Antero Resources (AR) 10-K 17 Feb 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Feb. 12, 2021	Jun. 30, 2020
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
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 Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
ICFR Auditor Attestation Flag	true
Entity Common Stock, Shares Outstanding		301,189,530
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Central Index Key	0001433270
Amendment Flag	false
Entity Public Float			$ 584

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Accounts receivable	$ 28,457	$ 46,419
Accounts receivable, related parties		125,000
Accrued revenue	425,314	317,886
Derivative instruments	105,130	422,849
Other current assets	15,238	10,731
Total current assets	574,139	922,885
Oil and gas properties, at cost (successful efforts method):
Unproved properties	1,175,178	1,368,854
Proved properties	12,260,713	11,859,817
Gathering systems and facilities	5,802	5,802
Other property and equipment	74,361	71,895
Property and equipment, gross	13,516,054	13,306,368
Less accumulated depletion, depreciation, and amortization	(3,869,116)	(3,327,629)
Property and equipment, net	9,646,938	9,978,739
Operating lease right-of-use assets	2,613,603	2,886,500
Derivative instruments	47,293	333,174
Investment in unconsolidated affiliate	255,082	1,055,177
Other assets	13,790	21,094
Total assets	13,150,845	15,197,569
Current liabilities:
Accounts payable	26,728	14,498
Accounts payable, related parties	69,860	97,883
Accrued liabilities	343,524	400,850
Revenue distributions payable	198,117	207,988
Derivative instruments	31,242	6,721
Short-term lease liabilities	266,024	305,320
Deferred revenue, VPP	45,257
Other current liabilities	2,302	6,879
Total current liabilities	983,054	1,040,139
Long-term liabilities:
Long-term debt	3,001,593	3,758,868
Deferred income tax liability	412,252	781,987
Derivative instruments	99,172	3,519
Long-term lease liabilities	2,348,785	2,583,678
Deferred revenue, VPP	156,024
Other liabilities	59,694	58,635
Total liabilities	7,060,574	8,226,826
Commitments and contingencies (Notes 15 and 16)
Equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued
Common stock, $0.01 par value; authorized - 1,000,000 shares; 295,941 shares and 268,672 shares issued and outstanding at December 31, 2019 and 2020, respectively	2,686	2,959
Additional paid-in capital	6,195,497	6,130,365
Accumulated earnings (deficit)	(430,478)	837,419
Total stockholders' equity	5,767,705	6,970,743
Noncontrolling interests	322,566
Total equity	6,090,271	6,970,743
Total liabilities and equity	$ 13,150,845	$ 15,197,569

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Thousands	Dec. 31, 2020	Dec. 31, 2019
Consolidated Balance Sheets
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, authorized shares	50,000	50,000
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	1,000,000
Common stock, shares issued	268,672	295,941
Common stock, shares outstanding	268,672	295,941

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Loss - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue and other:
Revenue	$ 3,394,477	$ 3,940,558	$ 4,133,139
Commodity derivative fair value gains (losses)	79,918	463,972	(87,594)
Marketing derivative fair value gains	0	0	94,081
Amortization of deferred revenue, VPP	14,507
Total revenue	3,491,699	4,408,690	4,139,626
Operating expenses:
Production and ad valorem taxes	106,775	125,142	126,474
Impairment of oil and gas properties	223,770	1,300,444	549,437
Impairment of midstream assets		14,782	9,658
Depletion, depreciation, and amortization	861,870	914,867	972,465
Accretion of asset retirement obligations	3,421	3,762	2,819
General and administrative (including equity-based compensation expense of $70,414, $23,559 and $23,317 in 2018, 2019 and 2020, respectively)	134,482	178,696	240,344
Contract termination and rig stacking	14,290	14,026
Loss on sale of assets	348	951
Total operating expenses	4,445,146	5,395,735	4,067,721
Operating income (loss)	(953,447)	(987,045)	71,905
Other income (expense):
Interest expense, net	(199,872)	(228,111)	(286,743)
Equity in net income (loss) of unconsolidated affiliates	(62,660)	(143,216)	40,280
Gain on early extinguishment of debt	175,962	36,419
Gain on deconsolidation of Antero Midstream Partners LP		1,406,042
Water earnout		125,000
Loss on the sale of equity method investment shares		(108,745)
Impairment of equity method investment	(610,632)	(467,590)
Transaction expense	(7,244)
Total other income (expenses)	(704,446)	619,799	(246,463)
Loss before income taxes	(1,657,893)	(367,246)	(174,558)
Provision for income tax benefit	397,482	74,110	128,857
Net loss and comprehensive loss including noncontrolling interests	(1,260,411)	(293,136)	(45,701)
Less: net income and comprehensive income attributable to noncontrolling interests	7,486	46,993	351,816
Net loss and comprehensive loss attributable to Antero Resources Corporation	$ (1,267,897)	$ (340,129)	$ (397,517)
Loss per share-basic	$ (4.65)	$ (1.11)	$ (1.26)
Loss per share-diluted	$ (4.65)	$ (1.11)	$ (1.26)
Weighted average number of shares outstanding:
Basic (in shares)	272,433	306,400	316,036
Diluted (in shares)	272,433	306,400	316,036
Natural gas sales
Revenue and other:
Revenue	$ 1,809,952	$ 2,247,162	$ 2,287,939
Natural gas liquids sales
Revenue and other:
Revenue	1,161,683	1,219,162	1,177,777
Oil sales
Revenue and other:
Revenue	112,270	177,549	187,178
Gathering, compression, water handling and treatment
Revenue and other:
Revenue		4,478	21,344
Operating expenses:
Cost of goods and services sold	2,530,838	2,146,647	1,339,358
Marketing
Revenue and other:
Revenue	310,572	292,207	458,901
Operating expenses:
Cost of goods and services sold	469,404	549,814	686,055
Other income
Revenue and other:
Revenue	2,797	4,160
Lease operating
Operating expenses:
Cost of goods and services sold	98,865	145,720	136,153
Exploration
Operating expenses:
Cost of goods and services sold	$ 1,083	$ 884	$ 4,958

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Loss (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Consolidated Statements of Operations and Comprehensive Loss
Equity-based compensation expense	$ 23,317	$ 23,559	$ 70,414

Consolidated Statement of Equit

Consolidated Statement of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional paid-in capital	Accumulated earnings (deficit)	Noncontrolling Interests	Total
Balances at Dec. 31, 2017	$ 3,164	$ 6,570,952	$ 1,575,065	$ 726,955	$ 8,876,136
Balances (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)
Effects of changes in ownership interests in consolidated subsidiaries		8,637		(8,637)
Distributions to non-controlling interests				(267,271)	(267,271)
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
Other				(3)	(3)
Net income (loss) and comprehensive income (loss)			(397,517)	351,816	(45,701)
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)
Distributions to non-controlling interests				(85,076)	(85,076)
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
Effect of deconsolidation of Antero Midstream Partners LP		(336,172)		(784,744)	(1,120,916)
Net income (loss) and comprehensive income (loss)			(340,129)	46,993	(293,136)
Balance at Dec. 31, 2019	$ 2,959	6,130,365	837,419		6,970,743
Balance (in shares) at Dec. 31, 2019	295,941
Increase (Decrease) in Stockholders' Equity
Issuance of common units in Martica Holdings, LLC				351,000	351,000
Equity component of 2026 Convertible Notes, net		85,407			85,407
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 9	(431)			(422)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	924
Distributions to non-controlling interests				(35,920)	(35,920)
Repurchases and retirements of common stock	$ (282)	(43,161)			(43,443)
Repurchases and retirements of common stock (in shares)	(28,193)
Equity-based compensation		23,317			23,317
Net income (loss) and comprehensive income (loss)			(1,267,897)	7,486	(1,260,411)
Balance at Dec. 31, 2020	$ 2,686	$ 6,195,497	$ (430,478)	$ 322,566	$ 6,090,271
Balance (in shares) at Dec. 31, 2020	268,672

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Cash flows provided by (used in) operating activities:
Net loss including noncontrolling interests	$ (1,260,411)	$ (293,136)	$ (45,701)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	865,291	918,629	975,284
Impairments	834,402	1,782,816	559,095
Commodity derivative fair value losses (gains)	(79,918)	(463,972)	87,594
Gains on settled commodity derivatives	794,684	325,090	243,112
Premium paid on derivative contract			(13,318)
Proceeds from derivative monetizations	9,007		370,365
Gains on settled marketing derivatives			72,687
Marketing derivative fair value gains	0	0	(94,081)
Loss on sale of assets	348	951
Equity-based compensation expense	23,317	23,559	70,414
Deferred income tax benefit	(397,482)	(79,158)	(128,857)
Gain on early extinguishment of debt	(175,962)	(36,419)
Loss on the sale of equity method investment shares		108,745
Equity in (earnings) loss of unconsolidated affiliates	62,660	143,216	(40,280)
Water earnout		(125,000)
Gain on deconsolidation of Antero Midstream Partners LP		(1,406,042)
Distributions/dividends of earnings from unconsolidated affiliates	171,022	157,956	46,415
Amortization of deferred revenue	(14,507)
Amortization of debt issuance costs, debt discount, debt premium and other	12,236	10,681	4,681
Changes in current assets and liabilities:
Accounts receivable	(9,492)	31,631	(15,156)
Accrued revenue	(107,428)	156,941	(174,706)
Other current assets	(5,507)	(1,025)	(5,817)
Accounts payable including related parties	(19,282)	(27,996)	9,307
Accrued liabilities	37,954	(25,762)	63,562
Revenue distributions payable	(5,203)	(102,839)	101,210
Other current liabilities	(89)	4,592	(3,823)
Net cash provided by operating activities	735,640	1,103,458	2,081,987
Cash flows provided by (used in) investing activities:
Additions to unproved properties	(45,129)	(88,682)	(172,387)
Drilling and completion costs	(826,265)	(1,254,118)	(1,488,573)
Additions to water handling and treatment systems		(24,416)	(97,699)
Additions to gathering systems and facilities		(48,239)	(444,413)
Additions to other property and equipment	(2,963)	(6,700)	(7,514)
Settlement of water earnout	125,000
Investments in unconsolidated affiliates		(25,020)	(136,475)
Proceeds from sale of common stock of Antero Midstream Corporation		100,000
Proceeds from the Antero Midstream Partners LP Transactions		296,611
Proceeds from asset sales	701	1,983
Proceeds from VPP sale, net	215,789
Change in other assets	2,806	7,091	(3,663)
Net cash used in investing activities	(530,061)	(1,041,490)	(2,350,724)
Cash flows provided by (used in) financing activities:
Repurchases of common stock	(43,443)	(38,772)	(129,084)
Issuance of senior notes by Antero Midstream Partners LP		650,000
Issuance of convertible notes	287,500
Repayment of senior notes	(1,219,019)	(191,092)
Borrowings (repayments) on bank credit facilities, net	465,000	232,000	660,379
Payment of debt issuance costs	(8,984)	(4,547)	(2,169)
Sale of noncontrolling interest	351,000
Distributions to noncontrolling interests	(35,920)	(85,076)	(267,271)
Employee tax withholding for settlement of equity compensation awards	(422)	(2,389)	(17,020)
Other	(1,291)	(2,560)	(4,539)
Net cash provided by (used in) financing activities	(205,579)	557,564	240,296
Effect of deconsolidation of Antero Midstream Partners LP		(619,532)
Net decrease in cash and cash equivalents			(28,441)
Cash and cash equivalents, beginning of period			28,441
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	192,302	224,331	275,769
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$ (94,619)	$ (15,897)	$ (47,717)

Organization

Organization	12 Months Ended
	Dec. 31, 2020
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 development, production, exploration 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, 2020
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, 2019 and 2020, and the results of its operations and its cash flows for the years ended December 31, 2018, 2019 and 2020. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is equal to its comprehensive income or loss. (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—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements), the Company’s ownership of Antero Midstream Partners common units represented approximately a limited partner interest in Antero Midstream Partners, and Antero Resources consolidated Antero Midstream Partners’ financial position and results of operations into its consolidated financial statements. The Transactions (defined in Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements) resulted in the exchange of the limited partner interest Antero Resources owned in Antero Midstream Partners for common stock of Antero Midstream Corporation representing an approximate interest as of March 13, 2019. As a result, Antero Resources’ controlling interest in Antero Midstream Partners was converted to 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. As of December 31, 2019 and 2020, the Company had a interest, respectively, in Antero Midstream Corporation. See Note 6—Equity Method Investments and Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on equity method investments and the Transactions, respectively. For the year ended December 31, 2020, the Company determined that Martica Holdings LLC (“Martica”) is a VIE for which Antero is the primary beneficiary. Therefore, Martica’s accounts are consolidated in the Company’s consolidated financial statements. Antero is the primary beneficiary of Martica based on its power to direct the activities that most significantly impact Martica’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Martica that could be significant to Martica. In reaching such determination that Antero is the primary beneficiary of Martica, the Company considered the following: ● Martica was formed to hold certain overriding royalty interests across the Company’s existing asset base; ● substantially all of Martica’s revenues are derived from production from the Company’s natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio; ● Antero owns the Class B Units in Martica, which entitle Antero to receive distributions in respect of the Incremental Override (as defined in Note 4—Transactions); and ● Antero provides accounting, administrative and other services to Martica under a Management Services Agreement. 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 for the years ended December 31, 2018 and 2019 represents the interests in Antero Midstream Partners that were owned by the public prior to the Transactions, and the incentive distribution rights in Antero Midstream Partners. The noncontrolling interest in the Company’s consolidated financial statements for the year ended December 31, 2020 represents the interest in Martica owned by third parties. See Note 4—Transactions to the consolidated financial statements for more information on the sale of this noncontrolling interest. Martica is a discrete entity and the assets and credits of Martica are not available to satisfy the debts and obligations of the Company or its other subsidiaries. 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 method 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 Investment in unconsolidated affiliate on the Company’s consolidated balance sheets. Income (loss) from investees that are accounted for under the equity method is included in Equity in earnings (loss) of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. When Antero records its proportionate share of net income or net loss, it is recorded in equity in earnings (loss) of unconsolidated affiliates in the statements of operations 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 Company’s 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 method 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, liabilities and 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, asset retirement obligations 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 storage capacity transportation 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, 2020, the book overdraft included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2019, 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. During the year ended December 31, 2019, the Company recorded an impairment expense of million for design and initial costs related to pads that are no longer planned to be placed into service. The Company incurred such expenses during the years ended December 31, 2018 and 2020. 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, future plans to develop acreage, 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 expense 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, estimated future commodity prices, future production estimates, and anticipated capital expenditures, using a commensurate discount rate. The carrying amount of the Company’s proved properties in the Utica Shale exceeded the estimated undiscounted future cash flows based on future commodity prices as of September 30, 2019. The Company estimated the fair value of the Utica Shale assets based on sales of other properties, estimates of proved reserves, estimated future commodity prices and future production estimates. As a result, the Company recorded an impairment expense of million related to proved properties in the Utica Shale during the third quarter of 2019. The Company did not incur any impairment expenses related to proved properties in the Utica Shale for the years ended December 31, 2018 and 2020. The Company did not record any impairment expenses associated with its proved properties in the Marcellus Shale during the years ended December 31, 2018, 2019 and 2020. As of December 31, 2020, 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. 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) 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 $10 million and $15 million for the years ended December 31, 2018 and 2019, respectively, and were associated with midstream assets. There were no such impairments for the year ended December 31, 2020. (h) Other Property and Equipment Other property and equipment assets are depreciated using the straight-line method over their estimated useful lives, which range from two . Depreciation expense for other property and equipment was 31, 2018, 2019 and 2020, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment. (i) Debt Issuance Costs Debt issuance 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 facility, 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 and 2026 Convertible Notes (as defined below in Note 8—Long-Term Debt). These costs are amortized over the term of the related debt instrument. The Company charges expense for unamortized debt issuance costs if the credit facility is retired prior to its maturity date. As of December 31, 2020, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. As of December 31, 2019, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. The amounts amortized and the write-off of previously deferred debt issuance costs were (j) 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. (k) 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. (l) 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, 2019 and 2020, 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. (m) Natural Gas, NGLs, and Oil Revenues The Company’s revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from the Company’s natural gas. Sales of natural gas, NGLs, and oil are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the sale. Under the Company’s natural gas sales contracts, it delivers natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from the wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or other third parties gather, compress, process and transport the Company’s natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. The Company’s sales contracts provide that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product at the delivery point and recognizes revenue based on the contract price. The costs incurred to gather, compress, process and transport natural gas are recorded as Gathering, compression, processing and transportation expense. NGLs, which are extracted from natural gas through processing, are either sold by the Company directly or by the processor under processing contracts. For NGLs sold by the Company directly, the sales contracts primarily provide that the Company delivers the product to the purchaser at an agreed upon delivery point and that it receives a specific index price adjusted for pricing differentials. The Company transfers control of the product to the purchaser at the delivery point and recognizes revenue based on the contract price. The costs incurred to process and transport NGLs are recorded as Gathering, compression, processing, and transportation expense. For NGLs sold by the processor, the Company’s processing contracts provide that the Company transfers control to the processor at the tailgate of the processing plant and it recognizes revenue based on the price received from the processor. Under the Company’s oil sales contracts, Antero Resources’ generally sells oil to purchasers and collects a contractually agreed upon index price, net of pricing differentials. The Company recognizes revenue based on the contract price when it transfers control of the product to a purchaser. When applicable, the costs incurred to transport oil to a purchaser are recorded as Gathering, compression, processing and transportation expense. (n) 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. The Company retains control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that it is the principal in these arrangements and therefore, the Company recognizes 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 the Company’s produced natural gas and NGLs. The Company satisfies performance obligations to the purchaser by transferring control of the product at the delivery point and recognizes revenue based on the contract price received from the purchaser. Fees generated from the sale of excess firm transportation marketed to third parties are included in Marketing 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. (o) Deferred Revenue Under the terms of the VPP (as defined below in Note 4—Transactions), the Company is obligated to deliver certain natural gas volumes from specified wells to an overriding royalty interest owner over the term of the arrangement. The Company has accounted for the VPP as a conveyance under Accounting Standard Codifications (“ASC”) Topic 932, Extractive Industries—Oil and Gas (“ASC 932”), which requires the net proceeds to be recorded as deferred revenue due to the Company’s future performance obligations. Revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP in Amortization of deferred revenue on the Company’s consolidated statements of operations. See Note 4—Transactions to the consolidated financial statements for further discussion of the VPP. (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 the Company’s 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 financial statements for further discussion on the Transactions and the Company’s reportable segments, respectively. The portion of such fees shown in 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 satisfied its performance obligations and recognized revenue when low pressure volumes were delivered to a compressor station, high pressure volumes were delivered to a processing plant or transmission pipeline, and compression volumes were delivered to a high pressure line. Revenue was 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 satisfied its performance obligations and recognized revenue when the fresh water volumes were delivered to the hydration unit of a specified well pad and the wastewater volumes were delivered to its wastewater treatment facility. For services contracted through third-party providers, Antero Midstream Partners’ performance obligation was satisfied when the services performed by the third-party providers were completed. Revenue was 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, 2018, 2019 and 2020 are as follows: ​ ​ ​ ​ ​ ​ Year Ended December 31, 2018 ​ ​ ​ ​ Mercuria Energy America, Inc. ​ 14 % ​ Tenaska Marketing Ventures ​ 13 % ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ Sabine Pass Liquefaction LLC ​ 16 % ​ WGL Midstream ​ 15 % ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ Sabine Pass Liquefaction LLC ​ 11 % ​ WGL Midstream ​ 11 % ​ ​ 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) as of December 31, 2020 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 (“NOL”) 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 The Financial Accounting Standards Board (“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) midstream services through the Company’s 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, Antero no longer consolidated the results of Antero Midstream Partners in Antero’s results; however, the Company’s segment disclosures include the Company’s equity method investment in Antero Midstream Corporation due to its significance to the Company’s operations. See Note 3—Deconsolidation of Antero Midstream Partners LP and Note 18—Segment Information to the consolidated financial statements for further discussion on the Transactions and the Company’s reportable segments, respectively. 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

