​ ​ (c) Results of Operations for Oil and Gas Producing Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, (In thousands) ​ 2017 ​ 2018 ​ 2019 ​ Revenues ​ $ 2,747,920 ​ ​ 3,652,894 ​ ​ 3,643,873 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 1,279,217 ​ ​ 1,601,985 ​ ​ 2,417,509 ​ Exploration expenses ​ 8,538 ​ ​ 4,958 ​ ​ 884 ​ Depletion and depreciation ​ 694,332 ​ ​ 832,326 ​ ​ 884,350 ​ Impairment of oil and gas properties ​ 159,598 ​ ​ 549,437 ​ ​ 1,300,444 ​ Results of operations before income tax (expense) benefit ​ 606,235 ​ ​ 664,188 ​ ​ (959,314) ​ Income tax (expense) benefit ​ (228,096) ​ ​ (156,350) ​ ​ 224,511 ​ Results of operations ​ $ 378,139 ​ ​ 507,838 ​ ​ (734,803) ​ ​ (d) Oil and Gas Reserves The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the years ended December 31, 2017, 2018 and 2019 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (“D&M”) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States. Proved reserves are the estimated quantities of oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months . Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, cash flows from operations, future drilling and completion costs, and other economic factors. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural gas ​ NGLs ​ condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2016 ​ 9,414 ​ 957 ​ 38 ​ 15,386 ​ Revisions ​ 342 ​ (22) ​ (6) ​ 176 ​ Extensions, discoveries and other additions ​ 1,644 ​ 77 ​ 7 ​ 2,148 ​ Production ​ (591) ​ (36) ​ (2) ​ (822) ​ Purchases of reserves ​ 289 ​ 13 ​ 1 ​ 373 ​ December 31, 2017 ​ 11,098 ​ 989 ​ 38 ​ 17,261 ​ Revisions ​ (1,087) ​ 8 ​ (1) ​ (1,042) ​ Extensions, discoveries and other additions ​ 2,125 ​ 98 ​ 12 ​ 2,781 ​ Production ​ (711) ​ (43) ​ (3) ​ (989) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2018 ​ 11,425 ​ 1,052 ​ 46 ​ 18,011 ​ Revisions ​ (1,735) ​ 25 ​ (11) ​ (1,648) ​ Extensions, discoveries and other additions ​ 2,626 ​ 169 ​ 11 ​ 3,705 ​ Production ​ (822) ​ (55) ​ (4) ​ (1,175) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2019 ​ 11,494 ​ 1,191 ​ 42 ​ 18,893 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural gas ​ NGLs ​ condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ 5,587 ​ 467 ​ 16 ​ 8,488 ​ December 31, 2018 ​ 6,669 ​ 600 ​ 20 ​ 10,389 ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ 5,511 ​ 522 ​ 22 ​ 8,773 ​ December 31, 2018 ​ 4,756 ​ 452 ​ 26 ​ 7,622 ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​ ​ Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2017, 2018 and 2019 in the above table include the following: 2017 Changes in Reserves ● Extensions, discoveries, and other additions of 2,148 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. ● Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales. ● Net upward revisions of 176 Bcfe include: ● Upward revisions of 345 Bcfe related to improved well performance. ● Net downward revisions of 188 Bcfe related to revisions to our five-year development plan. This figure includes upward revisions of 2,092 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our five-year development plan, and downward revisions of 2,280 Bcfe for locations that were not developed within five years of initial booking as proved reserves. ● Upward revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil. ● Downward revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery. ● We produced 822 Bcfe during the year ended December 31, 2017. 2018 Changes in Reserves ● Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. ● Net downward revisions of 1,042 Bcfe include: ● Downward revisions of 433 Bcfe related to well performance. ● Net downward revisions of 742 Bcfe related to optimization to our five-year development plan. This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within five years of initial booking as proved reserves. ● Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil. ● Upward revisions of 115 Bcfe are due to an increase in our assumed future ethane recovery. We produced 989 Bcfe during the year ended December 31, 2018. 2019 Changes in Reserves ● Extensions, discoveries, and other additions of 3,705 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. ● Net downward revisions of 1,648 Bcfe include: ● Upward revisions of 63 Bcfe related to well performance. ● Net downward revisions of 1,705 Bcfe related to optimization to our five-year development plan. This figure includes upward revisions of 595 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our five-year development plan, and downward revisions of 2,300 Bcfe for locations that were not developed within five years of initial booking as proved reserves. ● Downward revisions of 157 Bcfe were due to increases in prices for natural gas, NGLs, and oil. ● Upward revisions of 315 Bcfe are due to an increase in our assumed future ethane recovery. ● Downward revisions of 164 Bcfe are due to the deconsolidation of Antero Midstream Partners. Deconsolidation of Antero Midstream Partners resulted in Antero Resources recording the full fees paid to Antero Midstream Partners for services rendered and no longer including future capital expenditures associated with Antero Midstream Partners’ assets in future development costs. Prior to deconsolidation, Antero Resources’ consolidated reserves included the elimination of full fees paid by Antero Resources to Antero Midstream Partners and the inclusion of the operating costs and capital incurred by Antero Midstream Partners. We produced 1,175 Bcfe during the year ended December 31, 2019. The following table sets forth the Standardized measure of the discounted future net cash flows attributable to the Company’s proved reserves. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the Standardized measure. Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available NOL carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (in millions) ​ 2017 ​ 2018 ​ 2019 Future cash inflows ​ $ 55,824 ​ ​ 64,199 ​ ​ 54,228 ​ Future production costs ​ (26,375) ​ ​ (30,007) ​ ​ (36,524) ​ Future development costs ​ (3,312) ​ ​ (3,453) ​ ​ (2,772) ​ Future net cash flows before income tax ​ 26,137 ​ ​ 30,739 ​ ​ 14,932 ​ Future income tax expense ​ (4,104) ​ ​ (5,505) ​ ​ (1,639) ​ Future net cash flows ​ 22,033 ​ ​ 25,234 ​ ​ 13,293 ​ 10% annual discount for estimated timing of cash flows ​ (13,406) ​ ​ (14,756) ​ ​ (7,824) ​ Standardized measure of discounted future net cash flows ​ $ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​ ​ The 12-month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ ​ ​ ​ ​ ​ ​ $ 3.23 ​ December 31, 2018 ​ ​ ​ ​ ​ ​ ​ $ 3.56 ​ December 31, 2019 ​ ​ ​ ​ ​ ​ ​ $ 2.87 ​ ​ (f) Changes in Standardized measure of Discounted Future Net Cash Flow ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (in millions) ​ 2017 ​ 2018 ​ 2019 ​ Sales of oil and gas, net of productions costs ​ $ (1,469) ​ ​ (2,051) ​ ​ (1,116) ​ Net changes in prices and production costs (1) ​ 3,918 ​ ​ 707 ​ ​ (6,729) ​ Development costs incurred during the period ​ 627 ​ ​ 755 ​ ​ 758 ​ Net changes in future development costs (2) ​ 229 ​ ​ 37 ​ ​ (92) ​ Extensions, discoveries and other additions ​ 1,448 ​ ​ 1,925 ​ ​ 782 ​ Acquisitions ​ 258 ​ ​ — ​ ​ — ​ Divestitures ​ ​ — ​ ​ — ​ ​ — ​ Revisions of previous quantity estimates ​ 734 ​ ​ (53) ​ ​ (1,011) ​ Accretion of discount ​ 368 ​ ​ 1,018 ​ ​ 1,259 ​ Net change in income taxes ​ (1,159) ​ ​ (563) ​ ​ 1,513 ​ Changes in timing and other ​ 386 ​ ​ 76 ​ ​ (373) ​ Net increase (decrease) ​ 5,340 ​ ​ 1,851 ​ ​ (5,009) ​ Beginning of year ​ 3,287 ​ ​ 8,627 ​ ​ 10,478 ​ End of year ​ $ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​ (1) (2)

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies
Basis of Presentation	(a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2018 and 2019, and the results of its operations and its cash flows for the years ended December 31, 2017, 2018 and 2019. The Company has items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. Operating results for the year ended December 31, 2019 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs, and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.
Principles of Consolidation	(b) Principles of Consolidation The accompanying consolidated financial statements include the accounts of Antero Resources Corporation, its wholly owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. Through March 12, 2019, Antero Midstream Partners LP (“Antero Midstream Partners”), a publicly traded limited partnership, was included in the consolidated financial statements of Antero. Prior to the Closing (defined in Note 3 to the consolidated financial statements), our ownership of Antero Midstream Partners common units represented approximately a limited partner interest in Antero Midstream Partners, and we consolidated Antero Midstream Partners’ financial position and results of operations into our consolidated financial statements. The Transactions (defined in Note 3 to the consolidated financial statements) resulted in the exchange of the limited partner interest we owned in Antero Midstream Partners for common stock of Antero Midstream Corporation representing an approximate interest as of March 13, 2019. As a result, we no longer hold a controlling interest in Antero Midstream Partners and we now have an interest in Antero Midstream Corporation that provides significant influence, but not control, over Antero Midstream Corporation. Thus, effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its consolidated financial statements and accounts for its interest in Antero Midstream Corporation using the equity method of accounting. On December 16, 2019, the Company sold 19,377,592 shares of Antero Midstream Corporation’s common stock to Antero Midstream at a price of $5.1606 per share, which shares were thereafter cancelled by Antero Midstream Corporation, resulting in aggregate proceeds to the Company of $100 million. This reduced Antero’s interest in Antero Midstream Corporation to approximately 28.7% at December 31, 2019. See Note 3 to the consolidated financial statements for further discussion of the Transactions. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. The noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream Partners, which were owned by the public prior to the Transactions, and the incentive distribution rights in Antero Midstream Partners, in both cases during the periods prior to the Transactions. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of equity method investees. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. When Antero records its proportionate share of net income, it increases equity income in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the balance sheet. The Company’s equity in earnings of unconsolidated affiliates is adjusted for intercompany transactions and the basis differences recognized due to the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation. The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).
Use of Estimates	(c) Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates. The Company’s consolidated financial statements are based on a number of significant estimates, including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s consolidated financial statements that involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred and current income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.
Risks and Uncertainties	(d) Risks and Uncertainties The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.
Cash and Cash Equivalents	(e) Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable and revenue distributions payable within its consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its consolidated statements of cash flows. As of December 31, 2019, the book overdraft included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2018, the book overdraft included within accounts payable and revenue distributions payable were
Oil and Gas Properties	(f) Oil and Gas Properties The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells-in- progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred such charges to expense during the years ended December 31, 2017 and 2018. During the year ended December 31, 2019, we recorded an impairment charge of million for design and initial costs related to pads that are no longer planned to be placed into service. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of- production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property-by- property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, commodity price outlooks, and future plans to develop acreage, as well as drilling results, and reservoir performance of wells in the area. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties was The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. During the year ended December 31, 2019, the carrying amount of the Utica Shale exceeded the estimated undiscounted future cash flows based on future commodity prices at September 30, 2019. We estimated the fair value of the Utica Shale assets based on sales of other properties. As a result, the Company recorded an impairment charge of million related to proved properties in the Utica Shale during the year ended December 31, 2019. The Company did not record any impairment expenses associated with its proved properties during the years ended December 31, 2017 and 2018, nor did it incur any impairment expenses related to proved properties in the Marcellus Shale during the year ended December 31, 2019. At December 31, 2019, the Company did not have capitalized costs related to exploratory wells-in-progress that have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units-of- production method. Depletion expense for oil and gas properties was
Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems	(g) Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that are not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred. Gathering pipelines and compressor stations are depreciated using the straight-line method over their estimated useful lives of . Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of . Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was 31, 2017, 2018 and 2019, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment. Due to the deconsolidation of Antero Midstream Partners, effective March 13, 2019, gathering pipelines, compressor stations, and water handling and treatment systems owned by Antero Midstream Partners are no longer included in the consolidated financial statements. In December 2019, the Company and Antero Midstream Corporation agreed to extend the initial term of the gathering and compression agreement to 2038 and established a growth incentive fee program whereby low pressure gathering fees will be reduced from 2020 through 2023 to the extent the Company achieves certain volumetric targets.
Impairment of Long Lived Assets Other than Oil and Gas Properties	(h) Impairment of Long-Lived Assets Other than Oil and Gas Properties The Company evaluates its long- lived assets other than oil and gas properties for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows using assumptions as to revenues, costs, and discount rates typical of third party market participants, which is a Level 3 fair value measurement. Impairment of long-lived assets other than oil and gas properties were $23 million, $10 million and $15 million during the years ended December 31, 2017, 2018 and 2019, respectively, and were associated with midstream assets.
Other Property and Equipment	(i) Other Property and Equipment Other property and equipment assets are depreciated using the straight-line method over their estimated useful lives, which range from 2 to 20 years . Depreciation expense for other property and equipment was 31, 2017, 2018 and 2019, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment.
Deferred Financing Costs	(j) Deferred Financing Costs Deferred financing costs represent loan origination fees and other initial borrowing costs. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2019, the Company had million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write-off of previously deferred debt issuance costs were
Derivative Financial Instruments	(k) Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions. The Company records derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.
Asset Retirement Obligations Policy	(l) Asset Retirement Obligations The Company is obligated to dispose of certain long- lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which is then discounted at the Company’s credit-adjusted, risk- free interest rate. Revisions to estimated AROs often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense.
Environmental Liabilities	(m) Environmental Liabilities Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2018 and 2019, the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows.
Natural Gas, NGLs, and Oil Revenues	(n) Natural Gas, NGLs, and Oil Revenues On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. The Company elected the modified retrospective transition method when new standard became effective for the Company on January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on the Company’s financial results. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the sale. Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses. NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor. Under our oil sales contracts, we generally sell oil to purchasers and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to a purchaser.
Marketing Revenues and Expenses	(o) Marketing Revenues and Expenses Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. We have concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser. Fees generated from the sale of excess firm transportation marketed to third parties are included in revenue. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense.
Gathering compression, water handling and treatment revenue	(p) Gathering, compression, water handling and treatment revenue Substantially all revenues from the gathering, compression, water handling and treatment operations were derived from transactions for services Antero Midstream Partners provided to our exploration and production operations through March 12, 2019 and were eliminated in consolidation. Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results. See Note 3 to the financial statements for further discussion on the Transactions and Note 18 to the consolidated financial statements for disclosures on the Company’s reportable segments. The portion of such fees shown in our consolidated financial statements prior to March 13, 2019 represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream Partners or usage of Antero Midstream Partners’ gathering and compression systems. For gathering and compression revenue, Antero Midstream Partners satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line. Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream Partners in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream Partners satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility. For services contracted through third-party providers, Antero Midstream Partners’ performance obligation is satisfied when the service performed by the third-party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream Partners in accordance with the water services agreement.
Concentrations of Credit Risk	(q) Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry. The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables. The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2017, 2018 and 2019 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 ​ ​ 2018 ​ ​ 2019 ​ Company A ​ 4 % ​ 8 % ​ 16 % Company B ​ 14 ​ ​ 6 ​ ​ 15 ​ Company C ​ 20 ​ ​ 13 ​ ​ 9 ​ Company D ​ — ​ ​ 14 ​ ​ 3 ​ All others ​ 62 ​ ​ 59 ​ ​ 57 ​ ​ ​ 100 % ​ 100 % ​ 100 % ​ The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due could have a material adverse effect on the Company’s financial condition and results of operations. The Company has economic hedges in place with different counterparties. The fair value of the Company’s commodity net derivative contracts is approximately million. The estimated fair value of commodity derivative assets has been risk-adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2019 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	(r) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense.
Fair Value Measurements	(s) Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long- lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments that are valued using Level 2 inputs include non-exchange traded derivatives such as over-the- counter commodity price swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures.
Industry Segments and Geographic Information	(t) Industry Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) marketing and utilization of excess firm transportation capacity, and (3) our equity method investment in Antero Midstream Corporation. Through March 12, 2019, the results of Antero Midstream Partners were included in the consolidated financial statements of Antero. Effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results; however, the Company’s segment disclosures include our equity method investment in Antero Midstream Corporation due to its significance to the Company’s operations. See Note 3 to the consolidated financial statements for further discussion on the Transactions and Note 18 to the consolidated financial statements for disclosures on the Company’s reportable segments. All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who then transport the Company’s production to foreign countries for resale or consumption.
Earnings (loss) Per Common Share	(u) Earnings (loss) Per Common Share Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is anti- dilutive . The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ Basic weighted average number of shares outstanding ​ 315,426 ​ 316,036 ​ 306,400 ​ Add: Dilutive effect of restricted stock units ​ 817 ​ — ​ — ​ Add: Dilutive effect of outstanding stock options ​ — ​ — ​ — ​ Add: Dilutive effect of performance stock units ​ 40 ​ — ​ — ​ Diluted weighted average number of shares outstanding ​ 316,283 ​ 316,036 ​ 306,400 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1) ​ ​ ​ ​ ​ ​ ​ Restricted stock units ​ 1,521 ​ 2,844 ​ 2,357 ​ Outstanding stock options ​ 676 ​ 626 ​ 527 ​ Performance stock units ​ 1,054 ​ 1,705 ​ 1,443 ​ (1)
Treasury Share Retirement	(v) Treasury Share Retirement The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares issued, to the balance of additional paid-in capital as of retirement.
Recently Issued Accounting Standards	(w) Recently Issued Accounting Standards In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement: Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement,” which provides changes to certain fair value disclosure requirements. This ASU is effective for annual reporting periods beginning after December 15, 2019 and interim periods within those annual periods, with early adoption permitted. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements.
Equity-Based Compensation	(x)  Equity-Based Compensation We recognize compensation cost related to all equity-based awards in the financial statements based on their estimated grant date fair value. We are to grant various types of equity-based compensation awards including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The grant date fair values are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations, or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note 9 for additional information regarding our equity-based compensation.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales)	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2017 ​ ​ 2018 ​ ​ 2019 ​ Company A ​ 4 % ​ 8 % ​ 16 % Company B ​ 14 ​ ​ 6 ​ ​ 15 ​ Company C ​ 20 ​ ​ 13 ​ ​ 9 ​ Company D ​ — ​ ​ 14 ​ ​ 3 ​ All others ​ 62 ​ ​ 59 ​ ​ 57 ​ ​ ​ 100 % ​ 100 % ​ 100 %
Reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding	The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ Basic weighted average number of shares outstanding ​ 315,426 ​ 316,036 ​ 306,400 ​ Add: Dilutive effect of restricted stock units ​ 817 ​ — ​ — ​ Add: Dilutive effect of outstanding stock options ​ — ​ — ​ — ​ Add: Dilutive effect of performance stock units ​ 40 ​ — ​ — ​ Diluted weighted average number of shares outstanding ​ 316,283 ​ 316,036 ​ 306,400 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1) ​ ​ ​ ​ ​ ​ ​ Restricted stock units ​ 1,521 ​ 2,844 ​ 2,357 ​ Outstanding stock options ​ 676 ​ 626 ​ 527 ​ Performance stock units ​ 1,054 ​ 1,705 ​ 1,443 ​ (1)

Deconsolidation of Antero Mid_2

Deconsolidation of Antero Midstream Partners LP (Tables)	12 Months Ended
	Dec. 31, 2019
Deconsolidation of Antero Midstream Partners LP
Summary of summary of assets and liabilities of Antero Midstream Partners as of March 12, 2019, the date of deconsolidation	​ ​ ​ ​ ​ ​ (in thousands) ​ March 12, 2019 ​ Current assets ​ $ 763,109 ​ Property and equipment, net ​ ​ 3,003,693 ​ Other noncurrent assets ​ ​ 501,208 ​ Total assets ​ $ 4,268,010 ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 123,473 ​ Long-term debt ​ ​ 2,359,084 ​ Other noncurrent liabilities ​ ​ 123,523 ​ Total liabilities ​ $ 2,606,080 ​ ​ ​ ​ ​ ​ Net assets ​ $ 1,661,930 ​

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue
Schedule of disaggregation of revenue	Revenue is disaggregated by type (in thousands) in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. For more information on reportable segments, see Note 18—Segment Information. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Segment to which ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ revenues relate ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,769,284 ​ $ 2,287,939 ​ ​ 2,247,162 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 93,041 ​ ​ 172,653 ​ ​ 124,563 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 777,400 ​ ​ 1,005,124 ​ ​ 1,094,599 ​ Exploration and production ​ Oil sales ​ ​ 108,195 ​ ​ 187,178 ​ ​ 177,549 ​ Exploration and production ​ Gathering and compression (1) ​ ​ 11,386 ​ ​ 17,817 ​ 3,972 ​ Equity method investment in AMC ​ Water handling and treatment (1) ​ ​ 1,334 ​ ​ 3,527 ​ ​ 506 ​ Equity method investment in AMC ​ Marketing ​ ​ 258,045 ​ ​ 458,901 ​ ​ 292,207 ​ Marketing ​ Total ​ ​ 3,018,685 ​ ​ 4,133,139 ​ 3,940,558 ​ ​ ​ Revenue from derivatives and other sources ​ ​ 636,889 ​ ​ 6,487 ​ ​ 468,132 ​ ​ ​ Total revenue and other ​ $ 3,655,574 ​ $ 4,139,626 ​ ​ 4,408,690 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3 to the consolidated financial statements for further discussion on the Transactions. ​

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2019
Equity Method Investments.
Schedule of reconciliation of investments in unconsolidated affiliates	The following table is a reconciliation of investments in unconsolidated affiliates for the years ending December 31, 2018 and 2019 in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ MarkWest ​ Antero Midstream ​ ​ ​ ​ ​ Stonewall (1) ​ Joint Venture ​ Corporation (2) ​ Total ​ Balance at December 31, 2017 ​ $ 67,128 ​ ​ 236,174 ​ ​ — ​ ​ 303,302 ​ Investments (3) ​ — ​ ​ 136,475 ​ ​ — ​ ​ 136,475 ​ Equity in net income of unconsolidated affiliates ​ ​ 10,740 ​ ​ 29,540 ​ ​ — ​ ​ 40,280 ​ Distributions from unconsolidated affiliates ​ (9,765) ​ ​ (36,650) ​ ​ — ​ ​ (46,415) ​ Balance at December 31, 2018 ​ $ 68,103 ​ ​ 365,539 ​ ​ — ​ ​ 433,642 ​ Investments (3) ​ — ​ ​ 25,020 ​ ​ — ​ ​ 25,020 ​ Equity in net income (loss) of unconsolidated affiliates ​ ​ 1,894 ​ ​ 10,370 ​ ​ (155,480) ​ ​ (143,216) ​ Distributions/dividends from unconsolidated affiliates ​ (3,000) ​ ​ (9,605) ​ ​ (145,351) ​ ​ (157,956) ​ Return of investment (4) ​ ​ — ​ ​ — ​ ​ (208,745) ​ ​ (208,745) ​ Impairment (5) ​ ​ — ​ ​ — ​ ​ (467,590) ​ ​ (467,590) ​ Elimination of intercompany profit ​ ​ — ​ ​ — ​ ​ 44,548 ​ ​ 44,548 ​ Effects of deconsolidation (6) ​ (66,997) ​ ​ (391,324) ​ ​ 1,987,795 ​ ​ 1,529,474 ​ Balance at December 31, 2019 ​ $ — ​ ​ — ​ ​ 1,055,177 ​ ​ 1,055,177 ​ (1) Distributions are net of operating and capital requirements retained by Stonewall. (2) As adjusted for the amortization of the difference between the cost of the equity investment in Antero Midstream Corporation and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation and as adjusted for the return of investment. (3) Investments in the Joint Venture during the year ended December 31, 2019 relate to capital contributions for construction of additional processing facilities. (4) In December 2019, Antero Midstream Corporation repurchased $100 million of its shares of common stock from the Company resulting in a return of investment. The Company recorded an $109 million loss on investment due to the carrying value exceeding the fair value of the stock repurchased. (5) Other-than-temporary impairment in Antero Midstream Corporation recorded as of December 31, 2019 to reduce the carrying value to fair value. (6) Effective March 13, 2019, the equity in earnings of Stonewall and the Joint Venture are accounted for in the equity in earnings of Antero Midstream Corporation.
Schedule of summarized financial information of Antero Midstream Corporation	Balance Sheet ​ ​ ​ ​ ​ ​ ​ December 31, ​ (in thousands) ​ 2019 ​ Current assets ​ $ 108,558 ​ Noncurrent assets ​ ​ 6,174,320 ​ Total assets ​ $ 6,282,878 ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 242,084 ​ Noncurrent liabilities ​ ​ 2,897,380 ​ Stockholders' equity ​ ​ 3,143,414 ​ Total liabilities and equity ​ $ 6,282,878 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ For the period ​ ​ ​ March 13, 2019 ​ ​ ​ through ​ (in thousands) ​ December 31, 2019 ​ Revenues ​ $ 792,588 ​ Operating expenses ​ ​ 1,177,610 ​ Loss from operations ​ $ (385,022) ​ Net loss attributable to the equity method investments ​ $ (341,565) ​