Deconsolidation of Antero Midst

Deconsolidation of Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2020
Deconsolidation of Antero Midstream Partners LP
Deconsolidation of Antero Midstream Partners LP	(3) Deconsolidation of Antero Midstream Partners LP 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 The Company recorded a gain on deconsolidation of $1.4 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 6—Equity Method Investments to the consolidated financial statements 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 ​ 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 ​ ​

Transactions

Transactions	12 Months Ended
	Dec. 31, 2020
Transactions
Transactions	(4) Transactions (a) Conveyance of Overriding Royalty Interest On June 15, 2020, the Company announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across the Company’s existing asset base (the “ORRIs”). In connection with the transaction, the Company contributed the ORRIs to Martica and Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds attributable to the ORRIs are achieved in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street at the initial closing was distributed to the Company. The Company met the applicable production threshold during the third quarter of 2020 and received a $51 million cash distribution during the year ended December 31, 2020. The ORRIs include an overriding royalty interest of 1.25% of the Company’s working interest in all of its operated proved developed in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of the Company’s working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”). Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which the Company turns to sales 2.2 million lateral feet (net to the Company’s interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which the Company turns to sales 3.82 million lateral feet (net to the Company’s interest) of horizontal wells are subject to the Development Override. The ORRIs also include an additional overriding royalty interest of 2.00% of the Company’s working interest in the properties underlying the Initial PDP Override (the “Incremental Override”). The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to the Company (at the Company’s election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023. Any portion of the Override that may not be re-conveyed to the Company based on the Company failing to achieve such production volumes through March 31, 2023 will remain with Martica. Prior to Sixth Street achieving an internal rate of return of 13% and 1.5 x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and the Company will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override. Following Sixth Street achieving the Hurdle, the Company will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved. The conveyance of the ORRIs from the Company to Martica was accounted for as a transaction between entities under common control. As a result, the contributed ORRIs have been recorded by Martica at their historical cost. (b) Volumetric Production Payment Transaction On August 10, 2020, the Company completed a volumetric production payment transaction and received net proceeds of approximately $216 million (the "VPP"). In connection with the VPP, the Company entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP. The Company has accounted for the VPP as a conveyance under ASC 932, and the net proceeds were recorded as deferred revenue in the consolidated balance sheet. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, Antero and its affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses as appropriate. Contemporaneously with the VPP, the Company executed a call option related to the production volumes associated with its retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for the Company’s retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument recorded at fair value. See Note 12—Derivative Instruments to the consolidated financial statements for more information on the Company’s derivative instruments. (c) Subsequent Event Drilling Partnership On February 17, 2021, Antero Resources announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners. Under the terms of the arrangement, QL will fund of total development capital spending on an annual basis from 2022 through 2024. All of the wells spud during each calendar year period will be a separate annual tranche. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for Antero Resources’ account. For each tranche other than 2021, Antero Resources will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during the year and, subject to the mutual agreement of the parties that the estimated IRR for each tranche exceeds a specified return, QL will be obligated to participate in such tranche. For each annual tranche in which QL participates, QL will receive a proportionate working interest percentage in each well spud in such tranche. If Antero Resources presents a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, Antero Resources will not be obligated to offer QL the opportunity to participate in subsequent tranches. No earlier than December 31 following the expiration of each tranche year, Antero Resources will calculate the tranche IRR for such tranche year and, if the tranche IRR exceeds certain specified returns, Antero Resources will receive a carry in the form of a one-time payment from QL for such annual tranche.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2020
Revenue
Revenue	(5) Revenue (a) Disaggregation of Revenue Revenue is disaggregated by type in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. See Note 18—Segment Information to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ (in thousands) 2018 2019 2020 Reportable Segment ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,287,939 ​ ​ 2,247,162 ​ ​ 1,809,952 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 172,653 ​ ​ 124,563 ​ ​ 113,811 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 1,005,124 ​ ​ 1,094,599 ​ ​ 1,047,872 ​ Exploration and production ​ Oil sales ​ ​ 187,178 ​ ​ 177,549 ​ ​ 112,270 ​ Exploration and production ​ Gathering and compression (1) ​ ​ 17,817 ​ ​ 3,972 ​ ​ — ​ Equity method investment in Antero Midstream Corporation ​ Water handling and treatment (1) ​ ​ 3,527 ​ ​ 506 ​ ​ — ​ Equity method investment in Antero Midstream Corporation ​ Marketing ​ ​ 458,901 ​ ​ 292,207 ​ ​ 310,572 ​ Marketing ​ Total revenue from contracts with customers ​ ​ 4,133,139 ​ ​ 3,940,558 ​ ​ 3,394,477 ​ ​ ​ Income from derivatives, deferred revenue and other sources ​ ​ 6,487 ​ ​ 468,132 ​ ​ 97,222 ​ ​ ​ Total revenue ​ $ 4,139,626 ​ ​ 4,408,690 ​ ​ 3,491,699 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions. ​ (b) Transaction Price Allocated to Remaining Performance Obligations For the Company’s product sales that have a contract term greater than one year, the Company 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 the Company’s 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 the Company’s product sales that have a contract term of one year or less, the Company 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 the Company’s sales contracts, the Company invoices customers after its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s contracts do not give rise to contract assets or liabilities. As of December 31, 2019 and 2020, the Company’s receivables from contracts with customers were

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2020
Equity Method Investments.
Equity Method Investments	(6) Equity Method Investments (a) Summary of Equity Method Investments As of December 31, 2020, Antero owned approximately 29.2% of Antero Midstream Corporation’s common stock, which is reflected in Antero’s consolidated financial statements using the equity method of accounting. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions. Prior to March 13, 2019, Antero’s 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 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 (loss) of Antero Midstream Corporation. The following table is a reconciliation of investments in unconsolidated affiliates for the years ended December 31, 2019 and 2020 in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antero ​ ​ ​ ​ ​ ​ ​ MarkWest ​ Midstream ​ ​ ​ ​ Stonewall (1) Joint Venture Corporation (2) Total ​ Balances as of 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 ​ Balances as of December 31, 2019 ​ ​ — ​ ​ — ​ ​ 1,055,177 ​ ​ 1,055,177 ​ Equity in loss of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (62,660) ​ ​ (62,660) ​ Distributions/dividends from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (171,022) ​ ​ (171,022) ​ Impairment (5) ​ ​ — ​ ​ — ​ ​ (610,632) ​ ​ (610,632) ​ Elimination of intercompany profit ​ ​ — ​ ​ — ​ ​ 44,219 ​ ​ 44,219 ​ Balances as of December 31, 2020 (7) ​ $ — ​ ​ — ​ ​ 255,082 ​ ​ 255,082 ​ (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 method 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) On December 16, 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 of the Company’s investment in Antero Midstream Corporation to reduce the carrying value of such investment to fair value, which was based on the quoted market share price of Antero Midstream Corporation as of December 31, 2019 and March 31, 2020, respectively (Level 1). (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. (7) The Company’s investment in Antero Midstream Corporation as of December 31, 2020, based on the quoted market share price of Antero Midstream Corporation on such date, was $1.1 billion. (b) Summarized Financial Information of Antero Midstream Corporation ​ The following tables present summarized financial information of Antero Midstream Corporation. Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ (in thousands) 2019 2020 ​ Current assets ​ $ 108,558 ​ ​ 93,931 ​ Noncurrent assets ​ ​ 6,174,320 ​ ​ 5,516,981 ​ Total assets ​ $ 6,282,878 ​ ​ 5,610,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 242,084 ​ ​ 94,005 ​ Noncurrent liabilities ​ ​ 2,897,380 ​ ​ 3,098,621 ​ Stockholders' equity ​ ​ 3,143,414 ​ ​ 2,418,286 ​ Total liabilities and stockholders' equity ​ $ 6,282,878 ​ ​ 5,610,912 ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the period ​ ​ ​ ​ ​ March 13, 2019 ​ ​ ​ ​ ​ through ​ Year Ended ​ (in thousands) December 31, 2019 December 31, 2020 ​ Revenues ​ $ 792,588 ​ ​ 900,719 ​ Operating expenses ​ ​ 1,177,610 ​ ​ 1,018,357 ​ Loss from operations ​ $ (385,022) ​ ​ (117,638) ​ Loss attributable to the equity method investment ​ $ (341,565) ​ ​ (122,527) ​ ​

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2020
Accrued Liabilities
Accrued Liabilities	(7) Accrued Liabilities Accrued liabilities as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Capital expenditures ​ $ 105,706 ​ 32,372 ​ Gathering, compression, processing, and transportation expenses ​ ​ 134,153 ​ ​ 152,724 ​ Marketing expenses ​ ​ 52,612 ​ ​ 68,193 ​ Interest expense, net ​ 30,834 ​ 25,645 ​ Accrued taxes ​ ​ 39,332 ​ ​ 40,796 ​ Other ​ 38,213 ​ 23,794 ​ Total accrued liabilities ​ $ 400,850 ​ 343,524 ​ ​

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2020
Long-Term Debt.
Long-Term Debt	(8) Long-Term Debt Long-term debt as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Credit Facility (a) ​ $ 552,000 ​ ​ 1,017,000 ​ 5.375% senior notes due 2021 (b) ​ ​ 952,500 ​ ​ — ​ 5.125% senior notes due 2022 (c) ​ ​ 923,041 ​ ​ 660,516 ​ 5.625% senior notes due 2023 (d) ​ ​ 750,000 ​ ​ 574,182 ​ 5.00% senior notes due 2025 (e) ​ ​ 600,000 ​ ​ 590,000 ​ 4.25% convertible senior notes due 2026 (f) ​ ​ — ​ ​ 287,500 ​ Total principal ​ ​ 3,777,541 ​ ​ 3,129,198 ​ Unamortized premium (discount), net ​ ​ 791 ​ ​ (111,886) ​ Unamortized debt issuance costs ​ ​ (19,464) ​ ​ (15,719) ​ Long-term debt ​ $ 3,758,868 ​ ​ 3,001,593 ​ ​ (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 semi-annual redeterminations. The borrowing base and lender commitments were each reaffirmed in the semi-annual redetermination in October 2020. The next redetermination of the borrowing base is scheduled to occur in April 2021. The Credit Facility is scheduled to mature on October 26, 2022. As of December 31, 2020, the borrowing base under the Credit Facility was $2.85 billion and lender commitments were $2.64 billion. Antero Resources was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2019 and 2020. As of December 31, 2020, Antero Resources had an outstanding balance under the Credit Facility of $1.0 billion with a weighted average interest rate of 3.26%, and outstanding letters of credit of $730 million. 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. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) 0.300% to 0.375% (subject to certain exceptions) of the unused portion based on utilization. (b) 5.375% Senior Notes Due 2021 On November 5, 2013, Antero Resources issued $1.0 billion of 5.375% senior notes due November 1, 2021 (the “2021 Notes”) at par . The 2021 Notes were unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 Notes ranked pari passu to Antero Resources’ other outstanding senior notes. The 2021 Notes were 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 was payable on May 1 and November 1 of each year. The Company repurchased or otherwise redeemed all of the 2021 Notes from time to time during the years ended December 31, 2019 and 2020. See —Debt Repurchase Program below for further details on 2021 Notes repurchases. (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 a redemption price of 100.00 %. 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) 4.25% Convertible Senior Notes Due 2026 On August 21, 2020, Antero Resources issued $250 million in aggregate principal amount of 4.25% senior unsecured convertible notes (the “2026 Convertible Notes”). On September 2, 2020, Antero Resources issued an additional million aggregate principal amount of 2026 Convertible Notes pursuant to the partial exercise of the initial purchasers’ option to purchase additional 2026 Convertible Notes. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources. The 2026 Convertible Notes bear interest at a fixed rate of per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Proceeds from the issuance of the 2026 Convertible Notes totaled The initial conversion rate is 230.2026 shares of Antero Resources’ common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events. As of December 31, 2020, the if-converted value of the 2026 Convertible Notes was $361 million, which exceeded the principal amount of the 2026 Convertible Notes by $73 million. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, note holders will have the right to convert their 2026 Convertible Notes only upon the occurrence of the following events: ● during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending on September 30, 2020, if the Last Reported Sale Price per share of Antero Resources’ common stock exceeds 130% of the Conversion Price for each of at least 20 Trading Days (whether or not consecutive) during the 30 consecutive Trading Days ending on, and including, the last Trading Day of the immediately preceding calendar quarter; ● during the five consecutive Business Days immediately after any 10 consecutive trading day period (such 10 consecutive Trading Day period, the “Measurement Period”) if the trading Price per $1,000 principal amount of 2026 Convertible Notes, as determined following a request by a noteholder in accordance with the procedures set forth below, for each trading day of the Measurement Period was less than 98% of the product of the last reported sale price per share of common stock on such trading day and the conversion rate on such trading day; ● if Antero Resources calls any or all of the 2026 Convertible Notes for redemption, at any time prior to the close of business on the scheduled trading day immediately preceding the redemption date; or ● upon the occurrence of certain specified corporate events as set forth in the indenture governing the 2026 Convertible Notes. From and after May 1, 2026, noteholders may convert their 2026 Convertible Notes at any time at their election until the close of business on the second scheduled trading day immediately before the maturity date. Upon conversion, Antero Resources may satisfy its conversion obligation by paying and/or delivering, as the case may be, cash, shares of Antero Resources’ common stock or a combination of cash and shares of Antero Resources’ common stock, at Antero Resources’ election, in the manner and subject to the terms and conditions provided in the indenture governing the 2026 Convertible Notes. Antero Resources’ current intent is is to settle the principle amount of the 2026 Convertible Notes in cash upon conversion except as it relates to the Equitization Transactions discussed in Note 8(h) below. At no point since issuance of the 2026 Convertible Notes has the conditions allowing holders of the 2026 Convertible Notes to exercise their conversion right been met. The conversion rate is subject to adjustment under certain circumstances in accordance with the terms of the indenture governing the 2026 Convertible Notes. In addition, following certain corporate events, as described in the indenture governing the 2026 Convertible Notes, that occur prior to the maturity date, Antero Resources will increase the conversion rate for a holder who elects to convert its 2026 Convertible Notes in connection with such a corporate event. If certain corporate events that constitute a Fundamental Change occur, then noteholders may require Antero Resources to repurchase their 2026 Convertible Notes at a cash repurchase price equal to the principal amount of the 2026 Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. The definition of Fundamental Change includes certain business combination transactions involving Antero Resources and certain de-listing events with respect to Antero Resources’ common stock. Upon issuance, the Company separately accounted for the liability and equity components of the 2026 Convertible Notes. The liability component was recorded at the estimated fair value of a similar debt instrument without the conversion feature. The difference between the principal amount of the 2026 Convertible Notes and the estimated fair value of the liability component was recorded as a debt discount and will be amortized to interest expense, together with debt issuance costs, over the term of the 2026 Convertible Notes using the effective interest method, with an effective interest rate of 15.1% per annum. As of the issuance date, the fair value of the 2026 Convertible Notes was estimated at $172 million, resulting in a debt discount at inception of $116 million. The equity component, representing the value of the conversion option, was computed by deducting the fair value of the liability component from the initial proceeds of the 2026 Convertible Notes issuance. This equity component was recorded, net of deferred taxes and issuance costs, in additional paid-in capital within the consolidated balance sheet and statement of stockholders’ equity and will not be remeasured as long as it continues to meet the conditions for equity classification. Transaction costs related to the 2026 Convertible Notes issuance were allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were recorded within debt issuance costs on the consolidated balance sheet and are amortized over the term of the 2026 Convertible Notes using the effective interest method. Issuance costs attributable to the equity component were recorded as a charge to additional paid-in capital within the consolidated balance sheet and statement of stockholders’ equity. The 2026 Convertible Notes consist of the following as of December 31, 2020 (in thousands): ​ ​ ​ ​ ​ Liability component: ​ ​ ​ ​ Principal ​ $ 287,500 ​ Less: unamortized note discount ​ ​ (112,265) ​ Less: unamortized debt issuance costs ​ ​ (5,852) ​ Net carrying value ​ $ 169,383 ​ Equity component (1) ​ $ 115,601 ​ (1) Recorded in additional paid-in capital, net of $3 million of issuance costs and $28 million of deferred taxes . (g) Debt Repurchase Program During the year ended December 31, 2019, Antero Resources repurchased $225 million principal amount of debt at a 17% weighted average discount, including a portion of its 2021 Notes and 2022 Notes. The Company recognized a gain of approximately million on the early extinguishment of the debt repurchased. During the year ended December 31, 2020, Antero Resources repurchased $1.4 billion aggregate principal amount of debt at a weighted average discount of 13% , which purchases included a portion of the 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. The Company recognized a gain of approximately million for the year ended December 31, 2020 on the early extinguishment of the debt repurchased. Repurchases of the principal amount of debt during year ended December 31, 2020 include repurchases of $367 million aggregate principal amount of the 2021 Notes, 2022 Notes and 2023 Notes through previously disclosed tender offers at a weighted average discount of 10%. ​ (h) Subsequent Events Issuance of 8.375% Senior Notes Due 2026 On January 4, 2021, Antero Resources issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par . The 2026 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2026 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 2026 Notes is payable on January 15 and July 15 of each year. Antero Resources may redeem all or part of the 2026 Notes at any time on or after January 15, 2024 at redemption prices ranging from on or after January 15, 2026. In addition, on or before January 15, 2024, Antero Resources may redeem up to of the principal amount of the 2026 Notes, plus accrued and unpaid interest. At any time prior to January 15, 2024, Antero Resources may also redeem the 2026 Notes, in whole or in part, at a price equal to of the principal amount of the 2026 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 2026 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to Partial Equitization of 2026 Convertible Notes On January 12, 2021, the Company completed a registered direct offering (the “Share Offering”) of an aggregate of 31.4 million shares of its common stock at a price of $6.35 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the Share Offering and approximately $63 million of borrowings under the Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “Convertible Note Repurchase,” and, collectively with the Share Offering, the “Equitization Transactions”). The 2026 Convertible Notes have an initial conversion rate of 230.2026 shares of the Company’s common stock per $1,000 principal amount, and the Equitization Transactions had the effect of increasing this conversion rate to 275.3525 shares of common stock per $1,000 principal amount. Redemption of 2022 Notes On January 16, 2021, the Company completed a partial redemption of $350 million of the 2022 Notes at par, plus accrued and unpaid interest. On February 10, 2021, the Company redeemed Issuance of 7.625% Senior Notes Due 2029 On January 26, 2021, Antero Resources issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par . The 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2029 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2029 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 2029 Notes is payable on February 1 and August 1 of each year. Antero Resources may redeem all or part of the 2029 Notes at any time on or after February 1, 2024 at redemption prices ranging from on or after February 1, 2027. In addition, on or before February 1, 2024, Antero Resources may redeem up to of the principal amount of the 2029 Notes, plus accrued and unpaid interest. At any time prior to February 1, 2024, Antero Resources may also redeem the 2029 Notes, in whole or in part, at a price equal to of the principal amount of the 2029 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 2029 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligations
Asset Retirement Obligations	(9) Asset Retirement Obligations The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2019 ​ 2020 ​ Beginning balances $ 58,979 ​ 54,845 ​ Obligations incurred ​ 2,312 ​ ​ 1,814 ​ Accretion expense ​ ​ 3,762 ​ ​ 3,421 ​ Settlement of obligations ​ ​ (153) ​ ​ (229) ​ Revisions to prior estimates ​ ​ (2,537) ​ ​ (5,399) ​ Effect of deconsolidation of Antero Midstream Partners LP (1) ​ ​ (7,518) ​ ​ — ​ Ending balances ​ $ 54,845 ​ ​ 54,452 ​ (1) Effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its results. ​ Revisions to prior estimates in 2020 are primarily due to an increase in estimated well lives. Revisions to prior estimates in 2019 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, 2020
Equity-Based Compensation
Equity-Based Compensation	(10) Equity-Based Compensation and Retention Awards On June 17, 2020, Antero Resources’ stockholders approved the Antero Resources Corporation 2020 Long-Term Incentive Plan (the “2020 Plan”), which replaced the Antero Resources Corporation Long-Term Incentive Plan (the “2013 Plan”), and the 2020 Plan became effective as of such date. The 2020 Plan provides for grants of stock options (including incentive stock options), stock appreciation rights, restricted stock awards, RSU awards, vested stock awards, dividend equivalent awards, and other stock-based and cash awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero Resources’ Board of Directors. Employees, officers, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the 2020 Plan. No further awards will be granted under the 2013 Plan on or after June 17, 2020. The 2020 Plan provides for the reservation of 10,050,000 shares of the Company’s common stock, plus the number of certain shares that become available again for delivery from the 2013 Plan in accordance with the share recycling provisions described below. The share recycling provisions allow for all or any portion of an award (including an award granted under the 2013 Plan that was outstanding as of June 17, 2020) that expires or is cancelled, forfeited, exchanged, settled for cash, or otherwise terminated without actual delivery of the shares to be considered not delivered and thus available for new awards under the 2020 Plan. Further, any shares withheld or surrendered in payment of any taxes relating to awards that were outstanding under either the 2013 Plan as of June 17, 2020 or are granted under the 2020 Plan (other than stock options and stock appreciation rights), will again be available for new awards under the 2020 Plan. A total of 6,921,638 shares were available for future grant under the 2020 Plan as of December 31, 2020. Antero Midstream Partners’ 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 includes Antero Resources). As part of the Transactions, each outstanding phantom unit award under the AMP Plan, was assumed by Antero Midstream Corporation and converted into 1.8926 RSUs under the Antero Midstream Corporation Long Term Incentive Plan (the “AMC Plan”). Each RSU award under the AMC Plan represents a right to receive one share of 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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 ​ RSU awards ​ $ 41,505 ​ ​ 10,343 ​ ​ 12,510 ​ Stock options ​ ​ 1,799 ​ ​ 355 ​ ​ — ​ PSU awards ​ ​ 9,659 ​ ​ 8,069 ​ ​ 7,219 ​ Antero Midstream Partners phantom unit awards (1) ​ ​ 15,351 ​ ​ 3,425 ​ ​ 2,519 ​ Equity awards issued to directors ​ ​ 2,100 ​ ​ 1,367 ​ ​ 1,069 ​ Total expense ​ $ 70,414 ​ ​ 23,559 ​ ​ 23,317 ​ (1) Antero Resources recognized compensation expense for equity awards granted under the 2013 Plan, 2020 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—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions. ​ (a) Restricted Stock Unit Awards RSU awards vest subject to the satisfaction of service requirements. Expense related to each RSU 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 RSU award activity for the year ended December 31, 2020 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Average ​ Aggregate ​ ​ ​ Number of ​ Grant Date ​ Intrinsic Value ​ ​ Shares Fair Value (in thousands) ​ Total awarded and unvested—December 31, 2019 ​ 2,370,575 ​ $ 12.81 ​ $ 6,756 ​ Granted ​ 7,001,802 ​ ​ 2.57 ​ ​ ​ ​ Vested ​ (809,008) ​ ​ 15.62 ​ ​ ​ ​ Forfeited ​ (130,972) ​ ​ 11.91 ​ ​ ​ ​ Total awarded and unvested—December 31, 2020 ​ 8,432,397 ​ $ 4.06 ​ $ 45,957 ​ ​ Intrinsic values are based on the closing price of Antero Resources’ common stock on the referenced dates. As of December 31, 2020, there was $23 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 2.2 years. (b) Stock Options Stock options granted under the 2013 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, 2020 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ Average ​ ​ ​ ​ ​ ​ ​ Average ​ Remaining ​ Intrinsic ​ ​ ​ Stock ​ Exercise ​ Contractual ​ Value ​ ​ Options Price Life (in thousands) ​ Outstanding—December 31, 2019 ​ 467,633 ​ $ 50.64 ​ 5.1 ​ $ — ​ Granted ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Forfeited ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Expired ​ (35,172) ​ ​ 50.56 ​ ​ ​ ​ ​ ​ Outstanding—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Vested—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Exercisable —December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ ​ Intrinsic values are based on the exercise price of the options and the closing price of Antero Resources’ common 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. (c) Performance Share Unit Awards Performance Share Unit Awards Based on Stock Price Targets In 2016, the Company granted 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. In 2020, the Company granted PSU awards to certain of its executive officers that vest based on Antero Resources’ absolute TSR determined as of the last day of each of three one-year performance periods ending on April 15, 2021, April 15, 2022, and April 15, 2023, and one cumulative three-year performance period ending on April 15, 2023, in each case, subject to the executive officer’s continued employment through April 15, 2023. The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period ranges from zero to 150% of the target number of PSUs granted. Expense related to these PSUs is recognized on a graded-vested basis over approximately three years . Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Additionally, in 2020, the Company granted PSUs to certain of its executive officers that vest based on Antero Resources’ TSR relative to the TSR of certain peer companies determined as of the last day of each of three one-year performance periods ending on April 15, 2021, April 15, 2022, and April 15, 2023, and one cumulative three-year performance period ending on April 15, 2023, in each case, subject to the executive officer’s continued employment through April 15, 2023. The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period ranges from zero to 150% of the target number of PSUs granted. Expense related to these PSUs is recognized on a graded-vested basis over approximately 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 (“2018 TSR PSUs”). The number of awards actually earned with respect to the 2018 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 2018 TSR PSUs ranges from zero to 200 % of the target number of 2018 TSR PSUs originally granted. Expense related to the 2018 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 year 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, 2020 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ Number of ​ Average Grant ​ ​ Units Date Fair Value ​ Total awarded and unvested—December 31, 2019 ​ 2,537,283 ​ $ 16.74 ​ Granted ​ 469,000 ​ ​ 2.97 ​ Forfeited ​ (29,316) ​ ​ 12.21 ​ Cancelled (unearned) ​ (429,169) ​ ​ 26.21 ​ Total awarded and unvested—December 31, 2020 ​ 2,547,798 ​ $ 12.66 ​ ​ 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, 2019 and 2020, and the assumptions used to determine the fair values: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2018 ​ 2019 ​ 2020 ​ ​ Dividend yield ​ ​ — % ​ ​ — % ​ — % ​ Volatility ​ ​ 41 % ​ ​ 36 % ​ 80 % ​ Risk-free interest rate ​ ​ 2.49 % ​ ​ 2.35 % ​ 0.17 % ​ Weighted average fair value of awards granted—Absolute TSR ​ $ 24.85 ​ ​ ​ 9.26 ​ ​ 2.63 ​ ​ Weighted average fair value of awards granted—Relative TSR ​ $ — ​ ​ ​ — ​ ​ 3.30 ​ ​ ​ As of December 31, 2020, there was $8 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 1.2 years. (d) Cash Retention Awards In January 2020, the Company granted cash awards of approximately $3.3 million to certain executives under the 2013 Plan, and compensation expense for these awards is recognized ratably over the vesting period for each of three tranches through January 20, 2023. In July 2020, the Company granted additional cash awards on the aggregate of $2.6 million to certain non-executive employees under the 2020 Plan that vest ratably over four years . As of December 31, 2020, the Company has accrued approximately $3.2 million in Other liabilities in the consolidated balance sheet related to cash awards. (e) 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 Directors 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 Antero Midstream Corporation RSU awards for the year ended December 31, 2020 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Aggregate ​ ​ ​ Number of ​ Grant Date ​ Intrinsic Value ​ ​ Units Fair Value (in thousands) ​ Total awarded and unvested—December 31, 2019 ​ 657,757 ​ $ 14.71 ​ $ 4,992 ​ Granted ​ — ​ ​ — ​ ​ ​ ​ Vested ​ (338,412) ​ ​ 14.44 ​ ​ ​ ​ Forfeited ​ (22,955) ​ ​ 14.08 ​ ​ ​ ​ Total awarded and unvested—December 31, 2020 ​ 296,390 ​ $ 15.06 ​ $ 2,285 ​ ​ 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, 2020, there was $2.2 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 1.0 years, and the Company’s proportionate share will be allocated to it as it is recognized.