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities as of December 31, 2018 and 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2018 2019 ​ Capital expenditures ​ $ 113,237 ​ 105,706 ​ Gathering, compression, processing, and transportation expenses ​ ​ 148,032 ​ ​ 134,153 ​ Marketing expenses ​ ​ 67,082 ​ ​ 52,612 ​ Interest expense, net ​ 43,444 ​ 30,834 ​ Other ​ 93,275 ​ 77,545 ​ Total accrued liabilities ​ $ 465,070 ​ 400,850 ​

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Long-Term Debt.
Schedule of long-term debt	Long-term debt as of December 31, 2018 and 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ 2018 2019 Antero Resources: ​ ​ ​ ​ ​ ​ Credit Facility (a) ​ $ 405,000 ​ 552,000 5.375% senior notes due 2021 (b) ​ 1,000,000 ​ 952,500 5.125% senior notes due 2022 (c) ​ ​ 1,100,000 ​ ​ 923,041 5.625% senior notes due 2023 (d) ​ ​ 750,000 ​ ​ 750,000 5.00% senior notes due 2025 (e) ​ ​ 600,000 ​ ​ 600,000 Net unamortized premium ​ 1,241 ​ 791 Net unamortized debt issuance costs ​ ​ (26,700) ​ ​ (19,464) Long-term debt ​ ​ 3,829,541 ​ ​ 3,758,868 Antero Midstream Partners: (1) ​ ​ ​ ​ ​ ​ Midstream Credit Facility ​ ​ 990,000 ​ ​ — 5.375% senior notes due 2024 ​ ​ 650,000 ​ ​ — Net unamortized debt issuance costs ​ ​ (7,853) ​ ​ — Long-term debt ​ ​ 1,632,147 ​ ​ — Consolidated long-term debt ​ $ 5,461,688 ​ 3,758,868 (1) At December 31, 2018, Antero Midstream Partners’ indebtedness was included in the consolidated financial statements of Antero. At December 31, 2019, following the deconsolidation, Antero Midstream Partners’ outstanding indebtedness is no longer reflected in Antero Resources’ consolidated financial statements. See Note 3 to the consolidated financial statements for further discussion on the Transactions. ​

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations
Schedule of reconciliation of asset retirement obligations	The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 ​ 2019 ​ Asset retirement obligations—December 31, 2018 ​ $ 34,610 ​ ​ 58,979 ​ Obligations settled ​ ​ — ​ ​ (153) ​ Obligations incurred ​ 9,981 ​ ​ 2,312 ​ Revisions to prior estimates ​ ​ 11,569 ​ ​ (2,537) ​ Accretion expense ​ 2,819 ​ ​ 3,762 ​ Effect of deconsolidation of Antero Midstream Partners LP (1) ​ — ​ ​ (7,518) ​ Asset retirement obligations—December 31, 2019 ​ $ 58,979 ​ ​ 54,845 ​ (1) Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero Resources’ results.

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Equity-Based Compensation
Schedule of equity-based compensation expense	The Company’s equity-based compensation expense, by type of award, was as follows for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ 2017 ​ 2018 ​ 2019 ​ Restricted stock unit awards ​ $ 70,866 ​ ​ 41,505 ​ ​ 10,343 ​ Stock options ​ ​ 2,375 ​ ​ 1,799 ​ ​ 355 ​ Performance share unit awards ​ ​ 10,797 ​ ​ 9,659 ​ ​ 8,069 ​ Antero Midstream Partners phantom unit awards (1) ​ ​ 17,461 ​ ​ 15,351 ​ ​ 3,425 ​ Equity awards issued to directors ​ ​ 1,946 ​ ​ 2,100 ​ ​ 1,367 ​ Total expense ​ $ 103,445 ​ ​ 70,414 ​ ​ 23,559 ​ (1) Antero Resources recognized compensation expense for equity awards granted under both the Plan and the AMP Plan because the awards under the AMP Plan are accounted for as if they are distributed by Antero Midstream Partners to Antero Resources. Antero Resources allocates a portion of equity-based compensation expense related to grants prior to the Transactions to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. Through March 12, 2019, the total amount of equity-based compensation is included in the consolidated financial statements of Antero Resources; and effective March 13, 2019 (date of deconsolidation), the amount allocated to Antero Midstream Partners is no longer reflected in Antero Resources’ consolidated financial statements. See Note 3 to the consolidated financial statements for further discussion on the Transactions.
Summary of restricted stock and restricted stock unit awards activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ Aggregate ​ ​ ​ Number of ​ grant date ​ intrinsic value ​ ​ shares fair value (in thousands) ​ Total awarded and unvested—December 31, 2018 1,712,485 ​ $ 24.57 ​ $ 16,080 ​ Granted 1,745,784 ​ $ 8.14 ​ ​ ​ ​ Vested (730,343) ​ $ 27.60 ​ ​ ​ ​ Forfeited (357,351) ​ $ 16.09 ​ ​ ​ ​ Total awarded and unvested—December 31, 2019 2,370,575 ​ $ 12.81 ​ $ 6,756 ​
Summary of stock option activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ average ​ remaining ​ Intrinsic ​ ​ ​ Stock ​ exercise ​ contractual ​ value ​ ​ options price ​ life (in thousands) Outstanding at December 31, 2018 579,617 ​ $ 50.55 ​ 5.81 ​ $ — ​ Granted — ​ $ — ​ ​ ​ ​ ​ ​ Exercised — ​ $ — ​ ​ ​ ​ ​ ​ Forfeited (4,250) ​ $ 50.18 ​ ​ ​ ​ ​ ​ Expired/Cancelled (107,734) ​ $ — ​ ​ ​ ​ ​ ​ Outstanding at December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​ Vested or expected to vest as of December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​ Exercisable at December 31, 2019 467,633 ​ $ 50.64 ​ 5.05 ​ $ — ​
Summary of Performance Stock Unit activity	A summary of PSU activity for the year ended December 31, 2019 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average ​ ​ ​ Number of ​ grant date ​ ​ ​ units ​ fair value ​ Total awarded and unvested—December 31, 2018 1,767,299 ​ $ 26.36 ​ Granted 1,416,378 ​ $ 9.26 ​ Exercised ​ (31,944) ​ $ 27.38 ​ Cancelled - Unearned (326,938) ​ $ 32.97 ​ Forfeited (287,512) ​ $ 19.38 ​ Total awarded and unvested—December 31, 2019 2,537,283 ​ $ 16.74 ​
Schedule of weighted average fair value assumptions used for PSUs granted	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ ​ 2018 ​ ​ 2019 ​ ​ Dividend yield ​ ​ — % ​ ​ — % ​ Volatility ​ ​ 41 % ​ ​ 36 % ​ Risk-free interest rate ​ ​ 2.49 % ​ ​ 2.35 % ​ Weighted average fair value of awards granted ​ $ 24.85 ​ ​ $ 9.26 ​ ​
Schedule of outstanding unvested restricted stock awards vesting schedule	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ Aggregate ​ ​ ​ Number of ​ average grant ​ intrinsic value ​ ​ ​ units ​ date fair value ​ (in thousands) ​ Total awarded and unvested—December 31, 2018 583,000 ​ $ 27.63 ​ $ 12,470 ​ Granted 5,972 ​ $ 23.44 ​ ​ ​ ​ Vested (3,853) ​ $ 32.44 ​ ​ ​ ​ Forfeited (20,338) ​ $ 26.73 ​ ​ ​ ​ AMP Plan Units awarded and unvested—March 12, 2019 ​ 564,781 ​ $ 27.59 ​ $ 13,476 ​ Effect of conversion (1) 504,119 ​ $ 14.58 ​ ​ ​ ​ Vested (362,191) ​ $ 14.35 ​ ​ ​ ​ Forfeited (48,952) ​ $ 14.51 ​ ​ ​ ​ Total awarded and unvested—December 31, 2019 657,757 ​ $ 14.71 ​ $ 4,992 ​ (1)

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments.
Schedule of outstanding commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural ​ ​ ​ ​ Weighted ​ ​ ​ Natural gas ​ ​ Gas Liquids ​ ​ Oil ​ average index ​ ​ ​ MMBtu/day ​ ​ Bbls/day ​ ​ Bbls/day ​ price ​ Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ FEI Propane ($/Gal) ​ — ​ ​ 9,883 ​ ​ — ​ $ 0.81 ​ Mont Belvieu Butane Non-TET ($/Gal) ​ — ​ ​ 6,000 ​ ​ — ​ ​ 0.50 ​ Mont Belvieu Propane Non-TET ($/Gal) ​ — ​ ​ 1,500 ​ ​ — ​ ​ 0.58 ​ Total ​ — ​ ​ 17,383 ​ ​ — ​ ​ ​ ​ Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 2,227,500 ​ ​ — ​ ​ — ​ $ 2.87 ​ ARA Propane ($/Gal) ​ — ​ ​ 10,371 ​ ​ — ​ ​ 0.65 ​ NYMEX-WTI ($/Bbl) ​ — ​ ​ — ​ ​ 26,000 ​ ​ 55.63 ​ Total ​ 2,227,500 ​ ​ 10,371 ​ ​ 26,000 ​ ​ ​ ​ Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 2,400,000 ​ ​ ​ ​ ​ ​ ​ $ 2.80 ​ Year ending December 31, 2023: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ NYMEX ($/MMBtu) ​ 90,000 ​ ​ ​ ​ ​ ​ ​ $ 2.91 ​
Schedule of natural gas basis swap positions which settle on pricing index to basis differential of NYMEX to TCO	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Weighted ​ ​ Natural Gas ​ Liquids ​ average hedged ​ ​ MMBtu/day ​ Bbls/day ​ differential Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ ​ ARA to Mont Belvieu Non-TET ($/Gal) ​ ​ ​ 2,670 ​ $ 0.24 Three months ending June 30, 2020: ​ ​ ​ ​ ​ ​ ​ ARA to Mont Belvieu Non-TET ($/Gal) ​ ​ ​ 1,602 ​ $ 0.22 Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 60,000 ​ ​ ​ $ 0.35 Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 40,000 ​ — ​ $ 0.41 Year ending December 31, 2022: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 60,000 ​ — ​ $ 0.52 Year ending December 31, 2023: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 50,000 ​ — ​ $ 0.53 Year ending December 31, 2024: ​ ​ ​ ​ ​ ​ ​ NYMEX to TCO ($/MMBtu) ​ 50,000 ​ — ​ $ 0.53
Tabular disclosure of commodity derivatives basis differential positions which settle on the pricing index to basis differential of Columbia Gas (TCO) to the NYMEX Henry Hub natural gas price.	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gas ​ Weighted ​ ​ ​ ​ Liquids ​ average payout ​ ​ ​ ​ Bbls/day ​ ratio ​ ​ Three months ending March 31, 2020: ​ ​ ​ ​ ​ ​ Mont Belvieu Propane to NYMEX-WTI ​ 500 ​ 50% ​ ​ Year ending December 31, 2020: ​ ​ ​ ​ ​ ​ Mont Belvieu Natural Gasoline to NYMEX-WTI ​ 18,800 ​ 80% ​ ​ Year ending December 31, 2021: ​ ​ ​ ​ ​ ​ Mont Belvieu Natural Gasoline to NYMEX-WTI ​ 18,650 ​ 78% ​ ​
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ December 31, 2019 ​ ​ ​ Balance sheet ​ ​ ​ Balance sheet ​ ​ ​ ​ ​ location ​ Fair value ​ location ​ Fair value ​ ​ ​ ​ ​ (In thousands) ​ ​ ​ (In thousands) ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives - current ​ Derivative instruments ​ $ 245,263 ​ Derivative instruments ​ $ 422,849 ​ Commodity derivatives - noncurrent ​ Derivative instruments ​ ​ 362,169 ​ Derivative instruments ​ ​ 333,174 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives ​ ​ ​ ​ 607,432 ​ ​ ​ ​ 756,023 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives - current ​ Derivative instruments ​ ​ 532 ​ Derivative instruments ​ ​ 6,721 ​ Commodity derivatives - noncurrent ​ Derivative instruments ​ ​ — ​ Derivative instruments ​ ​ 3,519 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives ​ ​ ​ ​ 532 ​ ​ ​ ​ 10,240 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives ​ ​ ​ $ 606,900 ​ ​ ​ $ 745,783 ​
Schedule of gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts	​ The following table presents the gross values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ December 31, 2019 ​ ​ ​ ​ ​ ​ ​ Net amounts ​ ​ ​ ​ ​ Net amounts ​ ​ Gross ​ Gross ​ of assets ​ Gross ​ Gross ​ of assets ​ ​ ​ amounts on ​ amounts offset on ​ (liabilities) on ​ amounts on ​ amounts offset on ​ (liabilities) on ​ ​ ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet ​ balance sheet Commodity derivative assets ​ $ 658,830 ​ (51,398) ​ 607,432 ​ $ 882,817 ​ (126,794) ​ 756,023 ​ Commodity derivative liabilities ​ $ (51,930) ​ 51,398 ​ (532) ​ $ (137,034) ​ 126,794 ​ (10,240) ​
Summary of derivative fair value gains (losses)	The following is a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ operations ​ Year ended December 31, ​ ​ ​ location ​ 2017 ​ 2018 ​ 2019 ​ Commodity derivative fair value gains (losses) ​ Revenue ​ $ 658,283 ​ ​ (87,594) ​ ​ 463,972 ​ Marketing derivative fair value gains (losses) ​ Revenue ​ $ (21,394) ​ ​ 94,081 ​ ​ — ​

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases
Summary of supplemental balance sheet information related to leases	​ The Company’s lease assets as of December 31, 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Right-of-use Assets: ​ ​ ​ ​ ​ ​ ​ Processing plants ​ $ 1,460,770 ​ ​ — ​ Drilling rigs and completion services ​ ​ 71,662 ​ ​ — ​ Gas gathering lines and compressor stations (1) ​ ​ 1,308,428 ​ ​ — ​ Office space ​ ​ 40,491 ​ ​ — ​ Vehicles ​ ​ 4,983 ​ ​ 2,328 ​ Other office and field equipment ​ ​ 166 ​ ​ 170 ​ Total right-of-use assets ​ $ 2,886,500 ​ ​ 2,498 (2) (1) (2) ​ The Company’s lease liabilities as of December 31, 2019 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Location on the balance sheet: ​ ​ ​ ​ ​ ​ ​ Short-term lease ​ $ 304,398 ​ ​ 923 ​ Long-term lease ​ ​ 2,582,102 ​ ​ 1,575 ​ Total lease ​ $ 2,886,500 ​ ​ 2,498 ​
Summary of costs associated with operating leases	Costs associated with operating leases were included in the statement of operations and comprehensive income (loss) for the year ended December 31, 2019 (in thousands): ​ ​ ​ ​ ​ Statement of Operations Location ​ Year ended December 31, 2019 ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ General and administrative ​ ​ 11,228 ​ Contract termination and rig stacking ​ ​ 10,692 ​ Total Lease Expense ​ $ 864,360 ​
Summary of supplemental cash flow information related to leases	The following is the Company’s supplemental cash flow information related to leases for year ended December 31, 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ Operating cash out flows related to operating leases ​ $ 809,667 ​ ​ — ​ Investing cash out flows related to operating leases ​ ​ 178,898 ​ ​ — ​ Financing cash out flows related to financing leases ​ ​ — ​ ​ 2,507 ​ ​ ​ $ 988,565 ​ ​ 2,507 ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ Right of use assets obtained in exchange for operating lease liabilities ​ $ 3,720,945 ​ ​ — ​ Right of use assets obtained in exchange for financing lease liabilities ​ $ — ​ ​ — ​ ​
Summary of maturities of operating lease liabilities	The table below is a schedule of future minimum payments for operating and financing lease liabilities as of December 31, 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2020 ​ $ 622,056 ​ ​ 244 ​ ​ 622,300 ​ 2021 ​ ​ 554,000 ​ ​ 1,007 ​ ​ 555,007 ​ 2022 ​ ​ 542,952 ​ ​ 1,205 ​ ​ 544,157 ​ 2023 ​ ​ 538,771 ​ ​ 42 ​ ​ 538,813 ​ 2024 ​ ​ 530,003 ​ ​ — ​ ​ 530,003 ​ Thereafter ​ ​ 1,851,738 ​ ​ — ​ ​ 1,851,738 ​ Total lease payments ​ ​ 4,639,520 ​ ​ 2,498 ​ ​ 4,642,018 ​ Less: imputed interest ​ ​ (1,753,020) ​ ​ — ​ ​ (1,753,020) ​ Total ​ $ 2,886,500 ​ ​ 2,498 ​ ​ 2,888,998 ​ ​ As of December 31, 2019, the following future minimum payments were required for office and equipment leases: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Office Leases ​ Equipment Leases ​ Total ​ 2020 ​ $ 6,145 ​ ​ 3,916 ​ ​ 10,061 ​ 2021 ​ ​ 6,071 ​ ​ 2,931 ​ ​ 9,002 ​ 2022 ​ ​ 6,027 ​ ​ 1,205 ​ ​ 7,232 ​ 2023 ​ ​ 4,761 ​ ​ 42 ​ ​ 4,803 ​ 2024 ​ ​ 4,792 ​ ​ — ​ ​ 4,792 ​ Thereafter ​ ​ 27,258 ​ ​ — ​ ​ 27,258 ​ Total lease payments ​ ​ 55,054 ​ ​ 8,094 ​ ​ 63,148 ​ Less: imputed interest ​ ​ (14,562) ​ ​ (447) ​ ​ (15,009) ​ Total ​ $ 40,492 ​ ​ 7,647 ​ ​ 48,139 ​
Summary of maturities of financing lease liabilities	The table below is a schedule of future minimum payments for operating and financing lease liabilities as of December 31, 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2020 ​ $ 622,056 ​ ​ 244 ​ ​ 622,300 ​ 2021 ​ ​ 554,000 ​ ​ 1,007 ​ ​ 555,007 ​ 2022 ​ ​ 542,952 ​ ​ 1,205 ​ ​ 544,157 ​ 2023 ​ ​ 538,771 ​ ​ 42 ​ ​ 538,813 ​ 2024 ​ ​ 530,003 ​ ​ — ​ ​ 530,003 ​ Thereafter ​ ​ 1,851,738 ​ ​ — ​ ​ 1,851,738 ​ Total lease payments ​ ​ 4,639,520 ​ ​ 2,498 ​ ​ 4,642,018 ​ Less: imputed interest ​ ​ (1,753,020) ​ ​ — ​ ​ (1,753,020) ​ Total ​ $ 2,886,500 ​ ​ 2,498 ​ ​ 2,888,998 ​ ​ As of December 31, 2019, the following future minimum payments were required for office and equipment leases: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Office Leases ​ Equipment Leases ​ Total ​ 2020 ​ $ 6,145 ​ ​ 3,916 ​ ​ 10,061 ​ 2021 ​ ​ 6,071 ​ ​ 2,931 ​ ​ 9,002 ​ 2022 ​ ​ 6,027 ​ ​ 1,205 ​ ​ 7,232 ​ 2023 ​ ​ 4,761 ​ ​ 42 ​ ​ 4,803 ​ 2024 ​ ​ 4,792 ​ ​ — ​ ​ 4,792 ​ Thereafter ​ ​ 27,258 ​ ​ — ​ ​ 27,258 ​ Total lease payments ​ ​ 55,054 ​ ​ 8,094 ​ ​ 63,148 ​ Less: imputed interest ​ ​ (14,562) ​ ​ (447) ​ ​ (15,009) ​ Total ​ $ 40,492 ​ ​ 7,647 ​ ​ 48,139 ​
Summary of weighted-average remaining lease term and discount rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ ​ ​ Operating Leases ​ Finance Leases ​ Weighted-average remaining lease term: ​ ​ 8.7 years ​ ​ 2.1 years ​ Weighted-average discount rate: ​ ​ 11.5 % ​ 6.0 %

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Taxes
Schedule of income tax expense from continuing operations	For the years ended December 31, 2017, 2018 and 2019, income tax expense (benefit) consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ 2017 2018 2019 Current income tax expense (benefit) ​ $ 75 ​ ​ — ​ ​ 5,048 ​ Deferred income tax benefit ​ (295,126) ​ (128,857) ​ (79,158) ​ Total income tax benefit ​ $ (295,051) ​ ​ (128,857) ​ ​ (74,110) ​
Schedule of reconciliation of income tax expense from continuing operations	Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to the year ended December 31, 2017 and 21% to the years ended December 31, 2018 and 2019 to income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ 2017 2018 2019 Federal income tax expense (benefit) ​ $ 171,530 ​ ​ (36,657) ​ ​ (77,122) ​ State income tax expense (benefit), net of federal benefit ​ 10,779 ​ (12,627) ​ (8,826) ​ Change in Federal tax rate, net of state benefit (1) ​ ​ (427,962) ​ ​ — ​ ​ — ​ Change in State tax rate, net of federal effect ​ ​ — ​ ​ (40,415) ​ ​ 24,041 ​ Nondeductible equity-based compensation ​ 12,098 ​ 6,079 ​ 6,920 ​ Dividends received deduction ​ ​ — ​ ​ — ​ ​ (4,201) ​ Noncontrolling interest in Antero Midstream Partners ​ ​ (59,523) ​ ​ (73,881) ​ ​ (10,998) ​ Deconsolidation adjustment ​ ​ — ​ ​ — ​ ​ (6,626) ​ Change in valuation allowance ​ (2,073) ​ 28,116 ​ 1,325 ​ Other ​ 100 ​ 528 ​ 1,377 ​ Total income tax benefit ​ $ (295,051) ​ ​ (128,857) ​ ​ (74,110) ​ (1) The change in the Federal tax rate was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. The passage of this legislation resulted in the Company generating a deferred tax benefit in 2017 primarily due to the reduction in the U.S. statutory rate from 35% to 21% .
Schedule of net deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2019 Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ Net operating loss carryforwards ​ $ 734,255 ​ ​ 560,136 ​ Equity-based compensation ​ ​ 10,633 ​ ​ 7,669 ​ Investment in Antero Midstream ​ ​ — ​ ​ 172,460 ​ Other ​ ​ 15,726 ​ ​ 15,754 ​ Total deferred tax assets ​ ​ 760,614 ​ ​ 756,019 ​ Valuation allowance ​ ​ (45,477) ​ ​ (46,802) ​ Net deferred tax assets ​ ​ 715,137 ​ ​ 709,217 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 271,747 ​ ​ 206,677 ​ Oil and gas properties ​ ​ 1,055,850 ​ ​ 1,284,528 ​ Investment in Antero Midstream Partners ​ ​ 11,258 ​ ​ — ​ Other ​ ​ 27,070 ​ ​ — ​ Total deferred tax liabilities ​ ​ 1,365,925 ​ ​ 1,491,205 ​ Net deferred tax liabilities ​ $ (650,788) ​ ​ (781,987) ​

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2019
Commitments
Schedule of future minimum payments for firm transportation, drilling rig and completion services, gas processing, gathering and compression, office and equipment agreements, and leases that have remaining lease terms in excess of one year	The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, which include leases that have remaining lease terms in excess of one year as of December 31, 2019 (in thousands). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Firm ​ gathering and ​ Land payment ​ Operating and ​ Imputed Interest ​ ​ ​ ​ ​ transportation ​ compression ​ obligations ​ Financing Leases ​ for Leases ​ ​ ​ ​ ​ (a) ​ (b) ​ (c) ​ (d) ​ (d) ​ Total ​ 2020 ​ $ 1,105,062 ​ ​ 55,338 ​ ​ 5,240 ​ ​ 304,441 ​ ​ 317,859 ​ ​ 1,787,940 ​ 2021 ​ ​ 1,076,832 ​ ​ 54,154 ​ ​ 2,859 ​ ​ 265,838 ​ ​ 289,169 ​ ​ 1,688,852 ​ 2022 ​ ​ 1,034,009 ​ ​ 53,606 ​ ​ 328 ​ ​ 285,209 ​ ​ 258,948 ​ ​ 1,632,100 ​ 2023 ​ ​ 1,056,902 ​ ​ 58,565 ​ ​ — ​ ​ 313,510 ​ ​ 225,303 ​ ​ 1,654,280 ​ 2024 ​ ​ 1,016,856 ​ ​ 58,687 ​ ​ — ​ ​ 342,348 ​ ​ 187,655 ​ ​ 1,605,546 ​ Thereafter ​ ​ 7,907,583 ​ ​ 152,523 ​ ​ — ​ ​ 1,377,652 ​ ​ 474,086 ​ ​ 9,911,844 ​ Total ​ $ 13,197,244 ​ ​ 432,873 ​ ​ 8,427 ​ ​ 2,888,998 ​ ​ 1,753,020 ​ ​ 18,280,562 ​

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
Segment Information
Schedule of operating results and assets of reportable segments	The operating results and assets of the Company’s reportable segments were as follows for the years ended December 31, 2017, 2018 and 2019 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ and ​ ​ ​ ​ ​ intersegment ​ Consolidated ​ ​ production ​ Marketing ​ Midstream ​ transactions ​ total Year ended December 31, 2017: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,406,203 ​ ​ 236,651 ​ ​ 12,720 ​ ​ — ​ 3,655,574 ​ Intersegment ​ 17,358 ​ ​ — ​ ​ 759,777 ​ ​ (777,135) ​ — ​ Total ​ $ 3,423,561 ​ 236,651 ​ 772,497 ​ (777,135) ​ 3,655,574 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 93,758 ​ ​ — ​ ​ 189,702 ​ ​ (194,403) ​ ​ 89,057 ​ Gathering, compression, processing, and transportation ​ ​ 1,441,129 ​ ​ — ​ ​ 39,147 ​ ​ (384,637) ​ 1,095,639 ​ Impairment of oil and gas properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Depletion, depreciation, and amortization ​ ​ 704,152 ​ ​ — ​ ​ 120,458 ​ ​ — ​ 824,610 ​ General and administrative ​ ​ 195,153 ​ ​ — ​ ​ 58,812 ​ ​ (2,769) ​ ​ 251,196 ​ Other ​ ​ 101,980 ​ ​ 366,281 ​ ​ 17,165 ​ ​ (13,476) ​ ​ 471,950 ​ Total ​ ​ 2,695,770 ​ ​ 366,281 ​ ​ 448,715 ​ ​ (595,285) ​ ​ 2,915,481 ​ Operating income (loss) ​ $ 727,791 ​ (129,630) ​ 323,782 ​ (181,850) ​ ​ 740,093 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 20,194 ​ ​ — ​ ​ 20,194 ​ Segment assets ​ $ 13,074,027 ​ ​ 36,701 ​ ​ 3,057,459 ​ ​ (906,697) ​ ​ 15,261,490 ​ Capital expenditures for segment assets ​ $ 1,859,481 ​ ​ — ​ ​ 540,719 ​ ​ (183,447) ​ ​ 2,216,753 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ ​ ​ intersegment ​ Consolidated ​ ​ production ​ Marketing ​ Midstream ​ transactions ​ total ​ Year ended December 31, 2018: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,565,300 ​ ​ 552,982 ​ ​ 21,344 ​ ​ — ​ 4,139,626 ​ Intersegment ​ (87,472) ​ ​ — ​ ​ 1,007,178 ​ ​ (919,706) ​ — ​ Total ​ $ 3,477,828 ​ 552,982 ​ 1,028,522 ​ (919,706) ​ 4,139,626 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 142,234 ​ ​ — ​ ​ 262,704 ​ ​ (268,785) ​ ​ 136,153 ​ Gathering, compression, processing, and transportation ​ ​ 1,792,898 ​ ​ — ​ ​ 49,550 ​ ​ (503,090) ​ 1,339,358 ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 9,658 ​ ​ — ​ ​ 9,658 ​ Depletion, depreciation, and amortization ​ ​ 841,645 ​ ​ — ​ ​ 130,820 ​ ​ — ​ 972,465 ​ General and administrative ​ ​ 181,305 ​ ​ — ​ ​ 61,629 ​ ​ (2,590) ​ ​ 240,344 ​ Other ​ ​ 129,947 ​ ​ 686,055 ​ ​ (88,715) ​ ​ 93,019 ​ ​ 820,306 ​ Total ​ ​ 3,637,466 ​ ​ 686,055 ​ ​ 425,646 ​ ​ (681,446) ​ ​ 4,067,721 ​ Operating income (loss) ​ $ (159,638) ​ (133,073) ​ 602,876 ​ (238,260) ​ ​ 71,905 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 40,280 ​ ​ — ​ ​ 40,280 ​ Segment assets ​ $ 12,986,945 ​ ​ 34,499 ​ ​ 3,542,862 ​ ​ (1,044,842) ​ ​ 15,519,464 ​ Capital expenditures for segment assets ​ $ 1,923,488 ​ ​ — ​ ​ 542,112 ​ ​ (255,014) ​ ​ 2,210,586 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ intersegment ​ ​ ​ ​ ​ ​ ​ ​ ​ Antero ​ transactions and ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ Midstream ​ unconsolidated ​ Consolidated ​ ​ and production ​ Marketing ​ Corporation ​ affiliates ​ total Year ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,107,845 ​ ​ 292,207 ​ ​ 50 ​ ​ — ​ 4,400,102 Intersegment ​ 5,812 ​ ​ — ​ ​ 792,538 ​ ​ (789,762) ​ 8,588 Total ​ $ 4,113,657 ​ 292,207 ​ 792,588 ​ (789,762) ​ 4,408,690 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 146,990 ​ ​ — ​ ​ 162,376 ​ ​ (163,646) ​ ​ 145,720 Gathering, compression, processing, and transportation ​ ​ 2,257,099 ​ ​ — ​ ​ 41,013 ​ ​ (151,465) ​ 2,146,647 Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 776,832 ​ ​ (762,050) ​ ​ 14,782 Depletion, depreciation, and amortization ​ ​ 893,161 ​ ​ — ​ ​ 95,526 ​ ​ (73,820) ​ 914,867 General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 118,113 ​ ​ (99,819) ​ ​ 178,696 Other ​ ​ 143,762 ​ ​ 549,814 ​ ​ 12,093 ​ ​ (11,090) ​ ​ 694,579 Total ​ ​ 4,901,858 ​ ​ 549,814 ​ ​ 1,205,953 ​ ​ (1,261,890) ​ ​ 5,395,735 Operating income (loss) ​ $ (788,201) ​ (257,607) ​ (413,365) ​ 472,128 ​ ​ (987,045) Equity in earnings (loss) of unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 51,315 ​ ​ (194,531) ​ ​ (143,216) Investments in unconsolidated affiliates ​ $ — ​ ​ — ​ ​ 709,639 ​ ​ 345,538 ​ ​ 1,055,177 Segment assets ​ $ 14,121,523 ​ ​ 20,869 ​ ​ 6,282,878 ​ ​ (5,227,701) ​ ​ 15,197,569 Capital expenditures for segment assets ​ $ 1,369,003 ​ ​ — ​ ​ 391,990 ​ ​ (338,838) ​ ​ 1,422,155