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2020
Fair Value
Fair Value	(11) Fair Value The carrying values of accounts receivable and accounts payable as of December 31, 2019 and 2020 approximated market values because of their short- term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2019 and 2020 approximated fair value because the variable interest rates are reflective of current market conditions. The fair value and carrying value of the senior notes and 2026 Convertible Notes as of December 31, 2019 and 2020 are as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ December 31, 2020 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 5.375% senior notes due 2021 ​ $ 906,304 ​ ​ 948,904 ​ ​ — ​ ​ — ​ 5.125% senior notes due 2022 ​ ​ 823,906 ​ ​ 918,640 ​ ​ 658,468 ​ ​ 658,400 ​ 5.625% senior notes due 2023 ​ ​ 602,550 ​ ​ 744,938 ​ ​ 562,698 ​ ​ 571,370 ​ 5.00% senior notes due 2025 ​ ​ 450,600 ​ ​ 594,386 ​ ​ 560,500 ​ ​ 585,440 ​ 4.25% convertible senior notes due 2026 (3) ​ ​ — ​ ​ — ​ ​ 430,963 ​ ​ 169,383 ​ Total ​ $ 2,783,360 ​ ​ 3,206,868 ​ ​ 2,212,629 ​ ​ 1,984,593 ​ (1) Fair values are based on Level 2 market data inputs. (2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums. (3) Carrying value excludes the equity component of $116 million recorded to additional paid-in-capital for the 2026 Convertible Notes. See Note 12—Derivative Instruments to the consolidated financial statements for information regarding the fair value of derivative financial instruments.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2020
Derivative Instruments.
Derivative Instruments	(12) Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, and it uses derivative instruments to manage its commodity price risk. In addition, the Company periodically enters into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. (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, 2018, 2019 and 2020. 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. 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, 2020, the Company’s fixed price natural gas, oil and NGL swap positions from January 1, 2021 through December 31, 2023 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Henry Hub ​ 2,160,000 MMBtu/day ​ $ 2.77 /MMBtu ​ January-December 2022 ​ Henry Hub ​ 1,155,486 MMBtu/day ​ ​ 2.50 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 43,000 MMBtu/day ​ ​ 2.37 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Ethane Mt Belv ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-March 2021 ​ Mont Belvieu Purity Ethane-OPIS ​ 19,000 Bbl/day ​ $ 8.40 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ West Texas Intermediate ​ 3,000 Bbl/day ​ $ 55.16 /Bbl ​ ​ In addition, the Company has a call option agreement, which entitles the holder the right, but not the obligation, to enter into a fixed price swap agreement on December 21, 2023 to purchase 427,500 MMBtu per day at a price of $2.77 per MMBtu for the year ending December 31, 2024. As of December 31, 2020, 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, were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period ​ Index to Basis Differential Contracted Volume Hedged Differential ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ NYMEX to TCO ​ 40,000 MMBtu/day ​ $ 0.414 /MMBtu ​ January-December 2022 ​ NYMEX to TCO ​ 60,000 MMBtu/day ​ ​ 0.515 /MMBtu ​ January-December 2023 ​ NYMEX to TCO ​ 50,000 MMBtu/day ​ ​ 0.525 /MMBtu ​ January-December 2024 ​ NYMEX to TCO ​ 50,000 MMBtu/day ​ ​ 0.530 /MMBtu ​ ​ As of December 31, 2020, the Company had natural gas and NGL contracts for January 1, 2021 through December 31, 2021 that fix the Mont Belvieu index price to percentages of WTI as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period Index to Basis Differential Contracted Volume Payout Ratio ​ Gas Liquids ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Natural Gasoline to WTI ​ 9,325 Bbl/day ​ 78 % ​ ​ As of December 31, 2020, the Company’s fixed price natural gas, oil and NGL swap positions from January 1, 2021 through March 31, 2025 for Martica, the Company’s consolidated VIE, were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Henry Hub ​ 46,536 MMBtu/day ​ $ 2.62 /MMBtu January-December 2022 ​ Henry Hub ​ 38,356 MMBtu/day ​ ​ 2.39 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 35,615 MMBtu/day ​ ​ 2.35 /MMBtu ​ January-December 2024 ​ Henry Hub ​ 23,885 MMBtu/day ​ ​ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 18,021 MMBtu/day ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Propane Mt Belv Non-TET ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Propane-OPIS ​ 1,121 Bbl/day ​ $ 18.90 /Bbl ​ January-December 2022 ​ Mont Belvieu Propane-OPIS ​ 934 Bbl/day ​ ​ 19.32 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Natural Gasoline Mt Belv Non-TET ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Natural Gasoline-OPIS ​ 282 Bbl/day ​ $ 29.82 /Bbl ​ January-December 2022 ​ Mont Belvieu Natural Gasoline-OPIS ​ 282 Bbl/day ​ ​ 34.44 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Ethane Mt Belv ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Purity Ethane-OPIS ​ 987 Bbl/day ​ $ 7.14 /Bbl ​ January-March 2022 ​ Mont Belvieu Purity Ethane-OPIS ​ 521 Bbl/day ​ ​ 6.72 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ West Texas Intermediate ​ 117 Bbl/day ​ $ 39.94 /Bbl ​ January-December 2022 ​ West Texas Intermediate ​ 71 Bbl/day ​ ​ 41.09 /Bbl ​ January-December 2023 ​ West Texas Intermediate ​ 52 Bbl/day ​ ​ 42.45 /Bbl ​ January-December 2024 ​ West Texas Intermediate ​ 43 Bbl/day ​ ​ 44.02 /Bbl ​ January-March 2025 ​ West Texas Intermediate ​ 39 Bbl/day ​ ​ 45.06 /Bbl ​ ​ (b) Embedded Derivatives The VPP includes an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties of 111,743,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.60 per MMBtu. The embedded put option is not clearly and closely related to the host contract, and therefore, the Company bifurcated this derivative instrument and reflected it at fair value in the consolidated financial statements. (c) 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. 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 years ended December 31, 2019 and 2020. (d) 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, 2019 and 2020. None ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ December 31, ​ ​ Location 2019 ​ 2020 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current ​ Derivative instruments ​ $ 422,849 ​ ​ 97,144 ​ Embedded derivatives—current ​ Derivative instruments ​ ​ — ​ ​ 7,986 ​ Commodity derivatives—noncurrent ​ Derivative instruments ​ ​ 333,174 ​ ​ 14,689 ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ — ​ ​ 32,604 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives ​ ​ ​ ​ 756,023 ​ ​ 152,423 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (1) ​ Derivative instruments ​ ​ 6,721 ​ ​ 31,242 ​ Commodity derivatives—noncurrent (1) ​ Derivative instruments ​ ​ 3,519 ​ ​ 99,172 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives ​ ​ ​ ​ 10,240 ​ ​ 130,414 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives assets ​ ​ ​ $ 745,783 ​ ​ 22,009 ​ (1) As of December 31, 2020, approximately $14 million of commodity derivative liabilities, including $7 million of current commodity derivatives and $7 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. 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, 2019 ​ December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ Gross ​ Gross Amounts ​ Assets ​ Gross ​ Gross Amounts ​ Assets ​ ​ ​ Amounts on ​ Offset on ​ (Liabilities) on ​ Amounts on ​ Offset on ​ (Liabilities) on ​ ​ Balance Sheet Balance Sheet Balance Sheet Balance Sheet Balance Sheet Balance Sheet Commodity derivative assets ​ $ 882,817 ​ ​ (126,794) ​ ​ 756,023 ​ $ 181,375 ​ ​ (69,542) ​ ​ 111,833 ​ Embedded derivative assets ​ $ — ​ ​ — ​ ​ — ​ $ 40,590 ​ ​ — ​ ​ 40,590 ​ Commodity derivative liabilities ​ $ (137,034) ​ ​ 126,794 ​ ​ (10,240) ​ $ (199,956) ​ ​ 69,542 ​ ​ (130,414) ​ ​ 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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location 2018 ​ 2019 2020 ​ Commodity derivative fair value gains (losses) ​ Revenue ​ $ (87,594) ​ ​ 463,972 ​ ​ 40,565 ​ Embedded derivative fair value gains (losses) ​ Revenue ​ $ — ​ ​ — ​ ​ 39,353 ​ ​ Commodity derivative fair value gains (losses) for the years ended December 31, 2018 and 2020, include gains of $370 million and $9 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, 2018 and 2020. There were no commodity derivatives monetizations in the year ended December 31, 2019. The Company’s commodity derivative position presented in Note 12(a) above reflects the volume and adjusted fixed price indices after the 2020 monetization.

Leases

Leases	12 Months Ended
	Dec. 31, 2020
Leases
Leases	(13) Leases On February 25, 2016, the FASB issued ASU No. 2016-02, Leases 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 the Company’s 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 lease 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 elected the effective date method for adoption of the new leasing standard. 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 ASC 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. 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. 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 and liabilities as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ Leases Balance Sheet Classification 2019 2020 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,460,770 ​ ​ 1,302,290 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 71,662 ​ ​ 29,894 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,308,428 ​ ​ 1,241,090 ​ Office space ​ Operating lease right-of-use assets ​ ​ 40,491 ​ ​ 36,879 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 4,983 ​ ​ 2,704 ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 166 ​ ​ 746 ​ Total operating lease right-of-use assets ​ ​ ​ $ 2,886,500 ​ ​ 2,613,603 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease obligation ​ Short-term lease liabilities ​ $ 304,397 ​ ​ 265,178 ​ Long-term operating lease obligation ​ Long-term lease liabilities ​ ​ 2,582,103 ​ ​ 2,348,425 ​ Total operating lease obligation ​ ​ ​ $ 2,886,500 ​ ​ 2,613,603 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 2,328 ​ ​ 1,206 ​ Other office and field equipment ​ Other property and equipment ​ ​ 170 ​ ​ — ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 2,498 ​ ​ 1,206 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease obligation ​ Short-term lease liabilities ​ $ 923 ​ ​ 845 ​ Long-term finance lease obligation ​ Long-term lease liabilities ​ ​ 1,575 ​ ​ 361 ​ Total finance lease obligation ​ ​ ​ $ 2,498 ​ ​ 1,206 ​ (1) Gas gathering lines and compressor stations leases includes $1.1 billion related to Antero Midstream Corporation as of December 31, 2019 and 2020. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $9 million and $3 million as of December 31, 2019 and 2020, respectively. ​ The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC Topic 842, Leases Supplemental Information Related to Leases Costs associated with operating leases were included in the consolidated statement of operations and comprehensive loss for the years ended December 31, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ ​ ​ ​ December 31, ​ Cost Classification Location 2019 2020 ​ Operating lease cost ​ Statement of operations ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ ​ 1,498,221 ​ Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 11,228 ​ ​ 11,530 ​ Operating lease cost ​ Statement of operations ​ Contract termination and rig stacking ​ ​ 10,692 ​ ​ 8,528 ​ Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 194,522 ​ ​ 104,146 ​ Total operating lease cost ​ ​ ​ ​ ​ $ 1,058,882 ​ ​ 1,622,425 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation, and amortization ​ $ 1,471 ​ ​ 872 ​ Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 335 ​ ​ 208 ​ Total finance lease cost ​ ​ ​ ​ ​ $ 1,806 ​ ​ 1,080 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 162,654 ​ ​ 122,577 ​ (1) Capitalized costs related to drilling and completion activities. ​ Supplemental Cash Flow Information Related to Leases The following is the Company’s supplemental cash flow information related to leases for years ended December 31, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases ​ $ 809,667 ​ ​ 1,576,984 ​ Operating cash flows from finance leases ​ ​ 335 ​ ​ 208 ​ Investing cash flows from operating leases ​ ​ 178,898 ​ ​ 106,867 ​ Financing cash flows from finance leases ​ ​ 2,507 ​ ​ 1,291 ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ROU assets obtained in exchange for new operating lease obligations ​ $ 3,720,945 ​ ​ 202,125 ​ ​ ​ Maturities of Lease Liabilities The table below is a schedule of future minimum payments for operating and financing lease liabilities as of December 31, 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2021 ​ $ 611,093 ​ ​ 901 ​ ​ 611,994 ​ 2022 ​ ​ 579,079 ​ ​ 366 ​ ​ 579,445 ​ 2023 ​ ​ 575,228 ​ ​ 8 ​ ​ 575,236 ​ 2024 ​ ​ 566,461 ​ ​ — ​ ​ 566,461 ​ 2025 ​ ​ 493,783 ​ ​ — ​ ​ 493,783 ​ Thereafter ​ ​ 1,558,470 ​ ​ — ​ ​ 1,558,470 ​ Total lease payments ​ ​ 4,384,114 ​ ​ 1,275 ​ ​ 4,385,389 ​ Less: imputed interest ​ ​ (1,770,511) ​ ​ (69) ​ ​ (1,770,580) ​ Total ​ $ 2,613,603 ​ ​ 1,206 ​ ​ 2,614,809 ​ ​ Lease Term and Discount Rate The table below is the Company’s weighted-average remaining lease term and discount rate as of December 31, 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2020 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ ​ Weighted-average remaining lease term ​ 8.0 years ​ 1.5 years ​ ​ Weighted-average discount rate ​ 13.7 % 6.2 % ​ ​ 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 the Company requests 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 . 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 at certain points during such time. Upon completion of the initial contract term, the gathering and compression agreement will continue in effect from year to year until such time as the agreement is terminated, effective upon an anniversary of the effective date of the agreement, by either the Company or Antero Midstream Corporation on or before the 180 th day prior to the anniversary of such effective date. The Company achieved the volumetric targets during each quarter during the year ended December 31, 2020. Antero Midstream Corporation has provided rebates of $48 million for the year ended December 31, 2020. For the years ended December 31, 2019 and 2020, gathering and compression fees paid by Antero related to this agreement were $643 million and $679 million, respectively. As of December 31, 2019 and 2020,