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2019
Condensed Consolidating Financial Information
Schedule of condensed consolidating balance sheets	Condensed Consolidating Balance Sheet December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts receivable, net ​ $ 49,529 ​ ​ — ​ ​ 1,544 ​ ​ — ​ ​ 51,073 ​ Intercompany receivables ​ ​ 383 ​ ​ — ​ ​ 115,378 ​ ​ (115,761) ​ ​ — ​ Accrued revenue ​ ​ 474,827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 474,827 ​ Derivative instruments ​ ​ 245,263 ​ ​ — ​ ​ — ​ ​ — ​ ​ 245,263 ​ Other current assets ​ ​ 13,937 ​ ​ — ​ ​ 21,513 ​ ​ — ​ ​ 35,450 ​ Total current assets ​ ​ 783,939 ​ ​ — ​ ​ 138,435 ​ ​ (115,761) ​ ​ 806,613 ​ Property and equipment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and gas properties, at cost (successful efforts method): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved properties ​ ​ 1,767,600 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,767,600 ​ Proved properties ​ ​ 13,306,585 ​ ​ — ​ ​ — ​ ​ (600,913) ​ ​ 12,705,672 ​ Water handling and treatment systems ​ ​ — ​ ​ — ​ ​ 1,004,793 ​ ​ 9,025 ​ ​ 1,013,818 ​ Gathering systems and facilities ​ ​ 17,825 ​ ​ — ​ ​ 2,452,883 ​ ​ — ​ ​ 2,470,708 ​ Other property and equipment ​ ​ 65,770 ​ ​ — ​ ​ 72 ​ ​ — ​ ​ 65,842 ​ ​ ​ ​ 15,157,780 ​ ​ — ​ ​ 3,457,748 ​ ​ (591,888) ​ ​ 18,023,640 ​ Less accumulated depletion, depreciation, and amortization ​ ​ (3,654,392) ​ ​ — ​ ​ (499,333) ​ ​ — ​ ​ (4,153,725) ​ Property and equipment, net ​ ​ 11,503,388 ​ ​ — ​ ​ 2,958,415 ​ ​ (591,888) ​ ​ 13,869,915 ​ Derivative instruments ​ ​ 362,169 ​ ​ — ​ ​ — ​ ​ — ​ ​ 362,169 ​ Investment in Antero Midstream Partners ​ ​ (740,031) ​ ​ — ​ ​ — ​ ​ 740,031 ​ ​ — ​ Contingent acquisition consideration ​ ​ 114,995 ​ ​ — ​ ​ — ​ ​ (114,995) ​ ​ — ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 433,642 ​ ​ — ​ ​ 433,642 ​ Other assets ​ ​ 31,200 ​ ​ — ​ ​ 15,925 ​ ​ — ​ ​ 47,125 ​ Total assets ​ $ 12,055,660 ​ ​ — ​ ​ 3,546,417 ​ ​ (82,613) ​ ​ 15,519,464 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities and Equity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable ​ $ 44,917 ​ ​ — ​ ​ 21,372 ​ ​ — ​ ​ 66,289 ​ Intercompany payable ​ ​ 111,620 ​ ​ — ​ ​ 4,141 ​ ​ (115,761) ​ ​ — ​ Accrued liabilities ​ ​ 392,949 ​ ​ — ​ ​ 72,121 ​ ​ — ​ ​ 465,070 ​ Revenue distributions payable ​ ​ 310,827 ​ ​ — ​ ​ — ​ ​ — ​ ​ 310,827 ​ Derivative instruments ​ ​ 532 ​ ​ — ​ ​ — ​ ​ — ​ ​ 532 ​ Short-term lease liabilities ​ ​ 2,459 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,459 ​ Other current liabilities ​ ​ 2,162 ​ ​ — ​ ​ 2,052 ​ ​ 4,149 ​ ​ 8,363 ​ Total current liabilities ​ ​ 865,466 ​ ​ — ​ ​ 99,686 ​ ​ (111,612) ​ ​ 853,540 ​ Long-term liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt ​ ​ 3,829,541 ​ ​ — ​ ​ 1,632,147 ​ ​ — ​ ​ 5,461,688 ​ Deferred income tax liability ​ ​ 650,788 ​ ​ — ​ ​ — ​ ​ — ​ ​ 650,788 ​ Contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 114,995 ​ ​ (114,995) ​ ​ — ​ Long-term lease liabilities ​ ​ 2,873 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,873 ​ Other liabilities ​ ​ 55,017 ​ ​ — ​ ​ 8,081 ​ ​ — ​ ​ 63,098 ​ Total liabilities ​ ​ 5,403,685 ​ ​ — ​ ​ 1,854,909 ​ ​ (226,607) ​ ​ 7,031,987 ​ Equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stockholders' equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Partners' capital ​ ​ — ​ ​ — ​ ​ 1,691,508 ​ ​ (1,691,508) ​ ​ — ​ Common stock ​ ​ 3,086 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,086 ​ Additional paid-in capital ​ ​ 5,471,341 ​ ​ — ​ ​ — ​ ​ 1,013,833 ​ ​ 6,485,174 ​ Accumulated earnings ​ ​ 1,177,548 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,177,548 ​ Total stockholders' equity ​ ​ 6,651,975 ​ ​ — ​ ​ 1,691,508 ​ ​ (677,675) ​ ​ 7,665,808 ​ Noncontrolling interests in consolidated subsidiary ​ ​ — ​ ​ — ​ ​ — ​ ​ 821,669 ​ ​ 821,669 ​ Total equity ​ ​ 6,651,975 ​ ​ — ​ ​ 1,691,508 ​ ​ 143,994 ​ ​ 8,487,477 ​ Total liabilities and equity ​ $ 12,055,660 ​ ​ — ​ ​ 3,546,417 ​ ​ (82,613) ​ ​ 15,519,464 ​ ​ Condensed Consolidating Balance Sheet December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Assets ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts receivable, net ​ ​ 46,419 ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,419 ​ Accounts receivable, related parties ​ ​ 125,000 ​ ​ 299,450 ​ ​ — ​ ​ (299,450) ​ ​ 125,000 ​ Accrued revenue ​ ​ 317,886 ​ ​ — ​ ​ — ​ ​ — ​ ​ 317,886 ​ Derivative instruments ​ ​ 422,849 ​ ​ — ​ ​ — ​ ​ — ​ ​ 422,849 ​ Other current assets ​ ​ 10,731 ​ ​ — ​ ​ — ​ ​ — ​ ​ 10,731 ​ Total current assets ​ ​ 922,885 ​ ​ 299,450 ​ ​ — ​ ​ (299,450) ​ ​ 922,885 ​ Property and equipment: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and gas properties, at cost (successful efforts method): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved properties ​ ​ 1,368,854 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,368,854 ​ Proved properties ​ ​ 11,859,817 ​ ​ — ​ ​ — ​ ​ — ​ ​ 11,859,817 ​ Gathering systems and facilities ​ ​ 5,802 ​ ​ — ​ ​ — ​ ​ — ​ ​ 5,802 ​ Other property and equipment ​ ​ 71,895 ​ ​ — ​ ​ — ​ ​ — ​ ​ 71,895 ​ ​ ​ ​ 13,306,368 ​ ​ — ​ ​ — ​ ​ — ​ ​ 13,306,368 ​ Less accumulated depletion, depreciation, and amortization ​ ​ (3,327,629) ​ ​ — ​ ​ ​ ​ ​ — ​ ​ (3,327,629) ​ Property and equipment, net ​ ​ 9,978,739 ​ ​ — ​ ​ — ​ ​ — ​ ​ 9,978,739 ​ Operating leases right-of-use assets ​ ​ 2,886,500 ​ ​ — ​ ​ ​ ​ ​ — ​ ​ 2,886,500 ​ Derivative instruments ​ ​ 333,174 ​ ​ — ​ ​ — ​ ​ — ​ ​ 333,174 ​ Investments in unconsolidated affiliates ​ ​ 243,048 ​ ​ 812,129 ​ ​ — ​ ​ — ​ ​ 1,055,177 ​ Investments in consolidated affiliates ​ ​ 812,129 ​ ​ — ​ ​ — ​ ​ (812,129) ​ ​ — ​ Other assets ​ ​ 21,094 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,094 ​ Total assets ​ $ 15,197,569 ​ ​ 1,111,579 ​ ​ — ​ ​ (1,111,579) ​ ​ 15,197,569 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities and Equity ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable ​ $ 14,498 ​ ​ — ​ ​ — ​ ​ — ​ ​ 14,498 ​ Accounts payable, related parties ​ ​ 397,333 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 97,883 ​ Accrued liabilities ​ ​ 400,850 ​ ​ — ​ ​ — ​ ​ — ​ ​ 400,850 ​ Revenue distributions payable ​ ​ 207,988 ​ ​ — ​ ​ — ​ ​ — ​ ​ 207,988 ​ Derivative instruments ​ ​ 6,721 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,721 ​ Short-term lease liabilities ​ ​ 305,320 ​ ​ — ​ ​ — ​ ​ — ​ ​ 305,320 ​ Other current liabilities ​ ​ 6,879 ​ ​ — ​ ​ — ​ ​ — ​ ​ 6,879 ​ Total current liabilities ​ ​ 1,339,589 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 1,040,139 ​ Long-term liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt ​ ​ 3,758,868 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,758,868 ​ Deferred income tax liability ​ ​ 781,987 ​ ​ — ​ ​ — ​ ​ — ​ ​ 781,987 ​ Derivative instruments ​ ​ 3,519 ​ ​ — ​ ​ — ​ ​ — ​ ​ 3,519 ​ Long-term lease liabilities ​ ​ 2,583,678 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,583,678 ​ Other liabilities ​ ​ 58,635 ​ ​ — ​ ​ — ​ ​ — ​ ​ 58,635 ​ Total liabilities ​ ​ 8,526,276 ​ ​ — ​ ​ — ​ ​ (299,450) ​ ​ 8,226,826 ​ Equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Stockholders' equity: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Common stock ​ ​ 2,959 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,959 ​ Additional paid-in capital ​ ​ 5,600,714 ​ ​ 1,341,780 ​ ​ — ​ ​ (812,129) ​ ​ 6,130,365 ​ Accumulated earnings ​ ​ 1,067,620 ​ ​ (230,201) ​ ​ — ​ ​ — ​ ​ 837,419 ​ Total stockholders' equity ​ ​ 6,671,293 ​ ​ 1,111,579 ​ ​ — ​ ​ (812,129) ​ ​ 6,970,743 ​ Total liabilities and equity ​ $ 15,197,569 ​ ​ 1,111,579 ​ ​ — ​ ​ (1,111,579) ​ ​ 15,197,569 ​
Schedule of condensed consolidating statement of operations and comprehensive income	Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2017 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Subsidiaries ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 1,769,975 ​ ​ — ​ ​ — ​ ​ (691) ​ ​ 1,769,284 ​ Natural gas liquids sales ​ 870,441 ​ ​ — ​ ​ — ​ ​ — ​ 870,441 ​ Oil sales ​ ​ 108,195 ​ ​ — ​ ​ — ​ ​ — ​ ​ 108,195 ​ Commodity derivative fair value gains ​ ​ 658,283 ​ ​ — ​ ​ — ​ ​ — ​ ​ 658,283 ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 772,497 ​ ​ (759,777) ​ ​ 12,720 ​ Marketing ​ ​ 258,045 ​ ​ — ​ ​ — ​ ​ — ​ ​ 258,045 ​ Marketing derivative loss ​ ​ (21,394) ​ ​ — ​ ​ — ​ ​ — ​ ​ (21,394) ​ Other income ​ ​ 16,667 ​ ​ — ​ ​ — ​ ​ (16,667) ​ ​ — ​ Total revenue and other ​ ​ 3,660,212 ​ ​ — ​ ​ 772,497 ​ ​ (777,135) ​ ​ 3,655,574 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 93,758 ​ ​ — ​ ​ 189,702 ​ ​ (194,403) ​ ​ 89,057 ​ Gathering, compression, processing, and transportation ​ ​ 1,441,129 ​ ​ — ​ ​ 39,147 ​ ​ (384,637) ​ ​ 1,095,639 ​ Production and ad valorem taxes ​ ​ 90,832 ​ ​ — ​ ​ 3,689 ​ ​ — ​ ​ 94,521 ​ Marketing ​ ​ 366,281 ​ ​ — ​ ​ — ​ ​ — ​ ​ 366,281 ​ Exploration ​ ​ 8,538 ​ ​ — ​ ​ — ​ ​ — ​ ​ 8,538 ​ Impairment of unproved properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of gathering systems and facilities ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Depletion, depreciation, and amortization ​ ​ 705,048 ​ ​ — ​ ​ 119,562 ​ ​ — ​ ​ 824,610 ​ Accretion of asset retirement obligations ​ ​ 2,610 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,610 ​ General and administrative ​ ​ 195,153 ​ ​ — ​ ​ 58,812 ​ ​ (2,769) ​ ​ 251,196 ​ Change in fair value of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 13,476 ​ ​ (13,476) ​ ​ — ​ Total operating expenses ​ ​ 3,062,947 ​ ​ — ​ ​ 447,819 ​ ​ (595,285) ​ ​ 2,915,481 ​ Operating income ​ ​ 597,265 ​ ​ — ​ ​ 324,678 ​ ​ (181,850) ​ ​ 740,093 ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 20,194 ​ ​ — ​ ​ 20,194 ​ Interest ​ ​ (232,331) ​ ​ — ​ ​ (37,262) ​ ​ 892 ​ ​ (268,701) ​ Loss on early extinguishment of debt ​ ​ (1,205) ​ ​ — ​ ​ (295) ​ ​ — ​ ​ (1,500) ​ Equity in earnings (loss) of Antero Midstream ​ ​ (43,710) ​ ​ — ​ ​ — ​ ​ 43,710 ​ ​ — ​ Total other expenses ​ ​ (277,246) ​ ​ — ​ ​ (17,363) ​ ​ 44,602 ​ ​ (250,007) ​ Income before income taxes ​ ​ 320,019 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 490,086 ​ Provision for income tax benefit ​ ​ 295,051 ​ ​ — ​ ​ — ​ ​ — ​ ​ 295,051 ​ Net income and comprehensive income including noncontrolling interests ​ ​ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 785,137 ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 170,067 ​ ​ 170,067 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ $ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (307,315) ​ ​ 615,070 ​ ​ Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,287,939 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,287,939 ​ Natural gas liquids sales ​ 1,177,777 ​ — ​ — ​ — ​ 1,177,777 ​ Oil sales ​ ​ 187,178 ​ ​ — ​ ​ — ​ ​ — ​ ​ 187,178 ​ Commodity derivative fair value losses ​ ​ (87,594) ​ ​ — ​ ​ — ​ ​ — ​ ​ (87,594) ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 1,027,939 ​ ​ (1,006,595) ​ ​ 21,344 ​ Marketing ​ ​ 458,901 ​ ​ — ​ ​ — ​ ​ — ​ ​ 458,901 ​ Marketing derivative fair value gains ​ ​ 94,081 ​ ​ — ​ ​ — ​ ​ — ​ ​ 94,081 ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ 583 ​ ​ (583) ​ ​ — ​ Other income ​ ​ (87,217) ​ ​ — ​ ​ — ​ ​ 87,217 ​ ​ — ​ Total revenue and other ​ ​ 4,031,065 ​ ​ — ​ ​ 1,028,522 ​ ​ (919,961) ​ ​ 4,139,626 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 142,234 ​ ​ — ​ ​ 262,704 ​ ​ (268,785) ​ ​ 136,153 ​ Gathering, compression, processing, and transportation ​ ​ 1,792,898 ​ ​ — ​ ​ 49,550 ​ ​ (503,090) ​ ​ 1,339,358 ​ Production and ad valorem taxes ​ ​ 122,305 ​ ​ — ​ ​ 4,169 ​ ​ — ​ ​ 126,474 ​ Marketing ​ ​ 686,055 ​ ​ — ​ ​ — ​ ​ — ​ ​ 686,055 ​ Exploration ​ ​ 4,958 ​ ​ — ​ ​ — ​ ​ — ​ ​ 4,958 ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ 4,470 ​ ​ — ​ ​ 5,771 ​ ​ (583) ​ ​ 9,658 ​ Depletion, depreciation, and amortization ​ ​ 842,452 ​ ​ — ​ ​ 130,013 ​ ​ — ​ ​ 972,465 ​ Accretion of asset retirement obligations ​ ​ 2,684 ​ ​ — ​ ​ 135 ​ ​ — ​ ​ 2,819 ​ General and administrative ​ ​ 181,305 ​ ​ — ​ ​ 61,629 ​ ​ (2,590) ​ ​ 240,344 ​ Accretion of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ (93,019) ​ ​ 93,019 ​ ​ — ​ Total operating expenses ​ ​ 4,328,798 ​ ​ — ​ ​ 420,952 ​ ​ (682,029) ​ ​ 4,067,721 ​ Operating income (loss) ​ ​ (297,733) ​ ​ — ​ ​ 607,570 ​ ​ (237,932) ​ ​ 71,905 ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 40,280 ​ ​ — ​ ​ 40,280 ​ Interest expense, net ​ ​ (224,977) ​ ​ — ​ ​ (61,906) ​ ​ 140 ​ ​ (286,743) ​ Equity in earnings (loss) of consolidated subsidiaries ​ ​ (3,664) ​ ​ — ​ ​ — ​ ​ 3,664 ​ ​ — ​ Total other expenses ​ ​ (228,641) ​ ​ — ​ ​ (21,626) ​ ​ 3,804 ​ ​ (246,463) ​ Income (loss) before income taxes ​ ​ (526,374) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (174,558) ​ Provision for income tax benefit ​ ​ 128,857 ​ ​ — ​ ​ — ​ ​ — ​ ​ 128,857 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interests ​ ​ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (45,701) ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 351,816 ​ ​ 351,816 ​ Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation ​ $ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (585,944) ​ ​ (397,517) ​ ​ Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Non-Guarantor ​ Eliminations ​ Consolidated ​ Revenue and other: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,247,162 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,247,162 ​ Natural gas liquids sales ​ 1,219,162 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,219,162 ​ Oil sales ​ ​ 177,549 ​ ​ — ​ ​ — ​ ​ — ​ ​ 177,549 ​ Commodity derivative fair value gains ​ ​ 463,972 ​ ​ — ​ ​ — ​ ​ — ​ ​ 463,972 ​ Gathering, compression, water handling and treatment ​ ​ — ​ ​ — ​ ​ 218,360 ​ ​ (213,882) ​ ​ 4,478 ​ Marketing ​ ​ 292,207 ​ ​ — ​ ​ — ​ ​ — ​ ​ 292,207 ​ Other income ​ ​ 5,810 ​ ​ — ​ ​ — ​ ​ (1,650) ​ ​ 4,160 ​ Total revenue and other ​ ​ 4,405,862 ​ ​ — ​ ​ 218,360 ​ ​ (215,532) ​ ​ 4,408,690 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 146,957 ​ ​ — ​ ​ 64,818 ​ ​ (66,055) ​ ​ 145,720 ​ Gathering, compression, processing, and transportation ​ ​ 2,257,133 ​ ​ — ​ ​ — ​ ​ (110,486) ​ ​ 2,146,647 ​ Production and ad valorem taxes ​ ​ 124,202 ​ ​ — ​ ​ — ​ ​ 940 ​ ​ 125,142 ​ Marketing ​ ​ 549,814 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,814 ​ Exploration ​ ​ 884 ​ ​ — ​ ​ — ​ ​ — ​ ​ 884 ​ Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 ​ Impairment of midstream assets ​ ​ 7,800 ​ ​ — ​ ​ 6,982 ​ ​ — ​ ​ 14,782 ​ Depletion, depreciation, and amortization ​ ​ 893,160 ​ ​ — ​ ​ 21,707 ​ ​ — ​ ​ 914,867 ​ Loss on sale of assets ​ ​ 951 ​ ​ — ​ ​ — ​ ​ — ​ ​ 951 ​ Accretion of asset retirement obligations ​ ​ 3,699 ​ ​ — ​ ​ 63 ​ ​ — ​ ​ 3,762 ​ General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 18,793 ​ ​ (499) ​ ​ 178,696 ​ Contract termination and rig stacking ​ ​ 14,026 ​ ​ — ​ ​ — ​ ​ — ​ ​ 14,026 ​ Accretion of contingent acquisition consideration ​ ​ — ​ ​ — ​ ​ 1,928 ​ ​ (1,928) ​ ​ — ​ Total operating expenses ​ ​ 5,459,472 ​ ​ — ​ ​ 114,291 ​ ​ (178,028) ​ ​ 5,395,735 ​ Operating income (loss) ​ ​ (1,053,610) ​ ​ — ​ ​ 104,069 ​ ​ (37,504) ​ ​ (987,045) ​ Other income (expenses): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Water earnout ​ ​ 125,000 ​ ​ ​ ​ ​ ​ ​ ​ — ​ ​ 125,000 ​ Equity in earnings (loss) of unconsolidated affiliates ​ ​ (49,442) ​ ​ (106,038) ​ ​ 12,264 ​ ​ — ​ ​ (143,216) ​ Equity in earnings of affiliates ​ ​ 15,021 ​ ​ — ​ ​ — ​ ​ (15,021) ​ ​ — ​ Loss on the sale of equity investment shares ​ ​ (108,745) ​ ​ — ​ ​ — ​ ​ — ​ ​ (108,745) ​ Impairment of equity investments ​ ​ (143,090) ​ ​ (324,500) ​ ​ — ​ ​ — ​ ​ (467,590) ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ 1,205,705 ​ ​ 200,337 ​ ​ — ​ ​ — ​ ​ 1,406,042 ​ Interest expense, net ​ ​ (211,296) ​ ​ — ​ ​ (16,815) ​ ​ — ​ ​ (228,111) ​ Gain on early extinguishment of debt ​ ​ 36,419 ​ ​ — ​ ​ — ​ ​ — ​ ​ 36,419 ​ Total other income (expenses) ​ ​ 869,572 ​ ​ (230,201) ​ ​ (4,551) ​ ​ (15,021) ​ ​ 619,799 ​ Income before income taxes ​ ​ (184,038) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (367,246) ​ Provision for income tax expense ​ ​ 74,110 ​ ​ — ​ ​ — ​ ​ — ​ ​ 74,110 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interests ​ ​ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (293,136) ​ Net income and comprehensive income attributable to noncontrolling interests ​ ​ — ​ ​ — ​ ​ — ​ ​ 46,993 ​ ​ 46,993 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ $ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (99,518) ​ ​ (340,129) ​
Schedule of condensed consolidating statement of cash flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ (Antero ​ ​ ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income including noncontrolling interests ​ $ 615,070 ​ ​ — ​ ​ 307,315 ​ ​ (137,248) ​ ​ 785,137 ​ Adjustment to reconcile net income to net cash ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 707,658 ​ ​ — ​ ​ 119,562 ​ ​ — ​ ​ 827,220 ​ Change in fair value of contingent acquisition consideration ​ ​ (13,476) ​ ​ — ​ ​ 13,476 ​ ​ — ​ ​ — ​ Impairment of oil and gas properties ​ ​ 159,598 ​ ​ — ​ ​ — ​ ​ — ​ ​ 159,598 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 23,431 ​ ​ — ​ ​ 23,431 ​ Commodity derivative fair value gains ​ ​ (658,283) ​ ​ — ​ ​ — ​ ​ — ​ ​ (658,283) ​ Gains on settled commodity derivatives ​ ​ 213,940 ​ ​ — ​ ​ — ​ ​ — ​ ​ 213,940 ​ Proceeds from derivative monetizations ​ ​ 749,906 ​ ​ — ​ ​ — ​ ​ — ​ ​ 749,906 ​ Marketing derivative losses ​ ​ 21,394 ​ ​ — ​ ​ — ​ ​ — ​ ​ 21,394 ​ Deferred income tax benefit ​ ​ (295,126) ​ ​ — ​ ​ — ​ ​ — ​ ​ (295,126) ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Equity-based compensation expense ​ ​ 76,162 ​ ​ — ​ ​ 27,283 ​ ​ — ​ ​ 103,445 ​ Loss on early extinguishment of debt ​ ​ 1,205 ​ ​ — ​ ​ 295 ​ ​ — ​ ​ 1,500 ​ Equity in earnings of Antero Midstream ​ ​ 43,710 ​ ​ — ​ ​ — ​ ​ (43,710) ​ ​ — ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (20,194) ​ ​ — ​ ​ (20,194) ​ Distributions of earnings from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 20,195 ​ ​ — ​ ​ 20,195 ​ Other ​ ​ (4,500) ​ ​ — ​ ​ 2,593 ​ ​ — ​ ​ (1,907) ​ Distributions from subsidiaries ​ ​ 131,598 ​ ​ — ​ ​ — ​ ​ (131,598) ​ ​ — ​ Changes in current assets and liabilities ​ ​ 87,466 ​ ​ — ​ ​ (18,160) ​ ​ 6,729 ​ ​ 76,035 ​ Net cash provided by operating activities ​ ​ 1,836,322 ​ ​ — ​ ​ 475,796 ​ ​ (305,827) ​ ​ 2,006,291 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to proved properties ​ ​ (175,650) ​ ​ — ​ ​ — ​ ​ — ​ ​ (175,650) ​ Additions to unproved properties ​ ​ (204,272) ​ ​ — ​ ​ — ​ ​ — ​ ​ (204,272) ​ Drilling and completion costs ​ ​ (1,455,554) ​ ​ — ​ ​ — ​ ​ 173,569 ​ ​ (1,281,985) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (195,162) ​ ​ 660 ​ ​ (194,502) ​ Additions to gathering systems and facilities ​ ​ — ​ ​ — ​ ​ (346,217) ​ ​ — ​ ​ (346,217) ​ Additions to other property and equipment ​ ​ (14,127) ​ ​ — ​ ​ — ​ ​ — ​ ​ (14,127) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (235,004) ​ ​ — ​ ​ (235,004) ​ Change in other assets ​ ​ (8,594) ​ ​ — ​ ​ (3,435) ​ ​ — ​ ​ (12,029) ​ Other ​ ​ 2,156 ​ ​ — ​ ​ — ​ ​ — ​ ​ 2,156 ​ Net cash used in investing activities ​ ​ (1,856,041) ​ ​ — ​ ​ (779,818) ​ ​ 174,229 ​ ​ (2,461,630) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Issuance of common units by Antero Midstream ​ ​ — ​ ​ — ​ ​ 248,956 ​ ​ — ​ ​ 248,956 ​ Sale of common units in Antero Midstream by Antero Resources Corporation ​ ​ 311,100 ​ ​ — ​ ​ — ​ ​ — ​ ​ 311,100 ​ Borrowings (repayments) on bank credit facility, net ​ ​ (255,000) ​ ​ — ​ ​ 345,000 ​ ​ — ​ ​ 90,000 ​ Payments of deferred financing costs ​ ​ (10,857) ​ ​ — ​ ​ (5,520) ​ ​ — ​ ​ (16,377) ​ Distributions ​ ​ — ​ ​ — ​ ​ (283,950) ​ ​ 131,598 ​ ​ (152,352) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (18,229) ​ ​ — ​ ​ (5,945) ​ ​ — ​ ​ (24,174) ​ Other ​ ​ (4,785) ​ ​ — ​ ​ (198) ​ ​ — ​ ​ (4,983) ​ Net cash provided by financing activities ​ ​ 22,229 ​ ​ — ​ ​ 298,343 ​ ​ 131,598 ​ ​ 452,170 ​ Net increase (decrease) in cash and cash equivalents ​ ​ 2,510 ​ ​ — ​ ​ (5,679) ​ ​ — ​ ​ (3,169) ​ Cash and cash equivalents, beginning of period ​ ​ 17,568 ​ ​ — ​ ​ 14,042 ​ ​ — ​ ​ 31,610 ​ Cash and cash equivalents, end of period ​ $ 20,078 ​ ​ — ​ ​ 8,363 ​ ​ — ​ ​ 28,441 ​ Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ (Antero Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) including noncontrolling interests ​ $ (397,517) ​ ​ — ​ ​ 585,944 ​ ​ (234,128) ​ ​ (45,701) ​ Adjustment to reconcile net income (loss) to net cash provided by operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 845,136 ​ ​ — ​ ​ 130,148 ​ ​ — ​ ​ 975,284 ​ Changes in fair value of contingent acquisition consideration ​ ​ 93,019 ​ ​ — ​ ​ (93,019) ​ ​ — ​ ​ — ​ Impairment of oil and gas properties ​ ​ 549,437 ​ ​ — ​ ​ — ​ ​ — ​ ​ 549,437 ​ Impairment of midstream assets ​ ​ 4,470 ​ ​ — ​ ​ 5,771 ​ ​ (583) ​ ​ 9,658 ​ Commodity derivative fair value losses ​ ​ 87,594 ​ ​ — ​ ​ — ​ ​ — ​ ​ 87,594 ​ Gains on settled commodity derivatives ​ ​ 243,112 ​ ​ — ​ ​ — ​ ​ — ​ ​ 243,112 ​ Premium paid on derivative contracts ​ ​ (13,318) ​ ​ — ​ ​ — ​ ​ — ​ ​ (13,318) ​ Proceeds from derivative monetizations ​ ​ 370,365 ​ ​ — ​ ​ — ​ ​ — ​ ​ 370,365 ​ Marketing derivative fair value gains ​ ​ (94,081) ​ ​ — ​ ​ — ​ ​ — ​ ​ (94,081) ​ Gains on settled marketing derivatives ​ ​ 72,687 ​ ​ — ​ ​ — ​ ​ — ​ ​ 72,687 ​ Deferred income tax benefit ​ ​ (128,857) ​ ​ — ​ ​ — ​ ​ — ​ ​ (128,857) ​ Gain on sale of assets ​ ​ — ​ ​ — ​ ​ (583) ​ ​ 583 ​ ​ — ​ Equity-based compensation expense ​ ​ 49,341 ​ ​ — ​ ​ 21,073 ​ ​ — ​ ​ 70,414 ​ Equity in earnings (loss) of consolidated subsidiaries ​ ​ 3,664 ​ ​ — ​ ​ — ​ ​ (3,664) ​ ​ — ​ Equity in earnings of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (40,280) ​ ​ — ​ ​ (40,280) ​ Distributions of earnings from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ 46,415 ​ ​ — ​ ​ 46,415 ​ Distributions from Antero Midstream ​ ​ 159,181 ​ ​ — ​ ​ — ​ ​ (159,181) ​ ​ — ​ Other ​ ​ 4,681 ​ ​ — ​ ​ 2,879 ​ ​ (2,879) ​ ​ 4,681 ​ Changes in current assets and liabilities ​ ​ (26,059) ​ ​ — ​ ​ (788) ​ ​ 1,424 ​ ​ (25,423) ​ Net cash provided by operating activities ​ ​ 1,822,855 ​ ​ — ​ ​ 657,560 ​ ​ (398,428) ​ ​ 2,081,987 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to unproved properties ​ ​ (172,387) ​ ​ — ​ ​ — ​ ​ — ​ ​ (172,387) ​ Drilling and completion costs ​ ​ (1,743,587) ​ ​ — ​ ​ — ​ ​ 255,014 ​ ​ (1,488,573) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (88,674) ​ ​ (9,025) ​ ​ (97,699) ​ Additions to gathering systems and facilities ​ ​ 103 ​ ​ — ​ ​ (446,270) ​ ​ 1,754 ​ ​ (444,413) ​ Additions to other property and equipment ​ ​ (7,441) ​ ​ — ​ ​ — ​ ​ (73) ​ ​ (7,514) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (136,475) ​ ​ — ​ ​ (136,475) ​ Change in other assets ​ ​ (72) ​ ​ — ​ ​ (3,591) ​ ​ — ​ ​ (3,663) ​ Change in other liabilities ​ ​ — ​ ​ — ​ ​ 2,273 ​ ​ (2,273) ​ ​ — ​ Other ​ ​ — ​ ​ — ​ ​ 6,150 ​ ​ (6,150) ​ ​ — ​ Net cash used in investing activities ​ ​ (1,923,384) ​ ​ — ​ ​ (666,587) ​ ​ 239,247 ​ ​ (2,350,724) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Repurchases of common stock ​ ​ (129,084) ​ ​ — ​ ​ — ​ ​ — ​ ​ (129,084) ​ Borrowings (repayments) on bank credit facility, net ​ ​ 225,379 ​ ​ — ​ ​ 435,000 ​ ​ — ​ ​ 660,379 ​ Payments of deferred financing costs ​ ​ — ​ ​ — ​ ​ (2,169) ​ ​ — ​ ​ (2,169) ​ Distributions ​ ​ — ​ ​ — ​ ​ (426,452) ​ ​ 159,181 ​ ​ (267,271) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (11,491) ​ ​ — ​ ​ (5,529) ​ ​ — ​ ​ (17,020) ​ Other ​ ​ (4,353) ​ ​ — ​ ​ (186) ​ ​ — ​ ​ (4,539) ​ Net cash provided by financing activities ​ ​ 80,451 ​ ​ — ​ ​ 664 ​ ​ 159,181 ​ ​ 240,296 ​ Net decrease in cash and cash equivalents ​ ​ (20,078) ​ ​ — ​ ​ (8,363) ​ ​ — ​ ​ (28,441) ​ Cash and cash equivalents, beginning of period ​ ​ 20,078 ​ ​ — ​ ​ 8,363 ​ ​ — ​ ​ 28,441 ​ Cash and cash equivalents, end of period ​ $ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2019 (In thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Non-Guarantor ​ ​ ​ ​ ​ ​ ​ Parent ​ Guarantor ​ Subsidiaries ​ ​ ​ ​ ​ ​ ​ (Antero) ​ Subsidiaries ​ (Antero Midstream) ​ Eliminations ​ Consolidated ​ Cash flows provided by (used in) operating activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) including noncontrolling interests ​ $ (109,928) ​ ​ (230,201) ​ ​ 99,518 ​ ​ (52,525) ​ ​ (293,136) ​ Adjustment to reconcile net income (loss) to net cash provided by operating activities: ​ ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Depletion, depreciation, amortization, and accretion ​ ​ 896,859 ​ ​ — ​ ​ 21,770 ​ ​ — ​ ​ 918,629 ​ Impairments ​ ​ 1,451,334 ​ ​ 324,500 ​ ​ 6,982 ​ ​ — ​ ​ 1,782,816 ​ Commodity derivative fair value gains ​ ​ (463,972) ​ ​ — ​ ​ — ​ ​ — ​ ​ (463,972) ​ Gains on settled commodity derivatives ​ ​ 325,090 ​ ​ — ​ ​ — ​ ​ — ​ ​ 325,090 ​ Deferred income tax benefit ​ ​ (79,158) ​ ​ — ​ ​ — ​ ​ — ​ ​ (79,158) ​ Loss on sale of assets ​ ​ 951 ​ ​ — ​ ​ — ​ ​ — ​ ​ 951 ​ Equity-based compensation expense ​ ​ 21,082 ​ ​ — ​ ​ 2,477 ​ ​ — ​ ​ 23,559 ​ Gain on early extinguishment of debt ​ ​ (36,419) ​ ​ — ​ ​ — ​ ​ — ​ ​ (36,419) ​ Loss on sale of equity investment shares ​ ​ 108,745 ​ ​ — ​ ​ — ​ ​ — ​ ​ 108,745 ​ Equity in earnings of affiliates ​ ​ (15,021) ​ ​ — ​ ​ — ​ ​ 15,021 ​ ​ — ​ Equity in (earnings) loss of unconsolidated affiliates ​ ​ 49,442 ​ ​ 106,038 ​ ​ (12,264) ​ ​ — ​ ​ 143,216 ​ Water earnout ​ ​ (125,000) ​ ​ — ​ ​ — ​ ​ — ​ ​ (125,000) ​ Distributions/dividends of earnings from unconsolidated affiliates ​ ​ 145,351 ​ ​ — ​ ​ 12,605 ​ ​ — ​ ​ 157,956 ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ (1,205,705) ​ ​ (200,337) ​ ​ — ​ ​ — ​ ​ (1,406,042) ​ Distributions from Antero Midstream Partners LP ​ ​ 94,391 ​ ​ — ​ ​ — ​ ​ (94,391) ​ ​ — ​ Other ​ ​ (37,991) ​ ​ — ​ ​ 750 ​ ​ 47,922 ​ ​ 10,681 ​ Changes in current assets and liabilities ​ ​ 29,307 ​ ​ — ​ ​ (10,573) ​ ​ 16,808 ​ ​ 35,542 ​ Net cash provided by operating activities ​ ​ 1,049,358 ​ ​ — ​ ​ 121,265 ​ ​ (67,165) ​ ​ 1,103,458 ​ Cash flows provided by (used in) investing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Additions to unproved properties ​ ​ (88,682) ​ ​ — ​ ​ — ​ ​ — ​ ​ (88,682) ​ Drilling and completion costs ​ ​ (1,274,683) ​ ​ — ​ ​ — ​ ​ 20,565 ​ ​ (1,254,118) ​ Additions to water handling and treatment systems ​ ​ — ​ ​ — ​ ​ (24,547) ​ ​ 131 ​ ​ (24,416) ​ Additions to gathering systems and facilities ​ ​ — ​ ​ — ​ ​ (48,239) ​ ​ — ​ ​ (48,239) ​ Additions to other property and equipment ​ ​ (5,638) ​ ​ — ​ ​ (1,062) ​ ​ — ​ ​ (6,700) ​ Investments in unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (25,020) ​ ​ — ​ ​ (25,020) ​ Proceeds from sale of common stock of Antero Midstream Corporation ​ ​ 100,000 ​ ​ — ​ ​ — ​ ​ — ​ ​ 100,000 ​ Proceeds from the Antero Midstream Partners LP Transactions ​ ​ 296,611 ​ ​ — ​ ​ — ​ ​ — ​ ​ 296,611 ​ Change in other assets ​ ​ 10,448 ​ ​ — ​ ​ (3,357) ​ ​ — ​ ​ 7,091 ​ Proceeds from sale of assets ​ ​ 1,983 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,983 ​ Net cash investing activities ​ ​ (959,961) ​ ​ — ​ ​ (102,225) ​ ​ 20,696 ​ ​ (1,041,490) ​ Cash flows provided by (used in) financing activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ — ​ Repurchases of common stock ​ ​ (38,772) ​ ​ — ​ ​ — ​ ​ — ​ ​ (38,772) ​ Issuance of senior notes ​ ​ — ​ ​ — ​ ​ 650,000 ​ ​ — ​ ​ 650,000 ​ Repayment of senior notes ​ ​ (191,092) ​ ​ — ​ ​ — ​ ​ — ​ ​ (191,092) ​ Borrowings (repayments) on bank credit facilities, net ​ ​ 141,621 ​ ​ — ​ ​ 90,379 ​ ​ — ​ ​ 232,000 ​ Payments of deferred financing costs ​ ​ 2,921 ​ ​ — ​ ​ (7,468) ​ ​ — ​ ​ (4,547) ​ Distributions to noncontrolling interests in Antero Midstream Partners LP ​ ​ — ​ ​ — ​ ​ (131,545) ​ ​ 46,469 ​ ​ (85,076) ​ Employee tax withholding for settlement of equity compensation awards ​ ​ (2,360) ​ ​ — ​ ​ (29) ​ ​ — ​ ​ (2,389) ​ Other ​ ​ (1,715) ​ ​ — ​ ​ (845) ​ ​ — ​ ​ (2,560) ​ Net cash provided by (used in) financing activities ​ ​ (89,397) ​ ​ — ​ ​ 600,492 ​ ​ 46,469 ​ ​ 557,564 ​ Antero Midstream Partners LP cash at deconsolidation ​ ​ — ​ ​ — ​ ​ (619,532) ​ ​ — ​ ​ (619,532) ​ Net increase in cash and cash equivalents ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Cash and cash equivalents, beginning of period ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​ Cash and cash equivalents, end of period ​ $ — ​ ​ — ​ ​ — ​ ​ — ​ ​ — ​