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2020
Income Taxes
Income Taxes	(14) Income Taxes For the years ended December 31, 2018, 2019 and 2020, income tax benefit consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 Federal income tax expense (benefit) ​ $ — ​ ​ 5,048 ​ ​ (209) ​ State income tax expense (benefit), net of federal benefit ​ (128,857) ​ (79,158) ​ (397,273) ​ Total income tax benefit ​ $ (128,857) ​ ​ (74,110) ​ ​ (397,482) ​ ​ Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 21% to the years ended December 31, 2018, 2019 and 2020 to income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 Federal income tax expense (benefit) ​ $ (36,657) ​ ​ (77,122) ​ ​ (348,158) ​ State income tax expense (benefit), net of federal benefit ​ (12,627) ​ (8,826) ​ (50,584) ​ Change in state tax rate, net of federal effect ​ ​ (40,415) ​ ​ 24,041 ​ ​ 2,291 ​ Nondeductible equity-based compensation ​ 6,079 ​ 6,920 ​ 4,490 ​ Dividends received deduction ​ ​ — ​ ​ (4,201) ​ ​ (4,013) ​ Noncontrolling interest ​ ​ (73,881) ​ ​ (10,998) ​ ​ (1,801) ​ Deconsolidation adjustment ​ ​ — ​ ​ (6,626) ​ ​ — ​ Change in valuation allowance ​ 28,116 ​ 1,325 ​ 789 ​ Other ​ 528 ​ 1,377 ​ (496) ​ Total income tax benefit ​ $ (128,857) ​ ​ (74,110) ​ ​ (397,482) ​ ​ 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 as of December 31, 2019 and 2020 is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 560,136 ​ ​ 565,433 ​ Equity-based compensation ​ ​ 7,669 ​ ​ 8,445 ​ Investment in Antero Midstream ​ ​ 172,460 ​ ​ 330,301 ​ Other ​ ​ 15,754 ​ ​ 17,206 ​ Total deferred tax assets ​ ​ 756,019 ​ ​ 921,385 ​ Valuation allowance ​ ​ (46,802) ​ ​ (46,013) ​ Net deferred tax assets ​ ​ 709,217 ​ ​ 875,372 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 206,677 ​ ​ 13,189 ​ Oil and gas properties ​ ​ 1,284,528 ​ ​ 1,188,599 ​ Investment in Martica ​ ​ — ​ ​ 59,586 ​ 2026 Convertible Notes ​ ​ — ​ ​ 26,250 ​ Total deferred tax liabilities ​ ​ 1,491,205 ​ ​ 1,287,624 ​ Net deferred tax liabilities ​ $ (781,988) ​ ​ (412,252) ​ ​ 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 $47 million and 31, 2019 and 2020, respectively. The valuation allowance for each of the years ended December 31, 2019 and 2020, relates to Colorado and Oklahoma state NOL carryforwards and is primarily the result of expected future reduced income tax apportionment in those states. 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 in 2021. The Company has no unrecognized tax benefit balances through December 31, 2020. As of December 31, 2020, the Company has U.S. federal and state NOL carryforwards of $2.3 billion and $2.0 billion, respectively, exclusive of the valuation allowances discussed above. The U.S. federal and West Virginia NOL carryforwards generated in tax years prior to 2018 expire between 2032 and 2037. The Colorado NOL carryforwards generated in tax years prior to 2018 expire between 2025 and 2037. For tax years 2018 and thereafter, NOL carryforwards generated in these jurisdictions have no expiration date. The Pennsylvania NOL carryforwards expire between 2037 and 2040. Tax years 2017 through 2020 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 2016 through 2020.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2020
Commitments
Commitments	(15) 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, 2020 (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 2021 ​ $ 1,080,150 ​ ​ 54,873 ​ ​ 2,859 ​ ​ 265,849 ​ ​ 346,145 ​ ​ 1,749,876 ​ 2022 ​ ​ 1,037,503 ​ ​ 52,265 ​ ​ 328 ​ ​ 267,888 ​ ​ 311,557 ​ ​ 1,669,541 ​ 2023 ​ ​ 1,064,981 ​ ​ 59,140 ​ ​ — ​ ​ 300,971 ​ ​ 274,265 ​ ​ 1,699,357 ​ 2024 ​ ​ 1,024,833 ​ ​ 59,262 ​ ​ — ​ ​ 334,694 ​ ​ 231,767 ​ ​ 1,650,556 ​ 2025 ​ ​ 984,743 ​ ​ 47,960 ​ ​ — ​ ​ 306,918 ​ ​ 186,865 ​ ​ 1,526,486 ​ Thereafter ​ ​ 6,947,951 ​ ​ 113,379 ​ ​ — ​ ​ 1,138,489 ​ ​ 419,981 ​ ​ 8,619,800 ​ Total ​ $ 12,140,161 ​ ​ 386,879 ​ ​ 3,187 ​ ​ 2,614,809 ​ ​ 1,770,580 ​ ​ 16,915,616 ​ ​ (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 Antero Resources is committed to pay; however, the Company will record in its financial statements its proportionate share of costs based on its working interests. See Note 13—Leases to the consolidated financial statements for more information on the Company’s operating and finance leases. (e) Contract Terminations and Rig Stacking The Company incurs costs associated with the delay or cancellation of drilling and completion contracts with third-party contractors. These costs are recorded in Contract termination and rig stacking and included in the statement of operations and comprehensive income (loss) for the years ended December 31, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 ​ Contract termination and rig stacking ​ $ — ​ ​ 14,026 ​ ​ 14,290 ​ ​

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2020
Contingencies
Contingencies	(16) Contingencies Environmental In June 2018, the Company 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. The NOV alleges that combustion devices at these facilities did not meet applicable air permitting requirements. Separately, in June 2018, the Company 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. Subsequently, the West Virginia Department of Environmental Protection (“WVDEP”), and EPA Region V (covering Ohio facilities) each conducted its own inspections, and the Company has separately received NOVs from WVDEP and EPA Region V related to similar issues being investigated by the EPA Region III. The Company continues to negotiate with EPA overall and WVDEP to resolve the issues alleged in the NOVs and the information request. The Company’s operations at these facilities are not suspended, and management does not expect these matters to have a material adverse effect on the Company’s 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 its 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 multiple contractual disputes involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. In late 2015, WGL asserted that the natural gas index price specified in the Contracts was no longer appropriate and sought to invoke an alternative index clause in the Contracts. This dispute was referred to arbitration. In January 2017, the arbitration panel ruled in the Company’s favor and found that the natural gas index price specified in the Contracts should remain. In March of 2017, WGL filed a lawsuit against the Company in Colorado district court claiming that the Company breached contractual obligations by failing to deliver “TCO pool” gas, ultimately seeking damages of more than $40 million. Subsequently, after WGL failed to take certain volumes of gas required under the Contracts, the Company filed a separate lawsuit against WGL to recover damages that WGL refused to pay. These two lawsuits were consolidated and tried in June 2019. On June 20, 2019, the Company was awarded a jury verdict of approximately $96 million in damages against WGL. In addition, the jury rejected WGL’s claim against the Company, finding that the Company did not breach the Contracts. On December 10, 2020, the Colorado Court of Appeals affirmed the judgment of the trial court in favor of the Company. In February 2021, the Company and its royalty owners received a gross payment of approximately $107 million from WGL, which was in full satisfaction and discharge of the June 2019 judgment entered in favor of the Company. 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.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2020
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—Deconsolidation of Antero Midstream Partners LP 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—Segment Information to the consolidated financial statements for the operating results of the Company’s reportable segments.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2020
Segment Information
Segment Information	(18) Segment Information See Note 2(t)—Summary of Significant Accounting Policies—Industry Segments and Geographic Information to the consolidated financial statements for a description of the Company’s determination of its reportable segments. Revenues from midstream services 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, Antero Resources included the results of Antero Midstream Partners in its consolidated financial statements. Effective March 13, 2019, Antero no longer consolidates the results of Antero Midstream in its results; however, the Company’s segment disclosures include the results of the Company’s unconsolidated affiliates due to their significance to the Company’s operations. See Note 3—Deconsolidation of Antero Midstream Partners LP 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—Summary of Significant Accounting Policies 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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Intersegment ​ Consolidated ​ ​ Production Marketing Services 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 ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation (1) 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 ​ (1) Includes the consolidated results of Antero Midstream Partners through March 12, 2019 and results of the Company’s equity method investment in Antero Midstream Corporation effective March 13, 2019. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,178,330 ​ ​ 310,572 ​ ​ — ​ ​ — ​ ​ 3,488,902 ​ Intersegment ​ 2,797 ​ ​ — ​ ​ 900,719 ​ ​ (900,719) ​ ​ 2,797 ​ Total ​ $ 3,181,127 ​ ​ 310,572 ​ ​ 900,719 ​ ​ (900,719) ​ ​ 3,491,699 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 98,865 ​ ​ — ​ ​ — ​ ​ — ​ ​ 98,865 ​ Gathering, compression, processing, and transportation ​ ​ 2,530,838 ​ ​ — ​ ​ 165,386 ​ ​ (165,386) ​ ​ 2,530,838 ​ Impairment of oil and gas properties ​ ​ 223,770 ​ ​ — ​ ​ — ​ ​ — ​ ​ 223,770 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 673,640 ​ ​ (673,640) ​ ​ — ​ Depletion, depreciation, and amortization ​ ​ 861,870 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 861,870 ​ General and administrative ​ ​ 134,482 ​ ​ — ​ ​ 52,213 ​ ​ (52,213) ​ ​ 134,482 ​ Other ​ ​ 125,917 ​ ​ 469,404 ​ ​ 18,328 ​ ​ (18,328) ​ ​ 595,321 ​ Total ​ ​ 3,975,742 ​ ​ 469,404 ​ ​ 1,018,357 ​ ​ (1,018,357) ​ ​ 4,445,146 ​ Operating loss ​ $ (794,615) ​ ​ (158,832) ​ ​ (117,638) ​ ​ 117,638 ​ ​ (953,447) ​ Equity in earnings (loss) of unconsolidated affiliates ​ $ (62,660) ​ ​ — ​ ​ 86,430 ​ ​ (86,430) ​ ​ (62,660) ​ Investments in unconsolidated affiliates ​ $ 255,082 ​ ​ — ​ ​ — ​ ​ — ​ ​ 255,082 ​ Segment assets ​ $ 13,150,845 ​ ​ — ​ ​ 5,610,912 ​ ​ (5,610,912) ​ ​ 13,150,845 ​ Capital expenditures for segment assets ​ $ 874,357 ​ ​ — ​ ​ 196,724 ​ ​ (196,724) ​ ​ 874,357 ​ ​

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2020
Subsidiary Guarantors
Subsidiary Guarantors	(19) Subsidiary Guarantors 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 Antero (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 Antero or a restricted subsidiary of Antero, 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 Antero 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 tables present summarized financial information of Antero and its guarantor subsidiaries. The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company. Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ ​ ​ Parent (Antero) ​ ​ ​ and ​ ​ ​ Guarantor ​ (in thousands) Subsidiaries ​ Accounts receivable, non-guarantor subsidiaries ​ $ — ​ Accounts receivable, related parties ​ ​ — ​ Other current assets ​ ​ 543,841 ​ Total current assets ​ ​ 543,841 ​ Noncurrent assets ​ ​ 11,783,502 ​ Total assets ​ $ 12,327,343 ​ ​ ​ ​ ​ ​ Accounts payable, non-guarantor subsidiaries ​ $ — ​ Accounts payable, related parties ​ ​ 69,860 ​ Other current liabilities ​ ​ 906,348 ​ Total current liabilities ​ ​ 976,208 ​ Noncurrent liabilities ​ ​ 6,070,388 ​ Total liabilities ​ $ 7,046,596 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, ​ ​ ​ 2020 ​ ​ ​ Parent (Antero) ​ ​ ​ and ​ ​ ​ Guarantor ​ (in thousands) Subsidiaries ​ Revenues ​ $ 3,458,390 ​ Operating expenses ​ ​ 4,419,323 ​ Loss from operations ​ ​ (960,933) ​ Net loss and comprehensive loss including noncontrolling interests ​ ​ (1,267,897) ​ Net loss and comprehensive loss attributable to Antero Resources Corporation ​ $ (1,267,897) ​ ​

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2020
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, 2019 and 2020 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 the Company’s production revenues and the fair value of commodity derivatives. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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—basic ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ Earnings (loss) per common share—diluted ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ Quarter ​ Quarter ​ Quarter ​ Quarter ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,317,105 ​ ​ 484,911 ​ ​ 380,591 ​ 1,309,092 ​ Total operating expenses ​ 1,054,672 ​ ​ 1,091,833 ​ ​ 1,134,700 ​ 1,163,941 ​ Operating income (loss) ​ 262,433 ​ ​ (606,922) ​ ​ (754,109) ​ 145,151 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ (338,810) ​ ​ (463,068) ​ ​ (553,846) ​ 95,313 ​ Net income (loss) attributable to noncontrolling interest ​ ​ — ​ ​ 236 ​ ​ (18,233) ​ 25,483 ​ Net income (loss) attributable to Antero Resources Corporation ​ (338,810) ​ ​ (463,304) ​ ​ (535,613) ​ 69,830 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share—basic ​ $ (1.19) ​ ​ (1.73) ​ ​ (1.99) ​ 0.26 ​ Earnings (loss) per common share—diluted ​ $ (1.19) ​ ​ (1.73) ​ ​ (1.99) ​ 0.24 ​ ​ 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 method investments that were material to the quarters as presented. See Note 2—Summary of Significant Accounting Policies 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, 2020
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) ​ 2019 ​ 2020 ​ Proved properties ​ $ 11,859,817 ​ ​ 12,260,713 ​ Unproved properties ​ 1,368,854 ​ 1,175,178 ​ Total oil and gas properties ​ 13,228,671 ​ 13,435,891 ​ Accumulated depletion and depreciation ​ (3,284,330) ​ (3,818,279) ​ Net capitalized costs ​ $ 9,944,341 ​ ​ 9,617,612 ​ ​ (b) Costs Incurred in Certain Oil and Gas Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ (In thousands) ​ 2018 ​ 2019 ​ 2020 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ — ​ ​ — ​ ​ — ​ Unproved property ​ 172,387 ​ ​ 88,682 ​ ​ 45,129 ​ Development costs ​ 1,164,800 ​ ​ 1,104,336 ​ ​ 823,271 ​ Exploration costs ​ 323,773 ​ ​ 149,782 ​ ​ 2,993 ​ Total costs incurred ​ $ 1,660,960 ​ ​ 1,342,800 ​ ​ 871,393 ​ ​ (c) Results of Operations for Oil and Gas Producing Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (In thousands) ​ 2018 ​ 2019 ​ 2020 ​ Revenues ​ $ 3,652,894 ​ ​ 3,643,873 ​ ​ 3,083,905 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 1,601,985 ​ ​ 2,417,509 ​ ​ 2,736,478 ​ Exploration expenses ​ 4,958 ​ ​ 884 ​ ​ 1,083 ​ Depletion and depreciation ​ 832,326 ​ ​ 884,350 ​ ​ 854,331 ​ Impairment of unproved properties ​ 549,437 ​ ​ 1,300,444 ​ ​ 223,770 ​ Results of operations before income tax (expense) benefit ​ 664,188 ​ ​ (959,314) ​ ​ (731,757) ​ Income tax (expense) benefit ​ (156,350) ​ ​ 224,511 ​ ​ (176,061) ​ Results of operations ​ $ 507,838 ​ ​ (734,803) ​ ​ (907,818) ​ ​ (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, 2018, 2019 and 2020 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, net cash provided by operating activities, future drilling and completion costs, and other economic factors. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ Revisions ​ (1,280) ​ 65 ​ (8) ​ (940) ​ Extensions, discoveries and other additions ​ 799 ​ 48 ​ 3 ​ 1,105 ​ Production ​ (875) ​ (68) ​ (4) ​ (1,310) ​ Sales ​ (113) ​ — ​ — ​ (113) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2020 (1) ​ 10,025 ​ 1,236 ​ 33 ​ 17,635 ​ (1) Proved reserves for the noncontrolling interest in Martica as of December 31, 2020 were 254 Bcfe, which consists of 159 Bcf of natural gas, 15 MMBbl of NGLs and 0.5 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ 6,669 ​ 600 ​ 20 ​ 10,389 ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ December 31, 2020 (1) ​ 6,901 ​ 810 ​ 19 ​ 11,873 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ 4,756 ​ 452 ​ 26 ​ 7,622 ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​ December 31, 2020 (2) ​ 3,124 ​ 426 ​ 14 ​ 5,762 ​ (1) Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2020 were 181 Bcfe, which consists of 110 Bcf of natural gas, 11 MMBbl of NGLs and 0.3 MMBbl of oil and condensate. (2) Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2020 were 73 Bcfe, which consists of 49 Bcf of natural gas, 4 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Significant items included in the categories of proved developed and undeveloped reserve changes for the years ended December 31, 2018, 2019 and 2020 in the above table include the following: 2018 Changes in Reserves ● Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in the Appalachian Basin. ● 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 the Company’s 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 the Company’s 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 the Company’s assumed future ethane recovery. The Company 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 the Appalachian Basin. ● 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 the Company’s 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 the Company’s 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 the Company’s 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. The Company produced 1,175 Bcfe during the year ended December 31, 2019. 2020 Changes in Reserves ● Extensions, discoveries, and other additions of 1,105 Bcfe resulted from delineation and development drilling in the Appalachian Basin. ● Net downward revisions of 940 Bcfe include: ● Net downward revision of 1,126 Bcfe due to decreases in prices for natural gas, NGLs, and oil. ● Net downward revision of 922 Bcfe for locations that were not developed within five years of initial booking as proved reserves. ● Upward revisions of 485 Bcfe are due to an increase in the Company’s assumed future ethane recovery. ● Net upward revision of 132 Bcfe due to schedule optimization primarily driven by previously proved undeveloped properties reclassified from non-proved to proved undeveloped. ● Net upward performance revisions of 491 Bcfe. ● Sales of reserves of 113 Bcfe related to the VPP. The Company produced 1,310 Bcfe during the year ended December 31, 2020. (e) Standardized Measure of Discounted Future Net Cash Flow 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) ​ 2018 ​ 2019 ​ 2020 Future cash inflows ​ $ 64,199 ​ ​ 54,228 ​ ​ 37,845 ​ Future production costs ​ (30,007) ​ ​ (36,524) ​ ​ (32,202) ​ Future development costs ​ (3,453) ​ ​ (2,772) ​ ​ (1,685) ​ Future net cash flows before income tax ​ 30,739 ​ ​ 14,932 ​ ​ 3,958 ​ Future income tax expense (1) ​ (5,505) ​ ​ (1,639) ​ ​ — ​ Future net cash flows ​ 25,234 ​ ​ 13,293 ​ ​ 3,958 ​ 10% annual discount for estimated timing of cash flows ​ (14,756) ​ ​ (7,824) ​ ​ (2,748) ​ Standardized measure of discounted future net cash flows (2) ​ $ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ (1) Based on the 12-month average of the first-day-of-the-month prices used in the computation of PV-10 as of December 31, 2020, the future taxable net income generated over the life of the Company’s proved reserves is expected to be less than its NOL carryforward deductions and therefore, under the standardized measure, there is no deduction for federal or state income taxes. (2) The standardized measure of discounted future net cash flows for the noncontrolling interest in Martica was $359 million for the year ended December 31, 2020. The Company used the following 12-month weighted average prices to estimate its total equivalent reserves (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2018 ​ 2019 ​ 2020 ​ 12-month weighted average price ​ $ 3.56 ​ ​ 2.87 ​ ​ 2.15 ​ ​ (f) Changes in Standardized Measure of Discounted Future Net Cash Flow ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ (in millions) ​ 2018 ​ 2019 ​ 2020 ​ Sales of oil and gas, net of productions costs ​ $ (2,051) ​ ​ (1,116) ​ ​ (347) ​ Net changes in prices and production costs (1) ​ 707 ​ ​ (6,729) ​ ​ (5,455) ​ Development costs incurred during the period ​ 755 ​ ​ 758 ​ ​ 704 ​ Net changes in future development costs (2) ​ 37 ​ ​ (92) ​ ​ 249 ​ Extensions, discoveries and other additions ​ 1,925 ​ ​ 782 ​ ​ 31 ​ Acquisitions ​ — ​ ​ — ​ ​ — ​ Divestitures ​ ​ — ​ ​ — ​ ​ (174) ​ Revisions of previous quantity estimates ​ (53) ​ ​ (1,011) ​ ​ (379) ​ Accretion of discount ​ 1,018 ​ ​ 1,259 ​ ​ 607 ​ Net change in income taxes ​ (563) ​ ​ 1,513 ​ ​ 598 ​ Changes in timing and other ​ 76 ​ ​ (373) ​ ​ (93) ​ Net increase (decrease) ​ 1,851 ​ ​ (5,009) ​ ​ (4,259) ​ Beginning of year ​ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​ End of year (3) ​ $ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ (1) Includes $3.3 billion in increased production costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019. (2) Includes $185 million in increased future development costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019. (3) The standardized measure of discounted future net cash flows for the noncontrolling interest in Martica was $359 million for the year ended December 31, 2020.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Summary of Significant Accounting Policies
Basis of Presentation	(a) Basis of Presentation
Principles of Consolidation	(b) Principles of Consolidation
Use of Estimates	(c) Use of Estimates
Risks and Uncertainties	(d) Risks and Uncertainties
Cash and Cash Equivalents	(e) Cash and Cash Equivalents
Oil and Gas Properties	(f) Oil and Gas Properties
Impairment of Long Lived Assets Other than Oil and Gas Properties	(g) Impairment of Long-Lived Assets Other than Oil and Gas Properties
Other Property and Equipment	(h) Other Property and Equipment
Debt Issuance costs	(i) Debt Issuance Costs
Derivative Financial Instruments	(j) Derivative Financial Instruments
Asset Retirement Obligations	(k) Asset Retirement Obligations
Environmental Liabilities	(l) Environmental Liabilities
Natural Gas, NGLs, and Oil Revenues	(m) Natural Gas, NGLs, and Oil Revenues
Marketing Revenues and Expenses	(n) Marketing Revenues and Expenses
Deferred Revenue	(o) Deferred Revenue
Gathering compression, water handling and treatment revenue	(p) Gathering, Compression, Water Handling and Treatment Revenue
Concentrations of Credit Risk	(q) Concentrations of Credit Risk
Income Taxes	(r) Income Taxes
Fair Value Measurements	(s) Fair Value Measurements
Industry Segments and Geographic Information	(t) Industry Segments and Geographic Information
Earnings (loss) Per Common Share	(u) Earnings (Loss) Per Common Share
Treasury Share Retirement	(v) Treasury Share Retirement
Equity-Based Compensation	(w) Equity-Based Compensation
Recently Issued Accounting Standards	(x) Recently Issued Accounting Standard