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information (Unaudited)
Schedule of quarterly financial information	The Company’s quarterly consolidated financial information for the years ended December 31, 2018 and 2019 is summarized in the tables below (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ quarter ​ quarter ​ quarter ​ quarter ​ Year Ended December 31, 2018: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,028,101 ​ 989,344 ​ 1,076,532 ​ 1,045,649 ​ Total operating expenses ​ 881,607 ​ 1,022,107 ​ 1,071,728 ​ 1,092,279 ​ Operating income (loss) ​ 146,494 ​ (32,763) ​ 4,804 ​ (46,630) ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ 80,810 ​ (67,275) ​ (77,972) ​ 18,736 ​ Net income attributable to noncontrolling interest ​ ​ 65,977 ​ 69,110 ​ 76,447 ​ 140,282 ​ Net income (loss) attributable to Antero Resources Corporation ​ 14,833 ​ (136,385) ​ (154,419) ​ (121,546) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share—basic ​ $ 0.05 ​ (0.43) ​ (0.49) ​ (0.39) ​ Earnings (loss) per common share—assuming dilution ​ $ 0.05 ​ (0.43) ​ (0.49) ​ (0.39) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ quarter ​ quarter ​ quarter ​ quarter Year Ended December 31, 2019: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,037,407 ​ ​ 1,299,664 ​ ​ 1,118,881 ​ 952,738 ​ Total operating expenses ​ 1,071,114 ​ ​ 1,199,668 ​ ​ 2,104,759 ​ 1,020,194 ​ Operating income (loss) ​ (33,707) ​ 99,996 ​ (985,878) ​ (67,456) ​ Gain on deconsolidation of Antero Midstream Partners LP ​ ​ 1,406,042 ​ ​ — ​ ​ — ​ ​ — ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ 1,025,756 ​ ​ 42,168 ​ ​ (878,864) ​ (482,196) ​ Net income attributable to noncontrolling interest ​ ​ 46,993 ​ ​ — ​ ​ — ​ — ​ Net income (loss) attributable to Antero Resources Corporation ​ 978,763 ​ 42,168 ​ (878,864) ​ (482,196) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ Earnings (loss) per common share—diluted ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​

Supplemental Information on O_2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Schedule of capitalized costs relating to oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, (In thousands) ​ 2018 ​ 2019 ​ Proved properties ​ $ 12,705,672 ​ ​ 11,859,817 ​ Unproved properties ​ 1,767,600 ​ 1,368,854 ​ ​ ​ 14,473,272 ​ 13,228,671 ​ Accumulated depletion and depreciation ​ (3,615,680) ​ (3,284,330) ​ Net capitalized costs ​ $ 10,857,592 ​ ​ 9,944,341 ​
Schedule of costs incurred in certain oil and gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (In thousands) ​ 2017 ​ 2018 ​ 2019 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ 175,650 ​ ​ — ​ ​ — ​ Unproved property ​ 204,272 ​ ​ 172,387 ​ ​ 88,682 ​ Development costs ​ 897,287 ​ ​ 1,164,800 ​ ​ 1,104,336 ​ Exploration costs ​ 384,698 ​ ​ 323,773 ​ ​ 149,782 ​ Total costs incurred ​ $ 1,661,907 ​ ​ 1,660,960 ​ ​ 1,342,800 ​
Schedule of results of operations (including discontinued operations) for oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, (In thousands) ​ 2017 ​ 2018 ​ 2019 ​ Revenues ​ $ 2,747,920 ​ ​ 3,652,894 ​ ​ 3,643,873 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 1,279,217 ​ ​ 1,601,985 ​ ​ 2,417,509 ​ Exploration expenses ​ 8,538 ​ ​ 4,958 ​ ​ 884 ​ Depletion and depreciation ​ 694,332 ​ ​ 832,326 ​ ​ 884,350 ​ Impairment of oil and gas properties ​ 159,598 ​ ​ 549,437 ​ ​ 1,300,444 ​ Results of operations before income tax (expense) benefit ​ 606,235 ​ ​ 664,188 ​ ​ (959,314) ​ Income tax (expense) benefit ​ (228,096) ​ ​ (156,350) ​ ​ 224,511 ​ Results of operations ​ $ 378,139 ​ ​ 507,838 ​ ​ (734,803) ​
Schedule of proved developed and undeveloped reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural gas ​ NGLs ​ condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2016 ​ 9,414 ​ 957 ​ 38 ​ 15,386 ​ Revisions ​ 342 ​ (22) ​ (6) ​ 176 ​ Extensions, discoveries and other additions ​ 1,644 ​ 77 ​ 7 ​ 2,148 ​ Production ​ (591) ​ (36) ​ (2) ​ (822) ​ Purchases of reserves ​ 289 ​ 13 ​ 1 ​ 373 ​ December 31, 2017 ​ 11,098 ​ 989 ​ 38 ​ 17,261 ​ Revisions ​ (1,087) ​ 8 ​ (1) ​ (1,042) ​ Extensions, discoveries and other additions ​ 2,125 ​ 98 ​ 12 ​ 2,781 ​ Production ​ (711) ​ (43) ​ (3) ​ (989) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2018 ​ 11,425 ​ 1,052 ​ 46 ​ 18,011 ​ Revisions ​ (1,735) ​ 25 ​ (11) ​ (1,648) ​ Extensions, discoveries and other additions ​ 2,626 ​ 169 ​ 11 ​ 3,705 ​ Production ​ (822) ​ (55) ​ (4) ​ (1,175) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2019 ​ 11,494 ​ 1,191 ​ 42 ​ 18,893 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural gas ​ NGLs ​ condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ 5,587 ​ 467 ​ 16 ​ 8,488 ​ December 31, 2018 ​ 6,669 ​ 600 ​ 20 ​ 10,389 ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ 5,511 ​ 522 ​ 22 ​ 8,773 ​ December 31, 2018 ​ 4,756 ​ 452 ​ 26 ​ 7,622 ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (in millions) ​ 2017 ​ 2018 ​ 2019 Future cash inflows ​ $ 55,824 ​ ​ 64,199 ​ ​ 54,228 ​ Future production costs ​ (26,375) ​ ​ (30,007) ​ ​ (36,524) ​ Future development costs ​ (3,312) ​ ​ (3,453) ​ ​ (2,772) ​ Future net cash flows before income tax ​ 26,137 ​ ​ 30,739 ​ ​ 14,932 ​ Future income tax expense ​ (4,104) ​ ​ (5,505) ​ ​ (1,639) ​ Future net cash flows ​ 22,033 ​ ​ 25,234 ​ ​ 13,293 ​ 10% annual discount for estimated timing of cash flows ​ (13,406) ​ ​ (14,756) ​ ​ (7,824) ​ Standardized measure of discounted future net cash flows ​ $ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2017 ​ ​ ​ ​ ​ ​ ​ $ 3.23 ​ December 31, 2018 ​ ​ ​ ​ ​ ​ ​ $ 3.56 ​ December 31, 2019 ​ ​ ​ ​ ​ ​ ​ $ 2.87 ​
Schedule of changes in standardized measure of discounted future net cash flow	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ (in millions) ​ 2017 ​ 2018 ​ 2019 ​ Sales of oil and gas, net of productions costs ​ $ (1,469) ​ ​ (2,051) ​ ​ (1,116) ​ Net changes in prices and production costs (1) ​ 3,918 ​ ​ 707 ​ ​ (6,729) ​ Development costs incurred during the period ​ 627 ​ ​ 755 ​ ​ 758 ​ Net changes in future development costs (2) ​ 229 ​ ​ 37 ​ ​ (92) ​ Extensions, discoveries and other additions ​ 1,448 ​ ​ 1,925 ​ ​ 782 ​ Acquisitions ​ 258 ​ ​ — ​ ​ — ​ Divestitures ​ ​ — ​ ​ — ​ ​ — ​ Revisions of previous quantity estimates ​ 734 ​ ​ (53) ​ ​ (1,011) ​ Accretion of discount ​ 368 ​ ​ 1,018 ​ ​ 1,259 ​ Net change in income taxes ​ (1,159) ​ ​ (563) ​ ​ 1,513 ​ Changes in timing and other ​ 386 ​ ​ 76 ​ ​ (373) ​ Net increase (decrease) ​ 5,340 ​ ​ 1,851 ​ ​ (5,009) ​ Beginning of year ​ 3,287 ​ ​ 8,627 ​ ​ 10,478 ​ End of year ​ $ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​ (1) (2)

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 16, 2019	Mar. 11, 2019	Dec. 31, 2019	Mar. 12, 2019	Dec. 31, 2018
Basis of Presentation
Other comprehensive income (loss)			$ 0
Common stock issued	19,377,592
Share price	$ 5.1606
Net proceeds from issuance of additional shares of common stock	$ 100
Accounts Payable
Basis of Presentation
Bank Overdrafts			7		$ 10
Revenue distributions payable
Basis of Presentation
Bank Overdrafts			$ 18		$ 28
Antero Midstream Corporation
Basis of Presentation
Ownership interest in equity method			28.70%	31.00%
Antero Midstream Partners LP
Basis of Presentation
Ownership interest		53.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Property and equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property and Equipment
Depreciation expense	$ 914,867	$ 972,465	$ 824,610
Oil and Gas Properties
Exploratory drilling costs initially capitalized, but subsequently charged to expense		0	0
Impairment of oil and gas properties	1,300,444	549,437	159,598
Impairment of oil and gas properties for leases expired or expected to expire	393,000	549,000	160,000
Impairment of proved properties	14,782	9,658	23,431
Depreciation, depletion, and amortization expense for oil and gas properties	884,000	832,000	694,000
Impairment of long-lived assets other than oil and gas properties	15,000	10,000	23,000
Deferred Financing Costs
Unamortized deferred financing costs included in other assets	7,000
Unamortized deferred financing costs included in long-term debt	19,000
Amounts amortized and the write-off of previously deferred debt issuance costs	11,000	13,000	13,000
Utica Shale
Oil and Gas Properties
Impairment of proved properties	$ 881,000
Gathering Systems and Facilities
Property and Equipment
Estimated useful life	50 years
Other property and equipment
Property and Equipment
Depreciation expense	$ 8,000	9,000	10,000
Other property and equipment | Minimum
Property and Equipment
Estimated useful life	2
Other property and equipment | Maximum
Property and Equipment
Estimated useful life	20 years
Gathering pipelines, compressor stations, and fresh water distribution systems
Property and Equipment
Depreciation expense	$ 22,000	$ 131,000	$ 120,000
Water handling and treatment | Minimum
Property and Equipment
Estimated useful life	5
Water handling and treatment | Maximum
Property and Equipment
Estimated useful life	20 years
Oil and gas property wells
Oil and Gas Properties
Impairment of oil and gas properties	$ 26,000

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Credit Risk (Details) - Sales - Customer concentration	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Concentrations of Credit Risk
Sales to major customers (as a percent)	100.00%	100.00%	100.00%
Company A
Concentrations of Credit Risk
Sales to major customers (as a percent)	16.00%	8.00%	4.00%
Company B
Concentrations of Credit Risk
Sales to major customers (as a percent)	15.00%	6.00%	14.00%
Company C
Concentrations of Credit Risk
Sales to major customers (as a percent)	9.00%	13.00%	20.00%
Company D
Concentrations of Credit Risk
Sales to major customers (as a percent)	3.00%	14.00%
All others
Concentrations of Credit Risk
Sales to major customers (as a percent)	57.00%	59.00%	62.00%

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Derivative Financial Instruments (Details) $ in Millions	Dec. 31, 2019USD ($)Counterparty
Derivative Financial Instruments
Number of counterparties | Counterparty	14
Fair value of commodity derivative contracts	$ 746
Morgan Stanley
Derivative Financial Instruments
Fair value of commodity derivative contracts	121
JP Morgan
Derivative Financial Instruments
Fair value of commodity derivative contracts	134
Scotiabank
Derivative Financial Instruments
Fair value of commodity derivative contracts	58
Citigroup
Derivative Financial Instruments
Fair value of commodity derivative contracts	117
Wells Fargo
Derivative Financial Instruments
Fair value of commodity derivative contracts	215
Canadian Imperial Bank of Commerce
Derivative Financial Instruments
Fair value of commodity derivative contracts	44
BNP Paribas
Derivative Financial Instruments
Fair value of commodity derivative contracts	21
PNC
Derivative Financial Instruments
Fair value of commodity derivative contracts	29
SunTrust
Derivative Financial Instruments
Fair value of commodity derivative contracts	7
Natixis
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 10

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings per share
Basic weighted average number of shares outstanding	306,400	316,036	315,426
Diluted weighted average number of shares outstanding	306,400	316,036	316,283
Restricted stock and restricted stock unit
Earnings per share
Add: Dilutive effect of non-vested restricted stock units			817
Weighted Average Anti-dilutive Awards	2,357	2,844	1,521
Stock options
Earnings per share
Weighted Average Anti-dilutive Awards	527	626	676
Performance share unit awards
Earnings per share
Add: Dilutive effect of non-vested restricted stock units			40
Weighted Average Anti-dilutive Awards	1,443	1,705	1,054

Deconsolidation of Antero Mid_3

Deconsolidation of Antero Midstream Partners LP - Narrative (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Mar. 13, 2019	Mar. 12, 2019	Mar. 11, 2019	Dec. 31, 2019	Dec. 31, 2018
Deconsolidation
Cash received				$ 296,611
Par value per share				$ 0.01	$ 0.01
Antero Midstream Corporation
Deconsolidation
Cash received		$ 297,000
Shares of Antero Midstream's common stock received		158,400
Par value per share		$ 0.01
Ownership interest in equity method		31.00%		28.70%
Gain on deconsolidation	$ 1,400,000
Fair value of our retained equity method investment	$ 2,000,000
Antero Midstream Partners LP
Deconsolidation
Number of common units owned		98,870,335
Ownership interest			53.00%

Deconsolidation of Antero Mid_4

Deconsolidation of Antero Midstream Partners LP - Summarized Financial Information of Antero Midstream Partners (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Mar. 12, 2019	Dec. 31, 2018	Dec. 31, 2017
Deconsolidation
Current assets	$ 922,885		$ 806,613
Property and equipment, net	9,978,739		13,869,915
Other noncurrent assets	21,094		47,125
Total assets	15,197,569		15,519,464	$ 15,261,490
Current liabilities	1,040,139		853,540
Long-term debt	3,758,868		5,461,688
Other noncurrent liabilities	58,635		63,098
Total liabilities	$ 8,226,826		$ 7,031,987
Antero Midstream Partners LP
Deconsolidation
Current assets		$ 763,109
Property and equipment, net		3,003,693
Other noncurrent assets		501,208
Total assets		4,268,010
Current liabilities		123,473
Long-term debt		2,359,084
Other noncurrent liabilities		123,523
Total liabilities		2,606,080
Net assets		$ 1,661,930

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue
Revenues from contracts with customers									$ 3,940,558	$ 4,133,139	$ 3,018,685
Revenue from derivatives and other sources									468,132	6,487	636,889
Total revenue and other	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	4,408,690	4,139,626	3,655,574
Natural gas sales
Disaggregation of Revenue
Revenues from contracts with customers									2,247,162	2,287,939	1,769,284
Oil sales
Disaggregation of Revenue
Revenues from contracts with customers									177,549	187,178	108,195
Marketing
Disaggregation of Revenue
Revenues from contracts with customers									292,207	458,901	258,045
Other income
Disaggregation of Revenue
Revenues from contracts with customers									4,160
Exploration and production | Natural gas sales
Disaggregation of Revenue
Revenues from contracts with customers									2,247,162	2,287,939	1,769,284
Exploration and production | Natural gas liquids sales (ethane)
Disaggregation of Revenue
Revenues from contracts with customers									124,563	172,653	93,041
Exploration and production | Natural gas liquids sales (C3+ NGLs)
Disaggregation of Revenue
Revenues from contracts with customers									1,094,599	1,005,124	777,400
Exploration and production | Oil sales
Disaggregation of Revenue
Revenues from contracts with customers									177,549	187,178	108,195
Gathering and compression | Gathering and compression
Disaggregation of Revenue
Revenues from contracts with customers									3,972	17,817	11,386
Water handling and treatment | Water handling and treatment
Disaggregation of Revenue
Revenues from contracts with customers									506	3,527	1,334
Marketing | Marketing
Disaggregation of Revenue
Revenues from contracts with customers									$ 292,207	$ 458,901	$ 258,045

Revenue - Transaction Price All

Revenue - Transaction Price Allocation and Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue
Original expected duration	true
Receivables from contracts with customers	$ 318	$ 475

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Thousands	Mar. 12, 2019item	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Equity Method Investments
Impairment of equity investments				$ 467,590
Investments in unconsolidated affiliates
Equity in earnings (loss) of unconsolidated affiliates				(143,216)	$ 40,280	$ 20,194
Distributions/dividends from unconsolidated affiliates				(157,956)	(46,415)	(20,195)
Impairment				(467,590)
Effects of deconsolidation				(108,745)
Loss on the sale of equity investment shares				(108,745)
Antero Midstream Corporation
Balance Sheet
Current assets		$ 108,558	$ 108,558	108,558
Noncurrent assets		6,174,320	6,174,320	6,174,320
Total assets		6,282,878	6,282,878	6,282,878
Current liabilities		242,084	242,084	242,084
Noncurrent liabilities		2,897,380	2,897,380	2,897,380
Stockholders' equity		3,143,414	3,143,414	3,143,414
Total liabilities and equity		$ 6,282,878	6,282,878	$ 6,282,878
Statement of Operations
Revenues			792,588
Operating expenses			1,177,610
Loss from operations			(385,022)
Net loss attributable to the equity method investments			$ (341,565)
Appalachia joint venture
Equity Method Investments
Ownership percentage	50.00%
Antero Midstream Corporation
Equity Method Investments
Ownership percentage	31.00%	28.70%	28.70%	28.70%
Impairment of equity investments				$ 467,590
Investments in unconsolidated affiliates
Equity in earnings (loss) of unconsolidated affiliates				(155,480)
Distributions/dividends from unconsolidated affiliates				(145,351)
Return of investment				(208,745)
Impairment				(467,590)
Elimination of intercompany profit				44,548
Effects of deconsolidation		$ 109,000		1,987,795
Balance at end of period		1,055,177	$ 1,055,177	1,055,177
Antero Midstream repurchased		100,000
Loss on the sale of equity investment shares		$ 109,000		$ 1,987,795
Antero Midstream Corporation | Antero Midstream Corporation
Equity Method Investments
Ownership percentage		28.70%	28.70%	28.70%
Antero Midstream Partners LP
Equity Method Investments
Number of equity method investments | item	2
Impairment of equity investments				$ 467,590
Investments in unconsolidated affiliates
Balance at beginning of period				433,642	303,302
Investments				25,020	136,475
Equity in earnings (loss) of unconsolidated affiliates				(143,216)	40,280
Distributions/dividends from unconsolidated affiliates				(157,956)	(46,415)
Return of investment				(208,745)
Impairment				(467,590)
Elimination of intercompany profit				44,548
Effects of deconsolidation				1,529,474
Balance at end of period		$ 1,055,177	$ 1,055,177	1,055,177	433,642	303,302
Loss on the sale of equity investment shares				1,529,474
Antero Midstream Partners LP | Stonewall
Equity Method Investments
Ownership percentage	15.00%
Investments in unconsolidated affiliates
Balance at beginning of period				68,103	67,128
Equity in earnings (loss) of unconsolidated affiliates				1,894	10,740
Distributions/dividends from unconsolidated affiliates				(3,000)	(9,765)
Effects of deconsolidation				(66,997)
Balance at end of period					68,103	67,128
Loss on the sale of equity investment shares				(66,997)
Antero Midstream Partners LP | Appalachia joint venture
Investments in unconsolidated affiliates
Balance at beginning of period				365,539	236,174
Investments				25,020	136,475
Equity in earnings (loss) of unconsolidated affiliates				10,370	29,540
Distributions/dividends from unconsolidated affiliates				(9,605)	(36,650)
Effects of deconsolidation				(391,324)
Balance at end of period					$ 365,539	$ 236,174
Loss on the sale of equity investment shares				$ (391,324)

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accrued Liabilities
Capital expenditures	$ 105,706	$ 113,237
Gathering, compression, processing, and transportation expenses	134,153	148,032
Marketing expenses	52,612	67,082
Interest expense, net	30,834	43,444
Other	77,545	93,275
Total accrued liabilities	$ 400,850	$ 465,070

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2017	Sep. 30, 2019	Dec. 31, 2018	Dec. 21, 2016	Mar. 17, 2015	Sep. 18, 2014	May 06, 2014	Nov. 05, 2013
Long- term Debt
Long-term debt	$ 3,758,868	$ 3,758,868			$ 5,461,688
Gain on extinguishment of debt repurchased		36,419	$ (1,500)
Debt Repurchase Program
Long- term Debt
Gain on extinguishment of debt repurchased	36,000
Notional amount debt repurchased	$ 225,000	225,000
Weighted average discount price	17.00%
Parent (Antero)
Long- term Debt
Net unamortized premium	$ 791	791			1,241
Net unamortized debt issuance costs	(19,464)	(19,464)			(26,700)
Long-term debt	3,758,868	3,758,868			3,829,541
Credit Facility
Long- term Debt
Long-term debt	552,000	552,000			$ 405,000
Current borrowing base	4,500	4,500
Lender commitments	$ 2,640,000	$ 2,640,000		$ 2,500,000
Time period prior to maturity date of senior notes as one option for maturity date of Credit Facility		91 days
Weighted average interest rate (as a percent)	3.28%	3.28%			3.95%
Outstanding letters of credit	$ 623,000	$ 623,000			$ 685,000
Credit Facility | Parent (Antero)
Long- term Debt
Bank credit facility long-term debt	$ 552,000	$ 552,000			405,000
Credit Facility | Minimum
Long- term Debt
Commitment fees on the unused portion during any period that is not an Investment Grade Period (as a percent)		0.30%
Commitment fees on the unused portion during an Investment Grade period (as a percent)		0.15%
Credit Facility | Minimum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate		0.25%
Credit Facility | Minimum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate		0.125%
Credit Facility | Maximum
Long- term Debt
Commitment fees on the unused portion during any period that is not an Investment Grade Period (as a percent)		0.375%
Commitment fees on the unused portion during an Investment Grade period (as a percent)		0.30%
Credit Facility | Maximum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate		2.25%
Credit Facility | Maximum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate		1.75%
5.375% senior notes due 2021
Long- term Debt
Interest rate (as a percent)	5.375%	5.375%								5.375%
Senior notes issued										$ 1,000,000
Issue price as percentage of par value										100.00%
Redemption price of the debt instrument in the event of change of control (as a percent)		101.00%
5.375% senior notes due 2021 | Parent (Antero)
Long- term Debt
Long-term notes payable	$ 952,500	$ 952,500			1,000,000
5.375% senior notes due 2021 | On or after November 1, 2019
Long- term Debt
Redemption price		100.00%
Stand-alone revolving note
Long- term Debt
Maximum amount of the Credit Facility	25,000	$ 25,000
Outstanding balance	$ 0	$ 0
Stand-alone revolving note | Other current liabilities
Long- term Debt
Outstanding balance					5,400
Stand-alone revolving note | Lender's Prime Rate
Long- term Debt
Basis spread on variable rate (as a percent)		1.00%
5.125 senior notes due 2022
Long- term Debt
Interest rate (as a percent)	5.125%	5.125%							5.125%
Senior notes issued								$ 500,000	$ 600,000
Issue price as percentage of par value								100.50%	100.00%
Redemption price		101.281%
Redemption price at which notes may be required to be repurchased in event of change of control		101.00%
5.125 senior notes due 2022 | Parent (Antero)
Long- term Debt
Long-term notes payable	$ 923,041	$ 923,041			1,100,000
5.125 senior notes due 2022 | On or after June 1, 2020
Long- term Debt
Redemption price of the debt instrument in the event of change of control (as a percent)		100.00%
5.625% senior notes due 2023
Long- term Debt
Interest rate (as a percent)	5.625%	5.625%					5.625%
Senior notes issued							$ 750,000
Issue price as percentage of par value							100.00%
Redemption price		102.813%
Redemption price at which notes may be required to be repurchased in event of change of control		101.00%
5.625% senior notes due 2023 | Parent (Antero)
Long- term Debt
Long-term notes payable	$ 750,000	$ 750,000			750,000
5.625% senior notes due 2023 | On Or After June 1, 2021
Long- term Debt
Redemption price		100.00%
5.375% senior notes due 2024
Long- term Debt
Interest rate (as a percent)	5.375%	5.375%
5.00% senior notes due 2025
Long- term Debt
Interest rate (as a percent)	5.00%	5.00%				5.00%
Senior notes issued						$ 600,000
Issue price as percentage of par value						100.00%
Redemption price at which notes may be required to be repurchased in event of change of control		101.00%
5.00% senior notes due 2025 | Parent (Antero)
Long- term Debt
Long-term notes payable	$ 600,000	$ 600,000			600,000
5.00% senior notes due 2025 | Prior to March 1, 2020
Long- term Debt
Redemption price		100.00%
5.00% senior notes due 2025 | On or before March 1, 2020
Long- term Debt
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings		35.00%
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)		105.00%
5.00% senior notes due 2025 | On or after March 1, 2020
Long- term Debt
Redemption price		103.75%
5.00% senior notes due 2025 | On or after March1, 2023
Long- term Debt
Redemption price		100.00%
Reportable legal entity | Parent (Antero)
Long- term Debt
Long-term debt	$ 3,758,868	$ 3,758,868			3,829,541
Gain on extinguishment of debt repurchased		$ 36,419	$ (1,205)
Antero Midstream Partners LP
Long- term Debt
Net unamortized debt issuance costs					(7,853)
Long-term debt					1,632,147
Antero Midstream Partners LP | Midstream Credit Facility
Long- term Debt
Bank credit facility long-term debt					990,000
Antero Midstream Partners LP | 5.375% senior notes due 2024
Long- term Debt
Long-term notes payable					$ 650,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 58,979	$ 34,610
Obligations settled	(153)
Obligations incurred	2,312	9,981
Revisions to prior estimates	(2,537)	11,569
Accretion expense	3,762	2,819	$ 2,610
Effect of deconsolidation of Antero Midstream Partners LP	(7,518)
Asset retirement obligations - end of period	$ 54,845	$ 58,979	$ 34,610

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	12 Months Ended
	Jan. 31, 2020	Mar. 12, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stock-based compensation expense
Number of stock-based compensation awards authorized			16,906,500
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01
Number of shares available for future grant under the Plan			6,297,751
Granted (in shares)	4,644,934
Equity based compensation expense recognized			$ 23,559	$ 70,414	$ 103,445
Midstream Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized			10,000,000
Restricted stock awards
Stock-based compensation expense
Granted (in shares)			1,745,784
Equity based compensation expense recognized			$ 10,343	41,505	70,866
Stock options
Stock-based compensation expense
Equity based compensation expense recognized			$ 355	1,799	2,375
Performance share unit awards
Stock-based compensation expense
Granted (in shares)			1,416,378
Equity based compensation expense recognized			$ 8,069	9,659	10,797
Antero Midstream Partners Phantom Unit Awards
Stock-based compensation expense
Granted (in shares)		5,972
Equity based compensation expense recognized			3,425	15,351	17,461
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized			$ 1,367	$ 2,100	$ 1,946
Antero Midstream Corporation | Midstream Plan
Stock-based compensation expense
Conversion rate of units converted into restricted stock			1.8926
Common stock, par value (in dollars per share)			$ 0.01
Antero Midstream Corporation | Midstream Plan | Common Stock
Stock-based compensation expense
Conversion rate of units converted into restricted stock			1

Equity-Based Compensation - Res

Equity-Based Compensation - Restricted Stock and RSU Awards (Details) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)$ / sharesshares
Number of shares
Granted (in shares) | shares	4,644,934
Vested (in shares) | shares		(730,343)
Weighted average grant date fair value
Vested (in dollars per share) | $ / shares		$ 27.60
Restricted stock awards
Number of shares
Total awarded and unvested at the beginning of the period (in shares) | shares	2,370,575	1,712,485
Granted (in shares) | shares		1,745,784
Vested (in shares) | shares		(357,351)
Total awarded and unvested at the end of the period (in shares) | shares		2,370,575
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares		$ 24.57
Granted (in dollars per share) | $ / shares		8.14
Vested (in dollars per share) | $ / shares		16.09
Forfeited (in dollars per share) | $ / shares		$ 12.81
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares
Aggregate intrinsic value
Total awarded and unvested at the beginning of the period | $	$ 6,756	$ 16,080
Total awarded and unvested at the end of the period | $		6,756
Additional equity compensation to be recognized over the remaining period | $		$ 21,000
Weighted average period for recognizing unrecognized stock-based compensation expense		2 years 4 months 24 days

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Options (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Intrinsic Value
Outstanding at the beginning of the period	$ 12,470
Outstanding at the end of the period	$ 4,992	$ 12,470
Stock options
Stock options
Outstanding at the beginning of the period (in shares)	579,617
Options forfeited (in shares)	(4,250)
Options expired (in shares)	(107,734)
Outstanding at the end of the period (in shares)	467,633	579,617
Vested or expected to vest (in shares)	467,633
Exercisable (in shares)	467,633
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.55
Options forfeited (in dollars per share)	50.18
Outstanding at the end of the period (in dollars per share)	50.64	$ 50.55
Vested or expected to vest (in dollars per share)	50.64
Exercisable (in dollars per share)	$ 50.64
Weighted average remaining contractual life
Outstanding	5 years 18 days	5 years 9 months 21 days
Vested or expected to vest	5 years 18 days
Exercisable	5 years 18 days
Weighted-average assumptions used to calculate fair value of stock options granted
Dividend yield (as a percent)	0.00%
Additional disclosures
Unamortized equity based compensation expense	$ 0
Stock options | Maximum
Stock-based compensation
Contractual life	10 years

Equity-Based Compensation - PSU

Equity-Based Compensation - PSU awards (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	10 Months Ended	12 Months Ended			24 Months Ended
	Jan. 31, 2020	Mar. 12, 2019	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2016	Dec. 31, 2017
Number of units
Granted (in shares)	4,644,934
Vested (in shares)				(730,343)
Weighted average grant date fair value
Vested (in dollars per share)				$ 27.60
Aggregate intrinsic value
Outstanding at the beginning of the period	$ 4,992	$ 12,470	$ 13,476	$ 12,470
Outstanding at the end of the period		$ 13,476	$ 4,992	$ 4,992	$ 12,470
Performance share unit awards
Number of units
Total awarded and unvested at the beginning of the period (in shares)	2,537,283	1,767,299		1,767,299
Granted (in shares)				1,416,378
Exercised (in shares)				(31,944)
Vested (in shares)				(326,938)
Forfeited (in shares)				(287,512)
Total awarded and unvested at the end of the period (in shares)			2,537,283	2,537,283	1,767,299
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share)	$ 16.74	$ 26.36		$ 26.36
Granted (in dollars per share)				9.26
Excercised (in dollars per share)				27.38
Vested (in dollars per share)				32.97
Forfeited (in dollars per share)				19.38
Total awarded and unvested at the end of the period (in dollars per share)			$ 16.74	16.74	$ 26.36
Weighted-average assumptions used to calculate fair value of performance share units granted
Weighted average fair value of awards granted (in dollars per share)				$ 9.26
Price target and TSR performance share unit awards
Price target as a percentage of beginning price				125.00%
Vesting period					3 years
Amortization period of PSU expense					3 years
Price target and TSR performance share unit awards | Minimum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent					0.00%
Price target and TSR performance share unit awards | Maximum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent					200.00%
Price target performance share unit awards
Number of successive days closing stock price must achieve specific thresholds for PSUs to vest per schedule						10 days
Vesting period				3 years
Price target performance share unit awards | Vesting before first anniversary | Maximum
Number of PSUs that may vest, as a percent						0.00%
Price target performance share unit awards | Vesting before the second anniversary | Maximum
Number of PSUs that may vest, as a percent						33.33%
Price target performance share unit awards | Vesting before the third anniversary | Maximum
Number of PSUs that may vest, as a percent				66.66%
TSR performance share unit awards
Price target as a percentage of beginning price				125.00%
Vesting period				3 years			3 years
TSR performance share unit awards | Minimum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent				0.00%			0.00%
TSR performance share unit awards | Maximum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent				200.00%
ROCE performance share unit awards
Vesting period					3 years
ROCE performance share unit awards | Minimum
Number of PSUs that may vest, as a percent					0.00%
ROCE performance share unit awards | Maximum
Number of PSUs that may vest, as a percent					200.00%
Market-Based PSUs
Weighted average grant date fair value
Granted (in dollars per share)				$ 9.26	$ 24.85
Additional disclosures
Additional equity compensation to be recognized over the remaining period			$ 17,000	$ 17,000
Weighted average period for recognizing unrecognized stock-based compensation expense				1 year 9 months 18 days
Weighted-average assumptions used to calculate fair value of performance share units granted
Dividend yield (as a percent)					0.00%
Volatility (as a percent)				36.00%	41.00%
Risk-free interest rate (as a percent)				2.35%	2.49%
Weighted average fair value of awards granted (in dollars per share)				$ 9.26	$ 24.85

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	2 Months Ended	10 Months Ended	12 Months Ended
	Jan. 31, 2020	Mar. 12, 2019	Dec. 31, 2019	Dec. 31, 2019
Number of units
Granted (in shares)	4,644,934
Vested (in shares)				(730,343)
Weighted average grant date fair value
Vested (in dollars per share)				$ 27.60
Aggregate intrinsic value
Outstanding at the beginning of the period	$ 4,992	$ 12,470	$ 13,476	$ 12,470
Outstanding at the end of the period		$ 13,476	$ 4,992	$ 4,992
Antero Midstream Partners Phantom Unit Awards
Number of units
Total awarded and unvested at the beginning of the period (in shares)	657,757	583,000	564,781	583,000
Granted (in shares)		5,972
Effect of conversion			504,119
Vested (in shares)		(3,853)	(362,191)
Forfeited (in shares)		(20,338)	(48,952)
Total awarded and unvested at the end of the period (in shares)		564,781	657,757	657,757
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share)	$ 14.71	$ 27.63	$ 27.59	$ 27.63
Granted (in dollars per share)		23.44
Effect of conversion (in dollars per share)			14.58
Vested (in dollars per share)		32.44	14.35
Forfeited (in dollars per share)		26.73	14.51
Total awarded and unvested at the end of the period (in dollars per share)		$ 27.59	$ 14.71	$ 14.71
Aggregate intrinsic value
Additional equity compensation to be recognized over the remaining period			$ 6,000	$ 6,000
Weighted average period for recognizing unrecognized stock-based compensation expense				1 year 8 months 12 days
Antero Midstream Corporation | Midstream Plan
Aggregate intrinsic value
Conversion rate of units converted into restricted stock				1.8926

Financial Instruments (Details)

Financial Instruments (Details) - USD ($) $ in Billions	Dec. 31, 2019	Dec. 31, 2018
Recurring | Level 2 market data
Financial Instruments
Fair value of senior notes	$ 2.8	$ 3.9

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)MMBTU / d$ / bbl$ / MMBTU$ / galbbl	Dec. 31, 2018USD ($)
Commodity derivative
Derivative Instruments
Gross amounts on balance sheet | $	$ 882,817	$ 658,830
Swaps | NYMEX | Year ending December 31, 2020
Derivative Instruments
Weighted average index price | $ / bbl	2.87
Swaps | NYMEX | Year ending December 31, 2021
Derivative Instruments
Weighted average index price | $ / MMBTU	2.80
Swaps | NYMEX | Year ending December 31, 2023
Derivative Instruments
Weighted average index price | $ / MMBTU	2.91
Swaps | ARA Propane | Year ending December 31, 2020
Derivative Instruments
Weighted average index price | $ / gal	0.65
Swaps | FEI Propane | Three months ending March 31, 2020
Derivative Instruments
Weighted average index price | $ / MMBTU	0.81
Swaps | Mont Belvieu Butane Non-TET | Three months ending March 31, 2020
Derivative Instruments
Weighted average index price | $ / gal	0.50
Swaps | Mont Belvieu Propane Non-TET | Three months ending March 31, 2020
Derivative Instruments
Weighted average index price | $ / gal	0.58
Swaps | NYMEX-WTI | Year ending December 31, 2020
Derivative Instruments
Weighted average index price | $ / gal	55.63
Swaps | Natural gas | Year ending December 31, 2020
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	2,227,500
Swaps | Natural gas | NYMEX | Year ending December 31, 2020
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	2,227,500
Swaps | Natural gas | NYMEX | Year ending December 31, 2021
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	2,400,000
Swaps | Natural gas | NYMEX | Year ending December 31, 2023
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	90,000
Swaps | Natural gas liquids
Derivative Instruments
Notional amount	18,800
Swaps | Natural gas liquids | Three months ending March 31, 2020
Derivative Instruments
Notional amount	17,383
Swaps | Natural gas liquids | Year ending December 31, 2020
Derivative Instruments
Notional amount	10,371
Swaps | Natural gas liquids | ARA Propane | Year ending December 31, 2020
Derivative Instruments
Notional amount	10,371
Swaps | Natural gas liquids | FEI Propane | Three months ending March 31, 2020
Derivative Instruments
Notional amount	9,883
Swaps | Natural gas liquids | Mont Belvieu Butane Non-TET | Three months ending March 31, 2020
Derivative Instruments
Notional amount	6,000
Swaps | Natural gas liquids | Mont Belvieu Propane Non-TET | Three months ending March 31, 2020
Derivative Instruments
Notional amount	1,500
Swaps | Oil | Year ending December 31, 2020
Derivative Instruments
Notional amount	26,000
Swaps | Oil | NYMEX-WTI | Year ending December 31, 2020
Derivative Instruments
Notional amount	26,000

Derivative Instruments (Details

Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2019MMBTU / d$ / MMBTUbbl
NYMEX to TCO | Year ending December 31, 2020
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.24
NYMEX to TCO | Year ending December 31, 2021
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.35
NYMEX to TCO | Year ending December 31, 2022
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.41
NYMEX to TCO | Year ending December 31, 2023
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.52
NYMEX to TCO | Year ending December 31, 2024
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.53
ARA to Mont Belvieu Non-TET | Year ending December 31, 2020
Derivative Instruments
Weighted average hedged differential | $ / MMBTU	0.22
Swaps
Derivative Instruments
Weighted average payout ratio	80
Swaps | Mont Belvieu Propane to NYMEX-WTI | Year ending December 31, 2020
Derivative Instruments
Weighted average payout ratio	50
Swaps | Mont Belvieu Natural Gasoline to NYMEX-WTI | Year ending December 31, 2021
Derivative Instruments
Weighted average payout ratio	78
Natural gas | Swaps | Year ending December 31, 2020
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	2,227,500
Natural gas | Swaps | NYMEX to TCO | Year ending December 31, 2021
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	60,000
Natural gas | Swaps | NYMEX to TCO | Year ending December 31, 2022
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	40,000
Natural gas | Swaps | NYMEX to TCO | Year ending December 31, 2023
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	60,000
Natural gas | Swaps | NYMEX to TCO | Year ending December 31, 2024
Derivative Instruments
Notional amount (MMBtu/day) | MMBTU / d	50,000
Oil | Swaps | Year ending December 31, 2020
Derivative Instruments
Notional amount	26,000
Natural gas liquids | Swaps
Derivative Instruments
Notional amount	18,800
Natural gas liquids | Swaps | Year ending December 31, 2020
Derivative Instruments
Notional amount	10,371
Natural gas liquids | Swaps | NYMEX to TCO | Year ending December 31, 2020
Derivative Instruments
Notional amount	2,670
Natural gas liquids | Swaps | ARA to Mont Belvieu Non-TET | Year ending December 31, 2020
Derivative Instruments
Notional amount	1,602
Natural gas liquids | Swaps | Mont Belvieu Propane to NYMEX-WTI | Year ending December 31, 2020
Derivative Instruments
Notional amount	500
Natural gas liquids | Swaps | Mont Belvieu Natural Gasoline to NYMEX-WTI | Year ending December 31, 2021
Derivative Instruments
Notional amount	18,650

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) $ in Thousands	Dec. 31, 2019USD ($)item	Dec. 31, 2018USD ($)item
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 422,849	$ 245,263
Noncurrent portion of fair value of derivative assets	333,174	362,169
Current portion of fair value of derivative liabilities	6,721	532
Noncurrent portion of fair value of derivative liabilities	3,519
Commodity derivative
Fair value of derivative instruments
Total asset derivatives	756,023	607,432
Total liability derivatives	10,240	532
Derivatives not designated as hedges for accounting purposes
Fair value of derivative instruments
Total asset derivatives	756,023	607,432
Total liability derivatives	10,240	532
Derivatives not designated as hedges for accounting purposes | Commodity derivative
Fair value of derivative instruments
Current portion of fair value of derivative assets	422,849	245,263
Noncurrent portion of fair value of derivative assets	333,174	362,169
Current portion of fair value of derivative liabilities	6,721	$ 532
Noncurrent portion of fair value of derivative liabilities	$ 3,519
Derivatives designated as hedges for accounting purposes
Fair value of derivative instruments
Number of derivative instruments held designated as hedges | item	0	0
Net derivatives	$ 745,783	$ 606,900

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - Commodity derivative - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Commodity derivative assets
Gross amounts on balance sheet	$ 882,817	$ 658,830
Gross amounts offset on balance sheet	(126,794)	(51,398)
Total asset derivatives	756,023	607,432
Commodity derivative liabilities
Gross amounts on balance sheet	(137,034)	(51,930)
Gross amounts offset on balance sheet	126,794	51,398
Total liability derivatives	$ (10,240)	$ (532)

Derivative Instruments - Fair_2

Derivative Instruments - Fair value gains (losses) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)		$ 463,972	$ (87,594)	$ 658,283
Marketing Derivative		0	94,081	(21,394)
Proceeds from marketing derivative			73,000
Commodity derivative fair value gains (losses) on derivatives monetized prior to settlement dates			370,000	750,000
Premium paid for a collar agreement	$ 13,000
Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)		$ 463,972	(87,594)	658,283
Marketing Derivative			$ 94,081	$ (21,394)

Leases (Details)

Leases (Details)	12 Months Ended
	Dec. 31, 2019
Leases
Options to renew - Operating lease	true
Options to renew - Finance lease	true
Minimum
Leases
Renewal terms - Operating lease	1 year
Maximum
Leases
Renewal terms - Operating lease	20 years

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information Related to Leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lease Assets
Operating leases right-of-use assets	$ 2,886,500
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Current
Finance leases, right of use assets	$ 2,498
Finance leases, accumulated amortization	9,000
Short-term lease liabilities, operating leases	304,398
Long-term lease liabilities, operating leases	$ 2,582,102
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Noncurrent
Total lease liabilities, operating leases	$ 2,886,500
Operating Lease, Liability, Statement of Financial Position [Extensible List]	ar:OperatingAndFinanceLeaseLiabilityCurrent ar:OperatingAndFinanceLeaseLiabilityNoncurrent
Short-term lease liabilities, finance leases	$ 923
Long-term lease liabilities, finance leases	1,575
Total	2,498
Vehicles
Lease Assets
Operating leases right-of-use assets	4,983
Finance leases, right of use assets	2,328
Other office and field equipment
Lease Assets
Operating leases right-of-use assets	166
Finance leases, right of use assets	170
Processing plants
Lease Assets
Operating leases right-of-use assets	1,460,770
Drilling and completion rigs
Lease Assets
Operating leases right-of-use assets	71,662
Gas gathering lines and compressor stations
Lease Assets
Operating leases right-of-use assets	1,308,428
Gas gathering lines and compressor stations | Antero Midstream Corporation
Lease Assets
Finance leases, accumulated amortization	1,100,000
Office space
Lease Assets
Operating leases right-of-use assets	$ 40,491

Leases - Supplemental Informati

Leases - Supplemental Information Related to Leases (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases
Total Lease Expense	$ 864,360
Capitalized operating leases	195,000
Short-term lease costs	163,000
Cash paid for amounts included in the measurement of lease liabilities: Operating cash out flows related to operating leases	809,667
Cash paid for amounts included in the measurement of lease liabilities: Investing cash out flows related to operating leases	178,898
Cash paid for amounts included in the measurement of lease liabilities for operating leases	988,565
Cash paid for amounts included in the measurement of lease liabilities: Financing cash out flows related to financing leases	2,507
Cash paid for amounts included in the measurement of lease liabilities for finance leases	2,507
Leased assets obtained in exchange for new operating lease liabilities	3,720,945
Gathering, compression, water handling and treatment
Leases
Total Lease Expense	842,440
General and administrative
Leases
Total Lease Expense	11,228
Contract termination and rig stacking
Leases
Total Lease Expense	10,692
Maximum
Leases
Finance leases, interest expense	1,000
Capitalized finance leases	$ 1,000