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Summary of Significant Accounting Policies
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales)	​ ​ ​ ​ ​ ​ Year Ended December 31, 2018 ​ ​ ​ ​ Mercuria Energy America, Inc. ​ 14 % ​ Tenaska Marketing Ventures ​ 13 % ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ Sabine Pass Liquefaction LLC ​ 16 % ​ WGL Midstream ​ 15 % ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ Sabine Pass Liquefaction LLC ​ 11 % ​ WGL Midstream ​ 11 % ​
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, ​ ​ 2018 2019 2020 ​ Basic weighted average number of shares outstanding ​ 316,036 ​ 306,400 ​ 272,433 ​ Add: Dilutive effect of RSUs ​ — ​ — ​ — ​ Add: Dilutive effect of outstanding stock options ​ — ​ — ​ — ​ Add: Dilutive effect of PSUs ​ — ​ — ​ — ​ Add: Dilutive effect of 2026 Convertible Notes (2) ​ — ​ — ​ — ​ Diluted weighted average number of shares outstanding ​ 316,036 ​ 306,400 ​ 272,433 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 2,844 ​ 2,357 ​ 6,810 ​ Outstanding stock options ​ 626 ​ 527 ​ 327 ​ PSUs ​ 1,705 ​ 1,443 ​ 432 ​ 2026 Convertible Notes (3) ​ — ​ — ​ 31,388 ​ (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive. (2) In August 2020 and September 2020, the Company issued $287.5 million in aggregate principal amount of 2026 Convertible Notes (as defined below in Note 8—Long-Term Debt). (3) On January 12, 2021, the Company completed the Equitization Transactions (defined below in Note 8—Long-Term Debt) whereby the Company issued 31.4 million shares and repurchased $150 million aggregate principal amount of the 2026 Convertible Notes. See Note 8—Long-Term Debt to the consolidated financial statements for further discussion on this transaction .

Deconsolidation of Antero Mid_2

Deconsolidation of Antero Midstream Partners LP (Tables)	12 Months Ended
	Dec. 31, 2020
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 ​ 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, 2020
Revenue
Schedule of disaggregation of revenue	Revenue is disaggregated by type in the following table. The table also identifies which reportable segment that the disaggregated revenues relate. See Note 18—Segment Information to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ (in thousands) 2018 2019 2020 Reportable Segment ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,287,939 ​ ​ 2,247,162 ​ ​ 1,809,952 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 172,653 ​ ​ 124,563 ​ ​ 113,811 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 1,005,124 ​ ​ 1,094,599 ​ ​ 1,047,872 ​ Exploration and production ​ Oil sales ​ ​ 187,178 ​ ​ 177,549 ​ ​ 112,270 ​ Exploration and production ​ Gathering and compression (1) ​ ​ 17,817 ​ ​ 3,972 ​ ​ — ​ Equity method investment in Antero Midstream Corporation ​ Water handling and treatment (1) ​ ​ 3,527 ​ ​ 506 ​ ​ — ​ Equity method investment in Antero Midstream Corporation ​ Marketing ​ ​ 458,901 ​ ​ 292,207 ​ ​ 310,572 ​ Marketing ​ Total revenue from contracts with customers ​ ​ 4,133,139 ​ ​ 3,940,558 ​ ​ 3,394,477 ​ ​ ​ Income from derivatives, deferred revenue and other sources ​ ​ 6,487 ​ ​ 468,132 ​ ​ 97,222 ​ ​ ​ Total revenue ​ $ 4,139,626 ​ ​ 4,408,690 ​ ​ 3,491,699 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions. ​

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2020
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 ended December 31, 2019 and 2020 in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Antero ​ ​ ​ ​ ​ ​ ​ MarkWest ​ Midstream ​ ​ ​ ​ Stonewall (1) Joint Venture Corporation (2) Total ​ Balances as of 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 ​ Balances as of December 31, 2019 ​ ​ — ​ ​ — ​ ​ 1,055,177 ​ ​ 1,055,177 ​ Equity in loss of unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (62,660) ​ ​ (62,660) ​ Distributions/dividends from unconsolidated affiliates ​ ​ — ​ ​ — ​ ​ (171,022) ​ ​ (171,022) ​ Impairment (5) ​ ​ — ​ ​ — ​ ​ (610,632) ​ ​ (610,632) ​ Elimination of intercompany profit ​ ​ — ​ ​ — ​ ​ 44,219 ​ ​ 44,219 ​ Balances as of December 31, 2020 (7) ​ $ — ​ ​ — ​ ​ 255,082 ​ ​ 255,082 ​ (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 method 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) On December 16, 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 of the Company’s investment in Antero Midstream Corporation to reduce the carrying value of such investment to fair value, which was based on the quoted market share price of Antero Midstream Corporation as of December 31, 2019 and March 31, 2020, respectively (Level 1). (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. (7) The Company’s investment in Antero Midstream Corporation as of December 31, 2020, based on the quoted market share price of Antero Midstream Corporation on such date, was $1.1 billion.
Schedule of summarized financial information of Antero Midstream Corporation	Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ (in thousands) 2019 2020 ​ Current assets ​ $ 108,558 ​ ​ 93,931 ​ Noncurrent assets ​ ​ 6,174,320 ​ ​ 5,516,981 ​ Total assets ​ $ 6,282,878 ​ ​ 5,610,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 242,084 ​ ​ 94,005 ​ Noncurrent liabilities ​ ​ 2,897,380 ​ ​ 3,098,621 ​ Stockholders' equity ​ ​ 3,143,414 ​ ​ 2,418,286 ​ Total liabilities and stockholders' equity ​ $ 6,282,878 ​ ​ 5,610,912 ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the period ​ ​ ​ ​ ​ March 13, 2019 ​ ​ ​ ​ ​ through ​ Year Ended ​ (in thousands) December 31, 2019 December 31, 2020 ​ Revenues ​ $ 792,588 ​ ​ 900,719 ​ Operating expenses ​ ​ 1,177,610 ​ ​ 1,018,357 ​ Loss from operations ​ $ (385,022) ​ ​ (117,638) ​ Loss attributable to the equity method investment ​ $ (341,565) ​ ​ (122,527) ​

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2020
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Capital expenditures ​ $ 105,706 ​ 32,372 ​ Gathering, compression, processing, and transportation expenses ​ ​ 134,153 ​ ​ 152,724 ​ Marketing expenses ​ ​ 52,612 ​ ​ 68,193 ​ Interest expense, net ​ 30,834 ​ 25,645 ​ Accrued taxes ​ ​ 39,332 ​ ​ 40,796 ​ Other ​ 38,213 ​ 23,794 ​ Total accrued liabilities ​ $ 400,850 ​ 343,524 ​

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2020
Schedule of long-term debt	Long-term debt as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Credit Facility (a) ​ $ 552,000 ​ ​ 1,017,000 ​ 5.375% senior notes due 2021 (b) ​ ​ 952,500 ​ ​ — ​ 5.125% senior notes due 2022 (c) ​ ​ 923,041 ​ ​ 660,516 ​ 5.625% senior notes due 2023 (d) ​ ​ 750,000 ​ ​ 574,182 ​ 5.00% senior notes due 2025 (e) ​ ​ 600,000 ​ ​ 590,000 ​ 4.25% convertible senior notes due 2026 (f) ​ ​ — ​ ​ 287,500 ​ Total principal ​ ​ 3,777,541 ​ ​ 3,129,198 ​ Unamortized premium (discount), net ​ ​ 791 ​ ​ (111,886) ​ Unamortized debt issuance costs ​ ​ (19,464) ​ ​ (15,719) ​ Long-term debt ​ $ 3,758,868 ​ ​ 3,001,593 ​ ​
4.25% convertible senior notes due 2026
Schedule of long-term debt	The 2026 Convertible Notes consist of the following as of December 31, 2020 (in thousands): ​ ​ ​ ​ ​ Liability component: ​ ​ ​ ​ Principal ​ $ 287,500 ​ Less: unamortized note discount ​ ​ (112,265) ​ Less: unamortized debt issuance costs ​ ​ (5,852) ​ Net carrying value ​ $ 169,383 ​ Equity component (1) ​ $ 115,601 ​ (1) Recorded in additional paid-in capital, net of $3 million of issuance costs and $28 million of deferred taxes .

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2019 ​ 2020 ​ Beginning balances $ 58,979 ​ 54,845 ​ Obligations incurred ​ 2,312 ​ ​ 1,814 ​ Accretion expense ​ ​ 3,762 ​ ​ 3,421 ​ Settlement of obligations ​ ​ (153) ​ ​ (229) ​ Revisions to prior estimates ​ ​ (2,537) ​ ​ (5,399) ​ Effect of deconsolidation of Antero Midstream Partners LP (1) ​ ​ (7,518) ​ ​ — ​ Ending balances ​ $ 54,845 ​ ​ 54,452 ​ (1) Effective March 13, 2019, Antero no longer consolidates Antero Midstream Partners in its results.

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 ​ RSU awards ​ $ 41,505 ​ ​ 10,343 ​ ​ 12,510 ​ Stock options ​ ​ 1,799 ​ ​ 355 ​ ​ — ​ PSU awards ​ ​ 9,659 ​ ​ 8,069 ​ ​ 7,219 ​ Antero Midstream Partners phantom unit awards (1) ​ ​ 15,351 ​ ​ 3,425 ​ ​ 2,519 ​ Equity awards issued to directors ​ ​ 2,100 ​ ​ 1,367 ​ ​ 1,069 ​ Total expense ​ $ 70,414 ​ ​ 23,559 ​ ​ 23,317 ​ (1) Antero Resources recognized compensation expense for equity awards granted under the 2013 Plan, 2020 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—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions.
Summary of restricted stock unit awards activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Average ​ Aggregate ​ ​ ​ Number of ​ Grant Date ​ Intrinsic Value ​ ​ Shares Fair Value (in thousands) ​ Total awarded and unvested—December 31, 2019 ​ 2,370,575 ​ $ 12.81 ​ $ 6,756 ​ Granted ​ 7,001,802 ​ ​ 2.57 ​ ​ ​ ​ Vested ​ (809,008) ​ ​ 15.62 ​ ​ ​ ​ Forfeited ​ (130,972) ​ ​ 11.91 ​ ​ ​ ​ Total awarded and unvested—December 31, 2020 ​ 8,432,397 ​ $ 4.06 ​ $ 45,957 ​
Summary of stock option activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ Average ​ ​ ​ ​ ​ ​ ​ Average ​ Remaining ​ Intrinsic ​ ​ ​ Stock ​ Exercise ​ Contractual ​ Value ​ ​ Options Price Life (in thousands) ​ Outstanding—December 31, 2019 ​ 467,633 ​ $ 50.64 ​ 5.1 ​ $ — ​ Granted ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Forfeited ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Expired ​ (35,172) ​ ​ 50.56 ​ ​ ​ ​ ​ ​ Outstanding—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Vested—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Exercisable —December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​
Summary of Performance Stock Unit activity	A summary of PSU activity for the year ended December 31, 2020 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ Number of ​ Average Grant ​ ​ Units Date Fair Value ​ Total awarded and unvested—December 31, 2019 ​ 2,537,283 ​ $ 16.74 ​ Granted ​ 469,000 ​ ​ 2.97 ​ Forfeited ​ (29,316) ​ ​ 12.21 ​ Cancelled (unearned) ​ (429,169) ​ ​ 26.21 ​ Total awarded and unvested—December 31, 2020 ​ 2,547,798 ​ $ 12.66 ​
Schedule of weighted average fair value assumptions used for PSUs granted	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2018 ​ 2019 ​ 2020 ​ ​ Dividend yield ​ ​ — % ​ ​ — % ​ — % ​ Volatility ​ ​ 41 % ​ ​ 36 % ​ 80 % ​ Risk-free interest rate ​ ​ 2.49 % ​ ​ 2.35 % ​ 0.17 % ​ Weighted average fair value of awards granted—Absolute TSR ​ $ 24.85 ​ ​ ​ 9.26 ​ ​ 2.63 ​ ​ Weighted average fair value of awards granted—Relative TSR ​ $ — ​ ​ ​ — ​ ​ 3.30 ​ ​
Schedule of outstanding unvested restricted stock awards vesting schedule	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Aggregate ​ ​ ​ Number of ​ Grant Date ​ Intrinsic Value ​ ​ Units Fair Value (in thousands) ​ Total awarded and unvested—December 31, 2019 ​ 657,757 ​ $ 14.71 ​ $ 4,992 ​ Granted ​ — ​ ​ — ​ ​ ​ ​ Vested ​ (338,412) ​ ​ 14.44 ​ ​ ​ ​ Forfeited ​ (22,955) ​ ​ 14.08 ​ ​ ​ ​ Total awarded and unvested—December 31, 2020 ​ 296,390 ​ $ 15.06 ​ $ 2,285 ​

Fair value (Tables)

Fair value (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value
Schedule of fair value and carrying value of the senior notes and 2026 Convertible Notes	The fair value and carrying value of the senior notes and 2026 Convertible Notes as of December 31, 2019 and 2020 are as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ December 31, 2020 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 5.375% senior notes due 2021 ​ $ 906,304 ​ ​ 948,904 ​ ​ — ​ ​ — ​ 5.125% senior notes due 2022 ​ ​ 823,906 ​ ​ 918,640 ​ ​ 658,468 ​ ​ 658,400 ​ 5.625% senior notes due 2023 ​ ​ 602,550 ​ ​ 744,938 ​ ​ 562,698 ​ ​ 571,370 ​ 5.00% senior notes due 2025 ​ ​ 450,600 ​ ​ 594,386 ​ ​ 560,500 ​ ​ 585,440 ​ 4.25% convertible senior notes due 2026 (3) ​ ​ — ​ ​ — ​ ​ 430,963 ​ ​ 169,383 ​ Total ​ $ 2,783,360 ​ ​ 3,206,868 ​ ​ 2,212,629 ​ ​ 1,984,593 ​ (1) Fair values are based on Level 2 market data inputs. (2) Carrying values are presented net of unamortized debt issuance costs and debt discounts or premiums. (3) Carrying value excludes the equity component of $116 million recorded to additional paid-in-capital for the 2026 Convertible Notes.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Schedule of outstanding commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Henry Hub ​ 2,160,000 MMBtu/day ​ $ 2.77 /MMBtu ​ January-December 2022 ​ Henry Hub ​ 1,155,486 MMBtu/day ​ ​ 2.50 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 43,000 MMBtu/day ​ ​ 2.37 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Ethane Mt Belv ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-March 2021 ​ Mont Belvieu Purity Ethane-OPIS ​ 19,000 Bbl/day ​ $ 8.40 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ West Texas Intermediate ​ 3,000 Bbl/day ​ $ 55.16 /Bbl ​
Schedule of natural gas basis swap positions which settle on pricing index to basis differential of NYMEX to TCO	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period ​ Index to Basis Differential Contracted Volume Hedged Differential ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ NYMEX to TCO ​ 40,000 MMBtu/day ​ $ 0.414 /MMBtu ​ January-December 2022 ​ NYMEX to TCO ​ 60,000 MMBtu/day ​ ​ 0.515 /MMBtu ​ January-December 2023 ​ NYMEX to TCO ​ 50,000 MMBtu/day ​ ​ 0.525 /MMBtu ​ January-December 2024 ​ NYMEX to TCO ​ 50,000 MMBtu/day ​ ​ 0.530 /MMBtu ​
Schedule 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.	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted Average ​ Commodity / Settlement Period Index to Basis Differential Contracted Volume Payout Ratio ​ Gas Liquids ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Natural Gasoline to WTI ​ 9,325 Bbl/day ​ 78 % ​
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ December 31, ​ ​ Location 2019 ​ 2020 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current ​ Derivative instruments ​ $ 422,849 ​ ​ 97,144 ​ Embedded derivatives—current ​ Derivative instruments ​ ​ — ​ ​ 7,986 ​ Commodity derivatives—noncurrent ​ Derivative instruments ​ ​ 333,174 ​ ​ 14,689 ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ — ​ ​ 32,604 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives ​ ​ ​ ​ 756,023 ​ ​ 152,423 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (1) ​ Derivative instruments ​ ​ 6,721 ​ ​ 31,242 ​ Commodity derivatives—noncurrent (1) ​ Derivative instruments ​ ​ 3,519 ​ ​ 99,172 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives ​ ​ ​ ​ 10,240 ​ ​ 130,414 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives assets ​ ​ ​ $ 745,783 ​ ​ 22,009 ​ (1) As of December 31, 2020, approximately $14 million of commodity derivative liabilities, including $7 million of current commodity derivatives and $7 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica.
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, 2019 ​ December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ Gross ​ Gross Amounts ​ Assets ​ Gross ​ Gross Amounts ​ Assets ​ ​ ​ Amounts on ​ Offset on ​ (Liabilities) on ​ Amounts on ​ Offset on ​ (Liabilities) on ​ ​ Balance Sheet Balance Sheet Balance Sheet Balance Sheet Balance Sheet Balance Sheet Commodity derivative assets ​ $ 882,817 ​ ​ (126,794) ​ ​ 756,023 ​ $ 181,375 ​ ​ (69,542) ​ ​ 111,833 ​ Embedded derivative assets ​ $ — ​ ​ — ​ ​ — ​ $ 40,590 ​ ​ — ​ ​ 40,590 ​ Commodity derivative liabilities ​ $ (137,034) ​ ​ 126,794 ​ ​ (10,240) ​ $ (199,956) ​ ​ 69,542 ​ ​ (130,414) ​
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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location 2018 ​ 2019 2020 ​ Commodity derivative fair value gains (losses) ​ Revenue ​ $ (87,594) ​ ​ 463,972 ​ ​ 40,565 ​ Embedded derivative fair value gains (losses) ​ Revenue ​ $ — ​ ​ — ​ ​ 39,353 ​
VIE, Martica
Schedule of outstanding commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Henry Hub ​ 46,536 MMBtu/day ​ $ 2.62 /MMBtu January-December 2022 ​ Henry Hub ​ 38,356 MMBtu/day ​ ​ 2.39 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 35,615 MMBtu/day ​ ​ 2.35 /MMBtu ​ January-December 2024 ​ Henry Hub ​ 23,885 MMBtu/day ​ ​ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 18,021 MMBtu/day ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Propane Mt Belv Non-TET ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Propane-OPIS ​ 1,121 Bbl/day ​ $ 18.90 /Bbl ​ January-December 2022 ​ Mont Belvieu Propane-OPIS ​ 934 Bbl/day ​ ​ 19.32 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Natural Gasoline Mt Belv Non-TET ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Natural Gasoline-OPIS ​ 282 Bbl/day ​ $ 29.82 /Bbl ​ January-December 2022 ​ Mont Belvieu Natural Gasoline-OPIS ​ 282 Bbl/day ​ ​ 34.44 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ OPIS Ethane Mt Belv ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ Mont Belvieu Purity Ethane-OPIS ​ 987 Bbl/day ​ $ 7.14 /Bbl ​ January-March 2022 ​ Mont Belvieu Purity Ethane-OPIS ​ 521 Bbl/day ​ ​ 6.72 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2021 ​ West Texas Intermediate ​ 117 Bbl/day ​ $ 39.94 /Bbl ​ January-December 2022 ​ West Texas Intermediate ​ 71 Bbl/day ​ ​ 41.09 /Bbl ​ January-December 2023 ​ West Texas Intermediate ​ 52 Bbl/day ​ ​ 42.45 /Bbl ​ January-December 2024 ​ West Texas Intermediate ​ 43 Bbl/day ​ ​ 44.02 /Bbl ​ January-March 2025 ​ West Texas Intermediate ​ 39 Bbl/day ​ ​ 45.06 /Bbl ​

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Leases
Summary of supplemental balance sheet information related to leases	The Company’s lease assets and liabilities as of December 31, 2019 and 2020 consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ Leases Balance Sheet Classification 2019 2020 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,460,770 ​ ​ 1,302,290 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 71,662 ​ ​ 29,894 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,308,428 ​ ​ 1,241,090 ​ Office space ​ Operating lease right-of-use assets ​ ​ 40,491 ​ ​ 36,879 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 4,983 ​ ​ 2,704 ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 166 ​ ​ 746 ​ Total operating lease right-of-use assets ​ ​ ​ $ 2,886,500 ​ ​ 2,613,603 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease obligation ​ Short-term lease liabilities ​ $ 304,397 ​ ​ 265,178 ​ Long-term operating lease obligation ​ Long-term lease liabilities ​ ​ 2,582,103 ​ ​ 2,348,425 ​ Total operating lease obligation ​ ​ ​ $ 2,886,500 ​ ​ 2,613,603 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 2,328 ​ ​ 1,206 ​ Other office and field equipment ​ Other property and equipment ​ ​ 170 ​ ​ — ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 2,498 ​ ​ 1,206 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease obligation ​ Short-term lease liabilities ​ $ 923 ​ ​ 845 ​ Long-term finance lease obligation ​ Long-term lease liabilities ​ ​ 1,575 ​ ​ 361 ​ Total finance lease obligation ​ ​ ​ $ 2,498 ​ ​ 1,206 ​ (1) Gas gathering lines and compressor stations leases includes $1.1 billion related to Antero Midstream Corporation as of December 31, 2019 and 2020. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $9 million and $3 million as of December 31, 2019 and 2020, respectively.
Summary of costs associated with operating leases	Costs associated with operating leases were included in the consolidated statement of operations and comprehensive loss for the years ended December 31, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ ​ ​ ​ December 31, ​ Cost Classification Location 2019 2020 ​ Operating lease cost ​ Statement of operations ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ ​ 1,498,221 ​ Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 11,228 ​ ​ 11,530 ​ Operating lease cost ​ Statement of operations ​ Contract termination and rig stacking ​ ​ 10,692 ​ ​ 8,528 ​ Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 194,522 ​ ​ 104,146 ​ Total operating lease cost ​ ​ ​ ​ ​ $ 1,058,882 ​ ​ 1,622,425 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation, and amortization ​ $ 1,471 ​ ​ 872 ​ Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 335 ​ ​ 208 ​ Total finance lease cost ​ ​ ​ ​ ​ $ 1,806 ​ ​ 1,080 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 162,654 ​ ​ 122,577 ​ (1) Capitalized costs related to drilling and completion activities.
Summary of supplemental cash flow information related to leases	The following is the Company’s supplemental cash flow information related to leases for years ended December 31, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases ​ $ 809,667 ​ ​ 1,576,984 ​ Operating cash flows from finance leases ​ ​ 335 ​ ​ 208 ​ Investing cash flows from operating leases ​ ​ 178,898 ​ ​ 106,867 ​ Financing cash flows from finance leases ​ ​ 2,507 ​ ​ 1,291 ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ROU assets obtained in exchange for new operating lease obligations ​ $ 3,720,945 ​ ​ 202,125 ​
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, 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2021 ​ $ 611,093 ​ ​ 901 ​ ​ 611,994 ​ 2022 ​ ​ 579,079 ​ ​ 366 ​ ​ 579,445 ​ 2023 ​ ​ 575,228 ​ ​ 8 ​ ​ 575,236 ​ 2024 ​ ​ 566,461 ​ ​ — ​ ​ 566,461 ​ 2025 ​ ​ 493,783 ​ ​ — ​ ​ 493,783 ​ Thereafter ​ ​ 1,558,470 ​ ​ — ​ ​ 1,558,470 ​ Total lease payments ​ ​ 4,384,114 ​ ​ 1,275 ​ ​ 4,385,389 ​ Less: imputed interest ​ ​ (1,770,511) ​ ​ (69) ​ ​ (1,770,580) ​ Total ​ $ 2,613,603 ​ ​ 1,206 ​ ​ 2,614,809 ​
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, 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (in thousands) ​ Operating Leases ​ Financing Leases ​ Total ​ 2021 ​ $ 611,093 ​ ​ 901 ​ ​ 611,994 ​ 2022 ​ ​ 579,079 ​ ​ 366 ​ ​ 579,445 ​ 2023 ​ ​ 575,228 ​ ​ 8 ​ ​ 575,236 ​ 2024 ​ ​ 566,461 ​ ​ — ​ ​ 566,461 ​ 2025 ​ ​ 493,783 ​ ​ — ​ ​ 493,783 ​ Thereafter ​ ​ 1,558,470 ​ ​ — ​ ​ 1,558,470 ​ Total lease payments ​ ​ 4,384,114 ​ ​ 1,275 ​ ​ 4,385,389 ​ Less: imputed interest ​ ​ (1,770,511) ​ ​ (69) ​ ​ (1,770,580) ​ Total ​ $ 2,613,603 ​ ​ 1,206 ​ ​ 2,614,809 ​ ​
Summary of weighted-average remaining lease term and discount rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2020 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ ​ Weighted-average remaining lease term ​ 8.0 years ​ 1.5 years ​ ​ Weighted-average discount rate ​ 13.7 % 6.2 % ​

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Income Taxes
Schedule of income tax expense from continuing operations	For the years ended December 31, 2018, 2019 and 2020, income tax benefit consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 Federal income tax expense (benefit) ​ $ — ​ ​ 5,048 ​ ​ (209) ​ State income tax expense (benefit), net of federal benefit ​ (128,857) ​ (79,158) ​ (397,273) ​ Total income tax benefit ​ $ (128,857) ​ ​ (74,110) ​ ​ (397,482) ​
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 21% to the years ended December 31, 2018, 2019 and 2020 to income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 Federal income tax expense (benefit) ​ $ (36,657) ​ ​ (77,122) ​ ​ (348,158) ​ State income tax expense (benefit), net of federal benefit ​ (12,627) ​ (8,826) ​ (50,584) ​ Change in state tax rate, net of federal effect ​ ​ (40,415) ​ ​ 24,041 ​ ​ 2,291 ​ Nondeductible equity-based compensation ​ 6,079 ​ 6,920 ​ 4,490 ​ Dividends received deduction ​ ​ — ​ ​ (4,201) ​ ​ (4,013) ​ Noncontrolling interest ​ ​ (73,881) ​ ​ (10,998) ​ ​ (1,801) ​ Deconsolidation adjustment ​ ​ — ​ ​ (6,626) ​ ​ — ​ Change in valuation allowance ​ 28,116 ​ 1,325 ​ 789 ​ Other ​ 528 ​ 1,377 ​ (496) ​ Total income tax benefit ​ $ (128,857) ​ ​ (74,110) ​ ​ (397,482) ​
Schedule of net deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2019 2020 ​ Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 560,136 ​ ​ 565,433 ​ Equity-based compensation ​ ​ 7,669 ​ ​ 8,445 ​ Investment in Antero Midstream ​ ​ 172,460 ​ ​ 330,301 ​ Other ​ ​ 15,754 ​ ​ 17,206 ​ Total deferred tax assets ​ ​ 756,019 ​ ​ 921,385 ​ Valuation allowance ​ ​ (46,802) ​ ​ (46,013) ​ Net deferred tax assets ​ ​ 709,217 ​ ​ 875,372 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 206,677 ​ ​ 13,189 ​ Oil and gas properties ​ ​ 1,284,528 ​ ​ 1,188,599 ​ Investment in Martica ​ ​ — ​ ​ 59,586 ​ 2026 Convertible Notes ​ ​ — ​ ​ 26,250 ​ Total deferred tax liabilities ​ ​ 1,491,205 ​ ​ 1,287,624 ​ Net deferred tax liabilities ​ $ (781,988) ​ ​ (412,252) ​