Leases - Maturities of Lease Li

Leases - Maturities of Lease Liabilities (Details) $ in Thousands	Dec. 31, 2019USD ($)
Future minimum payments for operating lease liabilities
2020	$ 622,056
2021	554,000
2022	542,952
2023	538,771
2024	530,003
Thereafter	1,851,738
Total lease payments	4,639,520
Less: imputed interest	(1,753,020)
Total lease liabilities, operating leases	2,886,500
Future minimum payments for financing lease liabilities
2020	244
2021	1,007
2022	1,205
2023	42
Total lease payments	2,498
Total	2,498
Future minimum payments for total lease liabilities
2020	622,300
2021	555,007
2022	544,157
2023	538,813
2024	530,003
Thereafter	1,851,738
Total lease payments	4,642,018
Less: imputed interest	(1,753,020)
Total	$ 2,888,998

Leases - Office and equipment l

Leases - Office and equipment leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Future minimum payments for operating lease liabilities
2020	$ 622,056
2021	554,000
2022	542,952
2023	538,771
2024	530,003
Thereafter	1,851,738
Total lease payments	4,639,520
Less: imputed interest	(1,753,020)
Total lease liabilities, operating leases	2,886,500
Office and Equipment Leases
Future minimum payments for operating lease liabilities
2020	10,061
2021	9,002
2022	7,232
2023	4,803
2024	4,792
Thereafter	27,258
Total lease payments	63,148
Less: imputed interest	(15,009)
Total lease liabilities, operating leases	48,139
Office Leases
Future minimum payments for operating lease liabilities
2020	6,145
2021	6,071
2022	6,027
2023	4,761
2024	4,792
Thereafter	27,258
Total lease payments	55,054
Less: imputed interest	(14,562)
Total lease liabilities, operating leases	40,492
Equipment Leases
Future minimum payments for operating lease liabilities
2020	3,916
2021	2,931
2022	1,205
2023	42
Total lease payments	8,094
Less: imputed interest	(447)
Total lease liabilities, operating leases	$ 7,647

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2019
Leases
Weighted-average remaining lease term: Operating lease	8 years 8 months 12 days
Weighted-average discount rate: Operating lease	11.50%
Weighted-average remaining lease term: Finance lease	2 years 1 month 6 days
Weighted-average discount rate: Finance lease	6.00%

Leases - Related party disclosu

Leases - Related party disclosure (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases
Amount included within accounts payable, related parties	$ 97,883
Antero Midstream Corporation
Leases
Utilizing capacity (as a percent)	75.00%
Payment of capacity (as a percent)	70.00%
Term of lease	10 years
Gathering and compression fees paid	$ 643,000
Amount included within accounts payable, related parties	$ 57,000

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income tax expense from continuing operations
Current income tax expense (benefit)		$ 5,048		$ 75
Deferred income tax benefit		(79,158)	$ (128,857)	(295,126)
Total income tax expense from continuing operations		$ (74,110)	$ (128,857)	$ (295,051)
U.S. Statutory federal income tax rate (as a percent)	21.00%	21.00%	21.00%	35.00%
Reconciliation of income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate to consolidated income
Federal income tax expense (benefit)		$ (77,122)	$ (36,657)	$ 171,530
State income tax expense (benefit), net of federal benefit		(8,826)	(12,627)	10,779
Change in Federal tax rate, net of state benefit				(427,962)
Change in State tax rate, net of federal effect		24,041	(40,415)
Nondeductible stock compensation		6,920	6,079	12,098
Dividends received deduction		(4,201)
Noncontrolling interest in Antero Midstream		(10,998)	(73,881)	(59,523)
Deconsolidation adjustment		(6,626)
Change in valuation allowance		1,325	28,116	(2,073)
Other		1,377	528	100
Total income tax expense from continuing operations		(74,110)	(128,857)	(295,051)
Income tax expense (benefit) allocated to continuing and discontinued operations
Total income tax expense from continuing operations		(74,110)	(128,857)	$ (295,051)
Deferred tax assets:
Net operating loss carryforwards		560,136	734,255
Equity based compensation		7,669	10,633
Investment in Antero Midstream Partners LP		172,460
Other		15,754	15,726
Total deferred tax assets		756,019	760,614
Valuation allowance		(46,802)	(45,477)
Net deferred tax assets		709,217	715,137
Deferred tax liabilities:
Unrealized gains on derivative instruments		206,677	271,747
Oil and gas properties		1,284,528	1,055,850
Investment in Antero Midstream			11,258
Other			27,070
Total deferred tax liabilities		1,491,205	1,365,925
Net deferred tax liabilities		(781,987)	(650,788)
Valuation allowance on net operating loss carryforwards		47,000	45,000
State
Deferred tax liabilities:
Valuation allowance on net operating loss carryforwards		$ 47,000	$ 45,000

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) $ in Thousands	Dec. 31, 2019USD ($)
Unrecognized tax benefits
Unrecognized tax benefits	$ 0
U.S Federal
Income Taxes
Net operating loss carryforward	2,200,000
State
Income Taxes
Net operating loss carryforward	$ 2,000,000

Commitments (Details)

Commitments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Future minimum payments
2020	$ 1,787,940
2021	1,688,852
2022	1,632,100
2023	1,654,280
2024	1,605,546
Thereafter	9,911,844
Total	18,280,562
Firm transportation
Future minimum payments
2020	1,105,062
2021	1,076,832
2022	1,034,009
2023	1,056,902
2024	1,016,856
Thereafter	7,907,583
Total	13,197,244
Gas processing, gathering and compression
Future minimum payments
2020	55,338
2021	54,154
2022	53,606
2023	58,565
2024	58,687
Thereafter	152,523
Total	432,873
Land payment obligations
Future minimum payments
2020	5,240
2021	2,859
2022	328
Total	8,427
Operating and Financing Leases
Future minimum payments
2020	304,441
2021	265,838
2022	285,209
2023	313,510
2024	342,348
Thereafter	1,377,652
Total	2,888,998
Imputed Interest for Leases
Future minimum payments
2020	317,859
2021	289,169
2022	258,948
2023	225,303
2024	187,655
Thereafter	474,086
Total	$ 1,753,020

Contingencies (Details)

Contingencies (Details)

Jun. 20, 2019USD ($)

Feb. 01, 2018MMBTU / d

Jan. 01, 2018MMBTU / d

Jun. 30, 2018USD ($)

Jan. 31, 2018MMBTU / d

Nov. 30, 2017MMBTU / d

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Nov. 30, 2018MMBTU / d

Mar. 31, 2018USD ($)

Mar. 31, 2017USD ($)

Contingencies

Revenues from contracts with customers

$ 3,940,558,000

$ 4,133,139,000

$ 3,018,685,000

Production and ad valorem taxes

125,142,000

126,474,000

94,521,000

Interest

(228,111,000)

(286,743,000)

(268,701,000)

Accrued revenue

317,886,000

474,827,000

Accounts receivable

46,419,000

51,073,000

Natural gas sales

Contingencies

Revenues from contracts with customers

2,247,162,000

$ 2,287,939,000

$ 1,769,284,000

Doddridge County, Tyler County and Ritchie County, West Virginia | Minimum

Contingencies

Settlement amount

$ 100,000

SJGC | Settled Litigation

Contingencies

Settlement amount received

$ 82,000,000

WGL

Contingencies

Natural gas long term purchase contract volume increase after specified events (in MMBtu)/day | MMBTU / d

530,000

Damages awarded

$ 96,000,000

WGL | Pending Litigation

Contingencies

Damages sought

$ 40,000,000

$ 30,000,000

WGL - Braxton, West Virginia

Contingencies

Natural gas long term purchase contract volume (in MMBtu)/day | MMBTU / d

200,000

500,000

WGL - Loudoun County, Virginia

Contingencies

Natural gas long term purchase contract volume increase after specified events (in MMBtu)/day | MMBTU / d

330,000

Potential Positive Outcome of Litigation | WGL

Contingencies

Natural gas long term purchase contract volume (in MMBtu)/day | MMBTU / d

500,000

600,000

Contract Termination and Rig _2

Contract Termination and Rig Stacking (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Contract Termination and Rig Stacking
Costs for delay or cancelation of drilling and completion contracts with third-party contractors	$ 14,026

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Sales and revenues:
Sales and revenues									$ 4,400,102	$ 4,139,626	$ 3,655,574
Sales and revenues	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	4,408,690	4,139,626	3,655,574
Operating expenses:
Water earnout									(125,000)
Impairment of oil and gas properties									1,300,444	549,437	159,598
Impairment of midstream assets									14,782	9,658	23,431
Impairment of equity investments									467,590
Depletion, depreciation, and amortization									914,867	972,465	824,610
General and administrative									178,696	240,344	251,196
Other operating expenses									694,579	820,306	471,950
Total operating expenses	1,020,194	2,104,759	1,199,668	1,071,114	1,092,279	1,071,728	1,022,107	881,607	5,395,735	4,067,721	2,915,481
Operating income (loss)	(67,456)	$ (985,878)	$ 99,996	$ (33,707)	(46,630)	$ 4,804	$ (32,763)	$ 146,494	(987,045)	71,905	740,093
Equity in earnings (loss) of unconsolidated affiliates									(143,216)	40,280	20,194
Investments in unconsolidated affiliates	1,055,177				433,642				1,055,177	433,642
Segment assets	15,197,569				15,519,464				15,197,569	15,519,464	15,261,490
Capital expenditures for segment assets									1,422,155	2,210,586	2,216,753
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues									4,107,845	3,565,300	3,406,203
Sales and revenues									4,113,657	3,477,828	3,423,561
Operating expenses:
Impairment of oil and gas properties									1,300,444	549,437	159,598
Depletion, depreciation, and amortization									893,161	841,645	704,152
General and administrative									160,402	181,305	195,153
Other operating expenses									143,762	129,947	101,980
Total operating expenses									4,901,858	3,637,466	2,695,770
Operating income (loss)									(788,201)	(159,638)	727,791
Segment assets	14,121,523				12,986,945				14,121,523	12,986,945	13,074,027
Capital expenditures for segment assets									1,369,003	1,923,488	1,859,481
Operating segments | Marketing
Sales and revenues:
Sales and revenues									292,207	552,982	236,651
Sales and revenues									292,207	552,982	236,651
Operating expenses:
Other operating expenses									549,814	686,055	366,281
Total operating expenses									549,814	686,055	366,281
Operating income (loss)									(257,607)	(133,073)	(129,630)
Segment assets	20,869				34,499				20,869	34,499	36,701
Operating segments | Antero Midstream Corporation
Sales and revenues:
Sales and revenues									50	21,344	12,720
Sales and revenues									792,588	1,028,522	772,497
Operating expenses:
Impairment of midstream assets									776,832	9,658	23,431
Depletion, depreciation, and amortization									95,526	130,820	120,458
General and administrative									118,113	61,629	58,812
Other operating expenses									12,093	(88,715)	17,165
Total operating expenses									1,205,953	425,646	448,715
Operating income (loss)									(413,365)	602,876	323,782
Equity in earnings (loss) of unconsolidated affiliates									51,315	40,280	20,194
Investments in unconsolidated affiliates	709,639								709,639
Segment assets	6,282,878				3,542,862				6,282,878	3,542,862	3,057,459
Capital expenditures for segment assets									391,990	542,112	540,719
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues									8,588	(919,706)	(777,135)
Sales and revenues									(789,762)	(919,706)	(777,135)
Operating expenses:
Impairment of midstream assets									(762,050)
Depletion, depreciation, and amortization									(73,820)
General and administrative									(99,819)	(2,590)	(2,769)
Other operating expenses									(11,090)	93,019	(13,476)
Total operating expenses									(1,261,890)	(681,446)	(595,285)
Operating income (loss)									472,128	(238,260)	(181,850)
Equity in earnings (loss) of unconsolidated affiliates									(194,531)
Investments in unconsolidated affiliates	345,538								345,538
Segment assets	$ (5,227,701)				$ (1,044,842)				(5,227,701)	(1,044,842)	(906,697)
Capital expenditures for segment assets									(338,838)	(255,014)	(183,447)
Elimination of intersegment transaction | Exploration and production
Sales and revenues:
Sales and revenues									5,812	(87,472)	17,358
Elimination of intersegment transaction | Antero Midstream Corporation
Sales and revenues:
Sales and revenues									792,538	1,007,178	759,777
Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									2,146,647	1,339,358	1,095,639
Gathering, compression, water handling and treatment | Operating segments | Exploration and production
Operating expenses:
Cost of goods and services sold									2,257,099	1,792,898	1,441,129
Gathering, compression, water handling and treatment | Operating segments | Antero Midstream Corporation
Operating expenses:
Cost of goods and services sold									41,013	49,550	39,147
Gathering, compression, water handling and treatment | Elimination of intersegment transaction
Operating expenses:
Cost of goods and services sold									(151,465)	(503,090)	(384,637)
Lease operating
Operating expenses:
Cost of goods and services sold									145,720	136,153	89,057
Lease operating | Operating segments | Exploration and production
Operating expenses:
Cost of goods and services sold									146,990	142,234	93,758
Lease operating | Operating segments | Antero Midstream Corporation
Operating expenses:
Cost of goods and services sold									162,376	262,704	189,702
Lease operating | Elimination of intersegment transaction
Operating expenses:
Cost of goods and services sold									$ (163,646)	$ (268,785)	$ (194,403)

Condensed Consolidating Finan_3

Condensed Consolidating Financial Information - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Accounts receivable, net	$ 46,419	$ 51,073
Accounts receivable, related parties	125,000
Accrued revenue	317,886	474,827
Derivative instruments	422,849	245,263
Other current assets	10,731	35,450
Total current assets	922,885	806,613
Unproved properties	1,368,854	1,767,600
Proved properties	11,859,817	12,705,672
Water handling and treatment systems		1,013,818
Gathering systems and facilities	5,802	2,470,708
Other property and equipment	71,895	65,842
Property and equipment, gross	13,306,368	18,023,640
Less accumulated depletion, depreciation, and amortization	(3,327,629)	(4,153,725)
Property and equipment, net	9,978,739	13,869,915
Operating leases right-of-use assets	2,886,500
Derivative instruments	333,174	362,169
Investments in unconsolidated affiliates	1,055,177	433,642
Other assets	21,094	47,125
Total assets	15,197,569	15,519,464	$ 15,261,490
Liabilities and Stockholders' Equity
Accounts payable	14,498	66,289
Accounts payable, related parties	97,883
Accrued liabilities	400,850	465,070
Revenue distributions payable	207,988	310,827
Derivative instruments	6,721	532
Short-term lease liabilities	305,320	2,459
Other current liabilities	6,879	8,363
Total current liabilities	1,040,139	853,540
Long-term debt	3,758,868	5,461,688
Deferred income tax liability	781,987	650,788
Derivative instruments	3,519
Long-term lease liabilities	2,583,678	2,873
Other liabilities	58,635	63,098
Total liabilities	8,226,826	7,031,987
Common stock	2,959	3,086
Additional paid-in capital	6,130,365	6,485,174
Accumulated earnings	837,419	1,177,548
Total stockholders' equity	6,970,743	7,665,808
Noncontrolling interests in consolidated subsidiary		821,669
Total equity	6,970,743	8,487,477	$ 8,876,136	$ 7,728,578
Total liabilities and equity	15,197,569	15,519,464
Parent (Antero)
Liabilities and Stockholders' Equity
Long-term debt	3,758,868	3,829,541
Reportable legal entity | Parent (Antero)
Current assets:
Accounts receivable, net	46,419	49,529
Accounts receivable, related parties	125,000
Intercompany receivables		383
Accrued revenue	317,886	474,827
Derivative instruments	422,849	245,263
Other current assets	10,731	13,937
Total current assets	922,885	783,939
Unproved properties	1,368,854	1,767,600
Proved properties	11,859,817	13,306,585
Gathering systems and facilities	5,802	17,825
Other property and equipment	71,895	65,770
Property and equipment, gross	13,306,368	15,157,780
Less accumulated depletion, depreciation, and amortization	(3,327,629)	(3,654,392)
Property and equipment, net	9,978,739	11,503,388
Operating leases right-of-use assets	2,886,500
Derivative instruments	333,174	362,169
Investment in consolidated affiliates	812,129	(740,031)
Contingent acquisition consideration		114,995
Investments in unconsolidated affiliates	243,048
Other assets	21,094	31,200
Total assets	15,197,569	12,055,660
Liabilities and Stockholders' Equity
Accounts payable	14,498	44,917
Accounts payable, related parties	397,333
Intercompany payable		111,620
Accrued liabilities	400,850	392,949
Revenue distributions payable	207,988	310,827
Derivative instruments	6,721	532
Short-term lease liabilities	305,320	2,459
Other current liabilities	6,879	2,162
Total current liabilities	1,339,589	865,466
Long-term debt	3,758,868	3,829,541
Deferred income tax liability	781,987	650,788
Derivative instruments	3,519
Long-term lease liabilities	2,583,678	2,873
Other liabilities	58,635	55,017
Total liabilities	8,526,276	5,403,685
Common stock	2,959	3,086
Additional paid-in capital	5,600,714	5,471,341
Accumulated earnings	1,067,620	1,177,548
Total stockholders' equity	6,671,293	6,651,975
Total equity		6,651,975
Total liabilities and equity	15,197,569	12,055,660
Reportable legal entity | Guarantor Subsidiaries
Current assets:
Accounts receivable, related parties	299,450
Total current assets	299,450
Investments in unconsolidated affiliates	812,129
Total assets	1,111,579
Liabilities and Stockholders' Equity
Additional paid-in capital	1,341,780
Accumulated earnings	(230,201)
Total stockholders' equity	1,111,579
Total liabilities and equity	1,111,579
Reportable legal entity | Non-Guarantor Subsidiaries
Current assets:
Accounts receivable, net		1,544
Intercompany receivables		115,378
Other current assets		21,513
Total current assets		138,435
Water handling and treatment systems		1,004,793
Gathering systems and facilities		2,452,883
Other property and equipment		72
Property and equipment, gross		3,457,748
Less accumulated depletion, depreciation, and amortization		(499,333)
Property and equipment, net		2,958,415
Investments in unconsolidated affiliates		433,642
Other assets		15,925
Total assets		3,546,417
Liabilities and Stockholders' Equity
Accounts payable		21,372
Intercompany payable		4,141
Accrued liabilities		72,121
Other current liabilities		2,052
Total current liabilities		99,686
Long-term debt		1,632,147
Contingent acquisition consideration		114,995
Other liabilities		8,081
Total liabilities		1,854,909
Partners' capital		1,691,508
Total stockholders' equity		1,691,508
Total equity		1,691,508
Total liabilities and equity		3,546,417
Eliminations
Current assets:
Accounts receivable, related parties	(299,450)
Intercompany receivables		(115,761)
Total current assets	(299,450)	(115,761)
Proved properties		(600,913)
Water handling and treatment systems		9,025
Property and equipment, gross		(591,888)
Property and equipment, net		(591,888)
Investment in consolidated affiliates	(812,129)	740,031
Contingent acquisition consideration		(114,995)
Total assets	(1,111,579)	(82,613)
Liabilities and Stockholders' Equity
Accounts payable, related parties	(299,450)
Intercompany payable		(115,761)
Other current liabilities		4,149
Total current liabilities	(299,450)	(111,612)
Contingent acquisition consideration		(114,995)
Total liabilities	(299,450)	(226,607)
Partners' capital		(1,691,508)
Additional paid-in capital	(812,129)	1,013,833
Total stockholders' equity	(812,129)	(677,675)
Noncontrolling interests in consolidated subsidiary		821,669
Total equity		143,994
Total liabilities and equity	$ (1,111,579)	$ (82,613)

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information - Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue and other:
Revenues from contracts with customers									$ 3,940,558	$ 4,133,139	$ 3,018,685
Commodity derivative fair value gains (losses)									463,972	(87,594)	658,283
Marketing derivative fair value gains (losses)									0	94,081	(21,394)
Gain on sale of assets									(951)
Total revenue and other	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	4,408,690	4,139,626	3,655,574
Operating expenses:
Water earnout									125,000
Production and ad valorem taxes									125,142	126,474	94,521
Impairment of oil and gas properties									1,300,444	549,437	159,598
Impairment of midstream assets									14,782	9,658	23,431
Impairment of equity investments									(467,590)
Impairment of gathering systems and facilities											23,431
Depletion, depreciation, and amortization									914,867	972,465	824,610
Accretion of asset retirement obligations									3,762	2,819	2,610
General and administrative									178,696	240,344	251,196
Contract termination and rig stacking									14,026
Total operating expenses	1,020,194	2,104,759	1,199,668	1,071,114	1,092,279	1,071,728	1,022,107	881,607	5,395,735	4,067,721	2,915,481
Operating income (loss)	(67,456)	(985,878)	99,996	(33,707)	(46,630)	4,804	(32,763)	146,494	(987,045)	71,905	740,093
Equity in earnings (loss) of unconsolidated affiliates									(143,216)	40,280	20,194
Interest expense, net									(228,111)	(286,743)	(268,701)
Gain (loss) on early extinguishment of debt									36,419		(1,500)
Gain on deconsolidation of Antero Midstream Partners LP				1,406,042					1,406,042
Total other income (expenses)									619,799	(246,463)	(250,007)
Income (loss) before									(367,246)	(174,558)	490,086
Provision for income tax benefit									74,110	128,857	295,051
Net income (loss) and comprehensive income (loss) including noncontrolling interests	(482,196)	(878,864)	42,168	1,025,756	18,736	(77,972)	(67,275)	80,810	(293,136)	(45,701)	785,137
Net income and comprehensive income attributable to noncontrolling interests				46,993	140,282	76,447	69,110	65,977	46,993	351,816	170,067
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (482,196)	$ (878,864)	$ 42,168	$ 978,763	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	(340,129)	(397,517)	615,070
Natural gas sales
Revenue and other:
Revenues from contracts with customers									2,247,162	2,287,939	1,769,284
Natural gas liquids sales
Revenue and other:
Revenues from contracts with customers									1,219,162	1,177,777	870,441
Oil sales
Revenue and other:
Revenues from contracts with customers									177,549	187,178	108,195
Gathering, compression, water handling and treatment
Revenue and other:
Revenues from contracts with customers									4,478	21,344	12,720
Operating expenses:
Cost of goods and services sold									2,146,647	1,339,358	1,095,639
Marketing
Revenue and other:
Revenues from contracts with customers									292,207	458,901	258,045
Operating expenses:
Cost of goods and services sold									549,814	686,055	366,281
Exploration
Operating expenses:
Cost of goods and services sold									884	4,958	8,538
Lease operating
Operating expenses:
Cost of goods and services sold									145,720	136,153	89,057
Other income
Revenue and other:
Revenues from contracts with customers									4,160
Reportable legal entity | Parent (Antero)
Revenue and other:
Commodity derivative fair value gains (losses)									463,972	(87,594)	658,283
Marketing derivative fair value gains (losses)										94,081	(21,394)
Gain on sale of assets									(951)
Total revenue and other									4,405,862	4,031,065	3,660,212
Operating expenses:
Water earnout									125,000
Production and ad valorem taxes									124,202	122,305	90,832
Impairment of oil and gas properties									1,300,444	549,437	159,598
Impairment of midstream assets									7,800	4,470
Impairment of equity investments									(143,090)
Depletion, depreciation, and amortization									893,160	842,452	705,048
Accretion of asset retirement obligations									3,699	2,684	2,610
General and administrative									160,402	181,305	195,153
Contract termination and rig stacking									14,026
Change in fair value of contingent acquisition consideration										(93,019)	13,476
Total operating expenses									5,459,472	4,328,798	3,062,947
Operating income (loss)									(1,053,610)	(297,733)	597,265
Equity in earnings (loss) of unconsolidated affiliates									(49,442)
Interest expense, net									(211,296)	(224,977)	(232,331)
Gain (loss) on early extinguishment of debt									36,419		(1,205)
Equity in earnings (loss) of consolidated subsidiaries									15,021	(3,664)	(43,710)
Gain on deconsolidation of Antero Midstream Partners LP									1,205,705
Total other income (expenses)									869,572	(228,641)	(277,246)
Income (loss) before									(184,038)	(526,374)	320,019
Provision for income tax benefit									74,110	128,857	295,051
Net income (loss) and comprehensive income (loss) including noncontrolling interests									(109,928)	(397,517)	615,070
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(109,928)	(397,517)	615,070
Reportable legal entity | Parent (Antero) | Natural gas sales
Revenue and other:
Revenues from contracts with customers									2,247,162	2,287,939	1,769,975
Reportable legal entity | Parent (Antero) | Natural gas liquids sales
Revenue and other:
Revenues from contracts with customers									1,219,162	1,177,777	870,441
Reportable legal entity | Parent (Antero) | Oil sales
Revenue and other:
Revenues from contracts with customers									177,549	187,178	108,195
Reportable legal entity | Parent (Antero) | Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									2,257,133	1,792,898	1,441,129
Reportable legal entity | Parent (Antero) | Marketing
Revenue and other:
Revenues from contracts with customers									292,207	458,901	258,045
Operating expenses:
Cost of goods and services sold									549,814	686,055	366,281
Reportable legal entity | Parent (Antero) | Exploration
Operating expenses:
Cost of goods and services sold									884	4,958	8,538
Reportable legal entity | Parent (Antero) | Lease operating
Operating expenses:
Cost of goods and services sold									146,957	142,234	93,758
Reportable legal entity | Parent (Antero) | Other income
Revenue and other:
Revenues from contracts with customers									5,810	(87,217)	16,667
Reportable legal entity | Guarantor Subsidiaries
Operating expenses:
Impairment of equity investments									(324,500)
Equity in earnings (loss) of unconsolidated affiliates									(106,038)
Gain on deconsolidation of Antero Midstream Partners LP									200,337
Total other income (expenses)									(230,201)
Income (loss) before									(230,201)
Net income (loss) and comprehensive income (loss) including noncontrolling interests									(230,201)
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(230,201)
Reportable legal entity | Non-Guarantor Subsidiaries
Revenue and other:
Gain on sale of assets										583
Total revenue and other									218,360	1,028,522	772,497
Operating expenses:
Production and ad valorem taxes										4,169	3,689
Impairment of midstream assets									6,982	5,771	23,431
Impairment of gathering systems and facilities											23,431
Depletion, depreciation, and amortization									21,707	130,013	119,562
Accretion of asset retirement obligations									63	135
General and administrative									18,793	61,629	58,812
Accretion of contingent acquisition consideration									1,928	(93,019)
Change in fair value of contingent acquisition consideration										93,019	(13,476)
Total operating expenses									114,291	420,952	447,819
Operating income (loss)									104,069	607,570	324,678
Equity in earnings (loss) of unconsolidated affiliates									12,264	40,280	20,194
Interest expense, net									(16,815)	(61,906)	(37,262)
Gain (loss) on early extinguishment of debt											(295)
Total other income (expenses)									(4,551)	(21,626)	(17,363)
Income (loss) before									99,518	585,944	307,315
Net income (loss) and comprehensive income (loss) including noncontrolling interests									99,518	585,944	307,315
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									99,518	585,944	307,315
Reportable legal entity | Non-Guarantor Subsidiaries | Gathering, compression, water handling and treatment
Revenue and other:
Revenues from contracts with customers									218,360	1,027,939	772,497
Operating expenses:
Cost of goods and services sold										49,550	39,147
Reportable legal entity | Non-Guarantor Subsidiaries | Lease operating
Operating expenses:
Cost of goods and services sold									64,818	262,704	189,702
Eliminations
Revenue and other:
Gain on sale of assets										(583)
Total revenue and other									(215,532)	(919,961)	(777,135)
Operating expenses:
Production and ad valorem taxes									940
Impairment of midstream assets										(583)
General and administrative									(499)	(2,590)	(2,769)
Accretion of contingent acquisition consideration									(1,928)	93,019
Change in fair value of contingent acquisition consideration											13,476
Total operating expenses									(178,028)	(682,029)	(595,285)
Operating income (loss)									(37,504)	(237,932)	(181,850)
Interest expense, net										140	892
Equity in earnings (loss) of consolidated subsidiaries									(15,021)	3,664	43,710
Total other income (expenses)									(15,021)	3,804	44,602
Income (loss) before									(52,525)	(234,128)	(137,248)
Net income (loss) and comprehensive income (loss) including noncontrolling interests									(52,525)	(234,128)	(137,248)
Net income and comprehensive income attributable to noncontrolling interests									46,993	351,816	170,067
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(99,518)	(585,944)	(307,315)
Eliminations | Natural gas sales
Revenue and other:
Revenues from contracts with customers											(691)
Eliminations | Gathering, compression, water handling and treatment
Revenue and other:
Revenues from contracts with customers									(213,882)	(1,006,595)	(759,777)
Operating expenses:
Cost of goods and services sold									(110,486)	(503,090)	(384,637)
Eliminations | Lease operating
Operating expenses:
Cost of goods and services sold									(66,055)	(268,785)	(194,403)
Eliminations | Other income
Revenue and other:
Revenues from contracts with customers									$ (1,650)	$ 87,217	$ (16,667)

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information - Cash Flows (Details) - USD ($) $ in Thousands	Dec. 16, 2019	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests		$ (482,196)	$ (878,864)	$ 42,168	$ 1,025,756	$ 18,736	$ (77,972)	$ (67,275)	$ 80,810	$ (293,136)	$ (45,701)	$ 785,137
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion										918,629	975,284	827,220
Impairment of oil and gas properties										1,300,444	549,437	159,598
Impairment of midstream assets										14,782	9,658	23,431
Asset Impairment Charges										1,782,816
Impairment of gathering systems and facilities												23,431
Commodity derivative fair value (gains) losses										(463,972)	87,594	(658,283)
Gains on settled commodity derivatives										325,090	243,112	213,940
Premium paid on derivative contracts											(13,318)
Proceeds from derivative monetizations											370,365	749,906
Marketing derivative fair value (gains) losses										0	(94,081)	21,394
Gains on settled marketing derivatives											72,687
Deferred income tax expense (benefit)										(79,158)	(128,857)	(295,126)
Gain on sale of assets										951
Equity-based compensation expense										23,559	70,414	103,445
Loss on sale of Antero Midstream Corporation shares										108,745
Loss (gain) on early extinguishment of debt										(36,419)		1,500
Equity in earnings (loss) of unconsolidated affiliates										143,216	(40,280)	(20,194)
Water earnout										(125,000)
Distributions/dividends of earnings from unconsolidated affiliates										157,956	46,415	20,195
Gain on deconsolidation of Antero Midstream Partners LP					$ (1,406,042)					(1,406,042)
Other										10,681	4,681	(1,907)
Changes in current assets and liabilities										35,542	(25,423)	76,035
Net cash provided by operating activities										1,103,458	2,081,987	2,006,291
Cash flows provided by (used in) investing activities:
Additions to proved properties												(175,650)
Additions to unproved properties										(88,682)	(172,387)	(204,272)
Drilling and completion costs										(1,254,118)	(1,488,573)	(1,281,985)
Additions to water handling and treatment systems										(24,416)	(97,699)	(194,502)
Additions to gathering systems and facilities										(48,239)	(444,413)	(346,217)
Additions to other property and equipment										(6,700)	(7,514)	(14,127)
Investments in unconsolidated affiliates										(25,020)	(136,475)	(235,004)
Proceeds from sale of common stock of Antero Midstream Corporation										100,000
Proceeds from the Antero Midstream Partners LP Transactions										296,611
Change in other assets										7,091	(3,663)	(12,029)
Change in other liabilities										7,091
Proceeds from sale of assets										1,983		2,156
Other												2,156
Net cash used in investing activities										(1,041,490)	(2,350,724)	(2,461,630)
Cash flows provided by (used in) financing activities:
Issuance of common stock	$ 100,000
Issuance of common units by Antero Midstream Partners LP												248,956
Repurchases of common stock										(38,772)	(129,084)
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation												311,100
Issuance of senior notes by Antero Midstream Partners LP										650,000
Repayment of senior notes										(191,092)
Borrowings on bank credit facilities, net										232,000	660,379	90,000
Payments of deferred financing costs										(4,547)	(2,169)	(16,377)
Distributions to noncontrolling interests in Antero Midstream Partners LP										(85,076)	(267,271)	(152,352)
Employee tax withholding for settlement of equity compensation awards										(2,389)	(17,020)	(24,174)
Other										(2,560)	(4,539)	(4,983)
Net cash provided by financing activities										557,564	240,296	452,170
Antero Midstream Partners LP cash at deconsolidation										(619,532)
Net increase (decrease) in cash and cash equivalents											(28,441)	(3,169)
Cash and cash equivalents, beginning of period									28,441		28,441	31,610
Cash and cash equivalents, end of period												28,441
Reportable legal entity | Parent (Antero)
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests										(109,928)	(397,517)	615,070
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion										896,859	845,136	707,658
Change in fair value of contingent acquisition consideration											93,019	(13,476)
Impairment of oil and gas properties										1,300,444	549,437	159,598
Impairment of midstream assets										7,800	4,470
Asset Impairment Charges										1,451,334
Commodity derivative fair value (gains) losses										(463,972)	87,594	(658,283)
Gains on settled commodity derivatives										325,090	243,112	213,940
Premium paid on derivative contracts											(13,318)
Proceeds from derivative monetizations											370,365	749,906
Marketing derivative fair value (gains) losses											(94,081)	21,394
Gains on settled marketing derivatives											72,687
Deferred income tax expense (benefit)										(79,158)	(128,857)	(295,126)
Gain on sale of assets										951
Equity-based compensation expense										21,082	49,341	76,162
Loss on sale of Antero Midstream Corporation shares										108,745
Loss (gain) on early extinguishment of debt										(36,419)		1,205
Equity in earnings of consolidated subsidiaries										(15,021)	3,664	43,710
Equity in earnings of affiliates										(15,021)
Equity in earnings (loss) of unconsolidated affiliates										49,442
Water earnout										(125,000)
Distributions/dividends of earnings from unconsolidated affiliates										145,351
Gain on deconsolidation of Antero Midstream Partners LP										(1,205,705)
Distributions from Antero Midstream Partners LP										94,391
Distributions from subsidiaries											159,181	131,598
Other										(37,991)	4,681	(4,500)
Changes in current assets and liabilities										29,307	(26,059)	87,466
Net cash provided by operating activities										1,049,358	1,822,855	1,836,322
Cash flows provided by (used in) investing activities:
Additions to proved properties												(175,650)
Additions to unproved properties										(88,682)	(172,387)	(204,272)
Drilling and completion costs										(1,274,683)	(1,743,587)	(1,455,554)
Additions to gathering systems and facilities											103
Additions to other property and equipment										(5,638)	(7,441)	(14,127)
Proceeds from sale of common stock of Antero Midstream Corporation										100,000
Proceeds from the Antero Midstream Partners LP Transactions										296,611
Change in other assets											(72)	(8,594)
Change in other liabilities										10,448
Proceeds from sale of assets										1,983
Other												2,156
Net cash used in investing activities										(959,961)	(1,923,384)	(1,856,041)
Cash flows provided by (used in) financing activities:
Repurchases of common stock										(38,772)	(129,084)
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation												311,100
Repayment of senior notes										(191,092)
Borrowings on bank credit facilities, net										141,621	225,379	(255,000)
Payments of deferred financing costs										2,921		(10,857)
Employee tax withholding for settlement of equity compensation awards										(2,360)	(11,491)	(18,229)
Other										(1,715)	(4,353)	(4,785)
Net cash provided by financing activities										(89,397)	80,451	22,229
Net increase (decrease) in cash and cash equivalents											(20,078)	2,510
Cash and cash equivalents, beginning of period									20,078		20,078	17,568
Cash and cash equivalents, end of period												20,078
Reportable legal entity | Guarantor Subsidiaries
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests										(230,201)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Asset Impairment Charges										324,500
Equity in earnings (loss) of unconsolidated affiliates										106,038
Gain on deconsolidation of Antero Midstream Partners LP										(200,337)
Reportable legal entity | Non-Guarantor Subsidiaries
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests										99,518	585,944	307,315
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion										21,770	130,148	119,562
Change in fair value of contingent acquisition consideration											(93,019)	13,476
Impairment of midstream assets										6,982	5,771	23,431
Asset Impairment Charges										6,982
Impairment of gathering systems and facilities												23,431
Gain on sale of assets											(583)
Equity-based compensation expense										2,477	21,073	27,283
Loss (gain) on early extinguishment of debt												295
Equity in earnings (loss) of unconsolidated affiliates										(12,264)	(40,280)	(20,194)
Distributions/dividends of earnings from unconsolidated affiliates										12,605	46,415	20,195
Other										750	2,879	2,593
Changes in current assets and liabilities										(10,573)	(788)	(18,160)
Net cash provided by operating activities										121,265	657,560	475,796
Cash flows provided by (used in) investing activities:
Additions to water handling and treatment systems										(24,547)	(88,674)	(195,162)
Additions to gathering systems and facilities										(48,239)	(446,270)	(346,217)
Additions to other property and equipment										(1,062)
Investments in unconsolidated affiliates										(25,020)	(136,475)	(235,004)
Change in other assets											(3,591)	(3,435)
Change in other liabilities										(3,357)	2,273
Other											6,150
Net cash used in investing activities										(102,225)	(666,587)	(779,818)
Cash flows provided by (used in) financing activities:
Issuance of common units by Antero Midstream Partners LP												248,956
Issuance of senior notes by Antero Midstream Partners LP										650,000
Borrowings on bank credit facilities, net										90,379	435,000	345,000
Payments of deferred financing costs										(7,468)	(2,169)	(5,520)
Distributions to noncontrolling interests in Antero Midstream Partners LP										(131,545)	(426,452)	(283,950)
Employee tax withholding for settlement of equity compensation awards										(29)	(5,529)	(5,945)
Other										(845)	(186)	(198)
Net cash provided by financing activities										600,492	664	298,343
Antero Midstream Partners LP cash at deconsolidation										(619,532)
Net increase (decrease) in cash and cash equivalents											(8,363)	(5,679)
Cash and cash equivalents, beginning of period									$ 8,363		8,363	14,042
Cash and cash equivalents, end of period												8,363
Eliminations
Cash flows provided by (used in) operating activities:
Net income (loss) and comprehensive income (loss) including noncontrolling interests										(52,525)	(234,128)	(137,248)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Change in fair value of contingent acquisition consideration												(13,476)
Impairment of midstream assets											(583)
Gain on sale of assets											583
Equity in earnings of consolidated subsidiaries										15,021	(3,664)	(43,710)
Equity in earnings of affiliates										15,021
Distributions from Antero Midstream Partners LP										(94,391)
Distributions from subsidiaries											(159,181)	(131,598)
Other										47,922	(2,879)
Changes in current assets and liabilities										16,808	1,424	6,729
Net cash provided by operating activities										(67,165)	(398,428)	(305,827)
Cash flows provided by (used in) investing activities:
Drilling and completion costs										20,565	255,014	173,569
Additions to water handling and treatment systems										131	(9,025)	660
Additions to gathering systems and facilities											1,754
Additions to other property and equipment											(73)
Change in other liabilities											(2,273)
Other											(6,150)
Net cash used in investing activities										20,696	239,247	174,229
Cash flows provided by (used in) financing activities:
Distributions to noncontrolling interests in Antero Midstream Partners LP										46,469	159,181	131,598
Net cash provided by financing activities										$ 46,469	$ 159,181	$ 131,598

Quarterly Financial Informati_3

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Total revenue	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 4,408,690	$ 4,139,626	$ 3,655,574
Total operating expenses	1,020,194	2,104,759	1,199,668	1,071,114	1,092,279	1,071,728	1,022,107	881,607	5,395,735	4,067,721	2,915,481
Operating income (loss)	(67,456)	(985,878)	99,996	(33,707)	(46,630)	4,804	(32,763)	146,494	(987,045)	71,905	740,093
Gain on deconsolidation of Antero Midstream Partners LP				1,406,042					1,406,042
Net income and comprehensive income including noncontrolling interests	(482,196)	(878,864)	42,168	1,025,756	18,736	(77,972)	(67,275)	80,810	(293,136)	(45,701)	785,137
Net Income (Loss) Attributable to Noncontrolling Interest				46,993	140,282	76,447	69,110	65,977	46,993	351,816	170,067
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (482,196)	$ (878,864)	$ 42,168	$ 978,763	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	$ (340,129)	$ (397,517)	$ 615,070
Earnings (loss) per common share - basic:
Earnings (loss) per common share - basic	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ (1.11)	$ (1.26)	$ 1.95
Earnings (loss) per share - diluted:
Earnings (loss) per common share - diluted	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ (1.11)	$ (1.26)	$ 1.94

Supplemental Information on O_3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 11,859,817	$ 12,705,672
Unproved properties	1,368,854	1,767,600
Total	13,228,671	14,473,272
Accumulated depletion and depreciation	(3,284,330)	(3,615,680)
Net capitalized costs	9,944,341	10,857,592
Costs Incurred in Certain Oil and Gas Activities
Proved property			$ 175,650
Unproved property	88,682	172,387	204,272
Development costs	1,104,336	1,164,800	897,287
Exploration costs	149,782	323,773	384,698
Total costs incurred	1,342,800	1,660,960	1,661,907
Results of Operations for Oil and Gas Producing Activities
Revenues	3,643,873	3,652,894	2,747,920
Operating expenses:
Production expenses	2,417,509	1,601,985	1,279,217
Exploration expenses	884	4,958	8,538
Depletion and depreciation	884,350	832,326	694,332
Impairment of unproved properties	1,300,444	549,437	159,598
Results of operations before income tax expense (benefit)	(959,314)	664,188	606,235
Income tax expense	224,511	(156,350)	(228,096)
Results of operations	$ (734,803)	$ 507,838	$ 378,139

Supplemental Information on O_4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details)	12 Months Ended
	Dec. 31, 2019MMcfeMMBblsBcf	Dec. 31, 2018MMcfeBcfMMBbls	Dec. 31, 2017MMcfeMMBblsBcf
Proved developed and undeveloped reserves:
Balance at the beginning of the period | MMcfe	18,011,000	17,261,000	15,386,000
Revisions | MMcfe	(1,648,000)	(1,042,000)	176,000
Extensions, discoveries and other additions | MMcfe	3,705,000	2,781,000	2,148,000
Production | MMcfe	(1,175,000)	(989,000)	(822,000)
Purchase of reserves | MMcfe			373,000
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MMcfe	18,893,000	18,011,000	17,261,000
Oil and Gas Reserves
Proved developed reserves | MMcfe	11,740	10,389	8,488
Proved undeveloped reserves | MMcfe	7,153	7,622	8,773
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	11,425	11,098	9,414
Revisions | Bcf	(1,735)	(1,087)	342
Extensions, discoveries and other additions | Bcf	2,626	2,125	1,644
Production | Bcf	(822)	(711)	(591)
Purchase of reserves | Bcf			289
Balance at the end of the period | Bcf	11,494	11,425	11,098
Oil and Gas Reserves
Proved developed reserves | Bcf	7,229	6,669	5,587
Proved undeveloped reserves | Bcf	4,265	4,756	5,511
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	1,052	989	957
Revisions	25	8	(22)
Extensions, discoveries and other additions	169	98	77
Production	(55)	(43)	(36)
Purchase of reserves			13
Balance at the end of the period	1,191	1,052	989
Oil and Gas Reserves
Proved developed reserves	731	600	467
Proved undeveloped reserves	460	452	522
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	46	38	38
Revisions	(11)	(1)	(6)
Extensions, discoveries and other additions	11	12	7
Production	(4)	(3)	(2)
Purchase of reserves			1
Balance at the end of the period	42	46	38
Oil and Gas Reserves
Proved developed reserves	21	20	16
Proved undeveloped reserves	21	26	22

Supplemental Information on O_5

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes In Reserves (Details) MMcfe in Thousands, Bcfe in Thousands	12 Months Ended
	Dec. 31, 2019BcfeMMcfe	Dec. 31, 2018MMcfe	Dec. 31, 2017MMcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Extensions, discoveries and other additions	3,705	2,781	2,148
Revisions	(1,648)	(1,042)	176
Time period of the development plan	5 years	5 years	5 years
Increase (decrease) in proved reserves due to performance revisions		(433)	345
Increase (decrease) in proved reserves due to development plan revisions	(1,705)	(742)	(188)
Increase in proved reserves due to additions to development plan	595	1,722	2,092
Decrease in proved reserves due to reclassifications related to five-year rule	(2,300)	(2,464)	(2,280)
Increase in proved reserves due to improved well performance	63
Increase (decrease) in proved reserves resulting from price revisions	(157)	18	132
Increase (decrease) in proved reserves due to ethane recovery	315	115	(113)
Increase (decrease) in proved reserves due to deconsolidation of equity method investment.	164
Production	1,175	989	822

Supplemental Information on O_6

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Discounted future cash flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Future cash inflows computation period	12 months
Percentage of net cash inflows that were discounted at annual rate	10.00%	10.00%	10.00%
Annual net cash inflows
Period of unweighted first day of the month average prices used to compute future cash inflows	12 months
Future cash inflows	$ 54,228	$ 64,199	$ 55,824
Future production costs	(36,524)	(30,007)	(26,375)
Future development costs	(2,772)	(3,453)	(3,312)
Future net cash flows before income tax	14,932	30,739	26,137
Future income tax expense	(1,639)	(5,505)	(4,104)
Future net cash flows	13,293	25,234	22,033
10% annual discount for estimated timing of cash flows	(7,824)	(14,756)	(13,406)
Standardized measure of discounted future net cash flows	$ 5,469	$ 10,478	$ 8,627	$ 3,287

Supplemental Information on O_7

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes in standardized measure of discounted future net cash flow (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / MMcfe	Dec. 31, 2018USD ($)$ / MMcfe	Dec. 31, 2017USD ($)$ / MMcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe	2.87	3.56	3.23
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs	$ (1,116)	$ (2,051)	$ (1,469)
Net changes in prices and production costs	(6,729)	707	3,918
Development costs incurred during the period	758	755	627
Net changes in future development costs	(92)	37	229
Extensions, discoveries and other additions	782	1,925	1,448
Acquisitions			258
Revisions of previous quantity estimates	(1,011)	(53)	734
Accretion of discount	1,259	1,018	368
Net change in income taxes	1,513	(563)	(1,159)
Changes in timing and other	(373)	76	386
Net increase (decrease)	(5,009)	1,851	5,340
Beginning of year	10,478	8,627	3,287
End of year	5,469	$ 10,478	$ 8,627
Increased production costs	3,300,000
Increased future development costs	$ 185,000