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 (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 2021 ​ $ 1,080,150 ​ ​ 54,873 ​ ​ 2,859 ​ ​ 265,849 ​ ​ 346,145 ​ ​ 1,749,876 ​ 2022 ​ ​ 1,037,503 ​ ​ 52,265 ​ ​ 328 ​ ​ 267,888 ​ ​ 311,557 ​ ​ 1,669,541 ​ 2023 ​ ​ 1,064,981 ​ ​ 59,140 ​ ​ — ​ ​ 300,971 ​ ​ 274,265 ​ ​ 1,699,357 ​ 2024 ​ ​ 1,024,833 ​ ​ 59,262 ​ ​ — ​ ​ 334,694 ​ ​ 231,767 ​ ​ 1,650,556 ​ 2025 ​ ​ 984,743 ​ ​ 47,960 ​ ​ — ​ ​ 306,918 ​ ​ 186,865 ​ ​ 1,526,486 ​ Thereafter ​ ​ 6,947,951 ​ ​ 113,379 ​ ​ — ​ ​ 1,138,489 ​ ​ 419,981 ​ ​ 8,619,800 ​ Total ​ $ 12,140,161 ​ ​ 386,879 ​ ​ 3,187 ​ ​ 2,614,809 ​ ​ 1,770,580 ​ ​ 16,915,616 ​
Schedule of contract termination and rig stacking	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2018 2019 2020 ​ Contract termination and rig stacking ​ $ — ​ ​ 14,026 ​ ​ 14,290 ​

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2018, 2019 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ ​ ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Intersegment ​ Consolidated ​ ​ Production Marketing Services 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 ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation (1) 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 ​ (1) Includes the consolidated results of Antero Midstream Partners through March 12, 2019 and results of the Company’s equity method investment in Antero Midstream Corporation effective March 13, 2019. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,178,330 ​ ​ 310,572 ​ ​ — ​ ​ — ​ ​ 3,488,902 ​ Intersegment ​ 2,797 ​ ​ — ​ ​ 900,719 ​ ​ (900,719) ​ ​ 2,797 ​ Total ​ $ 3,181,127 ​ ​ 310,572 ​ ​ 900,719 ​ ​ (900,719) ​ ​ 3,491,699 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ $ 98,865 ​ ​ — ​ ​ — ​ ​ — ​ ​ 98,865 ​ Gathering, compression, processing, and transportation ​ ​ 2,530,838 ​ ​ — ​ ​ 165,386 ​ ​ (165,386) ​ ​ 2,530,838 ​ Impairment of oil and gas properties ​ ​ 223,770 ​ ​ — ​ ​ — ​ ​ — ​ ​ 223,770 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 673,640 ​ ​ (673,640) ​ ​ — ​ Depletion, depreciation, and amortization ​ ​ 861,870 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 861,870 ​ General and administrative ​ ​ 134,482 ​ ​ — ​ ​ 52,213 ​ ​ (52,213) ​ ​ 134,482 ​ Other ​ ​ 125,917 ​ ​ 469,404 ​ ​ 18,328 ​ ​ (18,328) ​ ​ 595,321 ​ Total ​ ​ 3,975,742 ​ ​ 469,404 ​ ​ 1,018,357 ​ ​ (1,018,357) ​ ​ 4,445,146 ​ Operating loss ​ $ (794,615) ​ ​ (158,832) ​ ​ (117,638) ​ ​ 117,638 ​ ​ (953,447) ​ Equity in earnings (loss) of unconsolidated affiliates ​ $ (62,660) ​ ​ — ​ ​ 86,430 ​ ​ (86,430) ​ ​ (62,660) ​ Investments in unconsolidated affiliates ​ $ 255,082 ​ ​ — ​ ​ — ​ ​ — ​ ​ 255,082 ​ Segment assets ​ $ 13,150,845 ​ ​ — ​ ​ 5,610,912 ​ ​ (5,610,912) ​ ​ 13,150,845 ​ Capital expenditures for segment assets ​ $ 874,357 ​ ​ — ​ ​ 196,724 ​ ​ (196,724) ​ ​ 874,357 ​

Subsidiary Guarantors (Tables)

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2020
Subsidiary Guarantors
Schedule of condensed consolidating balance sheets	​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ ​ ​ Parent (Antero) ​ ​ ​ and ​ ​ ​ Guarantor ​ (in thousands) Subsidiaries ​ Accounts receivable, non-guarantor subsidiaries ​ $ — ​ Accounts receivable, related parties ​ ​ — ​ Other current assets ​ ​ 543,841 ​ Total current assets ​ ​ 543,841 ​ Noncurrent assets ​ ​ 11,783,502 ​ Total assets ​ $ 12,327,343 ​ ​ ​ ​ ​ ​ Accounts payable, non-guarantor subsidiaries ​ $ — ​ Accounts payable, related parties ​ ​ 69,860 ​ Other current liabilities ​ ​ 906,348 ​ Total current liabilities ​ ​ 976,208 ​ Noncurrent liabilities ​ ​ 6,070,388 ​ Total liabilities ​ $ 7,046,596 ​
Schedule of condensed consolidating statement of operations	​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, ​ ​ ​ 2020 ​ ​ ​ Parent (Antero) ​ ​ ​ and ​ ​ ​ Guarantor ​ (in thousands) Subsidiaries ​ Revenues ​ $ 3,458,390 ​ Operating expenses ​ ​ 4,419,323 ​ Loss from operations ​ ​ (960,933) ​ Net loss and comprehensive loss including noncontrolling interests ​ ​ (1,267,897) ​ Net loss and comprehensive loss attributable to Antero Resources Corporation ​ $ (1,267,897) ​

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information (Unaudited)
Schedule of quarterly financial information	The Company’s quarterly consolidated financial information for the years ended December 31, 2019 and 2020 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 the Company’s production revenues and the fair value of commodity derivatives. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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—basic ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ Earnings (loss) per common share—diluted ​ $ 3.17 ​ 0.14 ​ (2.86) ​ (1.61) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ Quarter ​ Quarter ​ Quarter ​ Quarter ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total operating revenues ​ $ 1,317,105 ​ ​ 484,911 ​ ​ 380,591 ​ 1,309,092 ​ Total operating expenses ​ 1,054,672 ​ ​ 1,091,833 ​ ​ 1,134,700 ​ 1,163,941 ​ Operating income (loss) ​ 262,433 ​ ​ (606,922) ​ ​ (754,109) ​ 145,151 ​ Net income (loss) and comprehensive income (loss) including noncontrolling interest ​ ​ (338,810) ​ ​ (463,068) ​ ​ (553,846) ​ 95,313 ​ Net income (loss) attributable to noncontrolling interest ​ ​ — ​ ​ 236 ​ ​ (18,233) ​ 25,483 ​ Net income (loss) attributable to Antero Resources Corporation ​ (338,810) ​ ​ (463,304) ​ ​ (535,613) ​ 69,830 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Earnings (loss) per common share—basic ​ $ (1.19) ​ ​ (1.73) ​ ​ (1.99) ​ 0.26 ​ Earnings (loss) per common share—diluted ​ $ (1.19) ​ ​ (1.73) ​ ​ (1.99) ​ 0.24 ​

Supplemental Information on O_2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
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) ​ 2019 ​ 2020 ​ Proved properties ​ $ 11,859,817 ​ ​ 12,260,713 ​ Unproved properties ​ 1,368,854 ​ 1,175,178 ​ Total oil and gas properties ​ 13,228,671 ​ 13,435,891 ​ Accumulated depletion and depreciation ​ (3,284,330) ​ (3,818,279) ​ Net capitalized costs ​ $ 9,944,341 ​ ​ 9,617,612 ​
Schedule of costs incurred in certain oil and gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ (In thousands) ​ 2018 ​ 2019 ​ 2020 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ — ​ ​ — ​ ​ — ​ Unproved property ​ 172,387 ​ ​ 88,682 ​ ​ 45,129 ​ Development costs ​ 1,164,800 ​ ​ 1,104,336 ​ ​ 823,271 ​ Exploration costs ​ 323,773 ​ ​ 149,782 ​ ​ 2,993 ​ Total costs incurred ​ $ 1,660,960 ​ ​ 1,342,800 ​ ​ 871,393 ​
Schedule of results of operations for oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, (In thousands) ​ 2018 ​ 2019 ​ 2020 ​ Revenues ​ $ 3,652,894 ​ ​ 3,643,873 ​ ​ 3,083,905 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 1,601,985 ​ ​ 2,417,509 ​ ​ 2,736,478 ​ Exploration expenses ​ 4,958 ​ ​ 884 ​ ​ 1,083 ​ Depletion and depreciation ​ 832,326 ​ ​ 884,350 ​ ​ 854,331 ​ Impairment of unproved properties ​ 549,437 ​ ​ 1,300,444 ​ ​ 223,770 ​ Results of operations before income tax (expense) benefit ​ 664,188 ​ ​ (959,314) ​ ​ (731,757) ​ Income tax (expense) benefit ​ (156,350) ​ ​ 224,511 ​ ​ (176,061) ​ Results of operations ​ $ 507,838 ​ ​ (734,803) ​ ​ (907,818) ​
Schedule of proved developed and undeveloped reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ Revisions ​ (1,280) ​ 65 ​ (8) ​ (940) ​ Extensions, discoveries and other additions ​ 799 ​ 48 ​ 3 ​ 1,105 ​ Production ​ (875) ​ (68) ​ (4) ​ (1,310) ​ Sales ​ (113) ​ — ​ — ​ (113) ​ Purchases of reserves ​ — ​ — ​ — ​ — ​ December 31, 2020 (1) ​ 10,025 ​ 1,236 ​ 33 ​ 17,635 ​ (1) Proved reserves for the noncontrolling interest in Martica as of December 31, 2020 were 254 Bcfe, which consists of 159 Bcf of natural gas, 15 MMBbl of NGLs and 0.5 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ 6,669 ​ 600 ​ 20 ​ 10,389 ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ December 31, 2020 (1) ​ 6,901 ​ 810 ​ 19 ​ 11,873 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2018 ​ 4,756 ​ 452 ​ 26 ​ 7,622 ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​ December 31, 2020 (2) ​ 3,124 ​ 426 ​ 14 ​ 5,762 ​ (1) Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2020 were 181 Bcfe, which consists of 110 Bcf of natural gas, 11 MMBbl of NGLs and 0.3 MMBbl of oil and condensate. (2) Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2020 were 73 Bcfe, which consists of 49 Bcf of natural gas, 4 MMBbl of NGLs and 0.2 MMBbl of oil and condensate.
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ (in millions) ​ 2018 ​ 2019 ​ 2020 Future cash inflows ​ $ 64,199 ​ ​ 54,228 ​ ​ 37,845 ​ Future production costs ​ (30,007) ​ ​ (36,524) ​ ​ (32,202) ​ Future development costs ​ (3,453) ​ ​ (2,772) ​ ​ (1,685) ​ Future net cash flows before income tax ​ 30,739 ​ ​ 14,932 ​ ​ 3,958 ​ Future income tax expense (1) ​ (5,505) ​ ​ (1,639) ​ ​ — ​ Future net cash flows ​ 25,234 ​ ​ 13,293 ​ ​ 3,958 ​ 10% annual discount for estimated timing of cash flows ​ (14,756) ​ ​ (7,824) ​ ​ (2,748) ​ Standardized measure of discounted future net cash flows (2) ​ $ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ (1) Based on the 12-month average of the first-day-of-the-month prices used in the computation of PV-10 as of December 31, 2020, the future taxable net income generated over the life of the Company’s proved reserves is expected to be less than its NOL carryforward deductions and therefore, under the standardized measure, there is no deduction for federal or state income taxes. (2) The standardized measure of discounted future net cash flows for the noncontrolling interest in Martica was $359 million for the year ended December 31, 2020.
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2018 ​ 2019 ​ 2020 ​ 12-month weighted average price ​ $ 3.56 ​ ​ 2.87 ​ ​ 2.15 ​
Schedule of changes in standardized measure of discounted future net cash flow	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ (in millions) ​ 2018 ​ 2019 ​ 2020 ​ Sales of oil and gas, net of productions costs ​ $ (2,051) ​ ​ (1,116) ​ ​ (347) ​ Net changes in prices and production costs (1) ​ 707 ​ ​ (6,729) ​ ​ (5,455) ​ Development costs incurred during the period ​ 755 ​ ​ 758 ​ ​ 704 ​ Net changes in future development costs (2) ​ 37 ​ ​ (92) ​ ​ 249 ​ Extensions, discoveries and other additions ​ 1,925 ​ ​ 782 ​ ​ 31 ​ Acquisitions ​ — ​ ​ — ​ ​ — ​ Divestitures ​ ​ — ​ ​ — ​ ​ (174) ​ Revisions of previous quantity estimates ​ (53) ​ ​ (1,011) ​ ​ (379) ​ Accretion of discount ​ 1,018 ​ ​ 1,259 ​ ​ 607 ​ Net change in income taxes ​ (563) ​ ​ 1,513 ​ ​ 598 ​ Changes in timing and other ​ 76 ​ ​ (373) ​ ​ (93) ​ Net increase (decrease) ​ 1,851 ​ ​ (5,009) ​ ​ (4,259) ​ Beginning of year ​ 8,627 ​ ​ 10,478 ​ ​ 5,469 ​ End of year (3) ​ $ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ (1) Includes $3.3 billion in increased production costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019. (2) Includes $185 million in increased future development costs due to the deconsolidation of Antero Midstream Partners for the year ended December 31, 2019. (3) The standardized measure of discounted future net cash flows for the noncontrolling interest in Martica was $359 million for the year ended December 31, 2020.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation (Details) - USD ($) $ / shares in Units, $ in Millions	Mar. 11, 2019	Dec. 31, 2020	Dec. 31, 2019	Mar. 13, 2019
Basis of Presentation
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Accounts Payable
Basis of Presentation
Bank Overdrafts		$ 11	$ 7
Revenue distributions payable
Basis of Presentation
Bank Overdrafts		$ 15	$ 18
Antero Midstream Partners
Basis of Presentation
Ownership interest	53.00%
Antero Midstream Corporation
Basis of Presentation
Ownership interest in equity method		29.20%	28.70%	31.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Property and equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Property and Equipment
Depreciation expense	$ 861,870	$ 914,867	$ 972,465
Oil and Gas Properties
Impairment of oil and gas properties	223,770	1,300,444	549,437
Impairment of unproved oil and gas properties	224,000	393,000	549,000
Depreciation, depletion, and amortization expense for oil and gas properties	854,000	884,000	832,000
Impairment of long-lived assets other than oil and gas properties	0	15,000	10,000
Deferred Financing Costs
Unamortized debt issuance costs included in other long term assets	3,000	7,000
Unamortized debt issuance costs included as a reduction to long-term debt	16,000	19,000
Amounts amortized and the write-off of previously deferred debt issuance costs	8,000	11,000	13,000
Utica Shale
Oil and Gas Properties
Impairment of oil and gas properties		881,000
Other property and equipment
Property and Equipment
Depreciation expense	$ 8,000	8,000	9,000
Other property and equipment | Minimum
Property and Equipment
Estimated useful life	P2Y
Other property and equipment | Maximum
Property and Equipment
Estimated useful life	20 years
Oil and gas property wells
Oil and Gas Properties
Impairment of oil and gas properties	$ 0	$ 26,000	$ 0

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Credit Risk (Details) - Sales - Customer concentration	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Mercuria Energy America, Inc.
Concentrations of Credit Risk
Sales to major customers (as a percent)			14.00%
Tenaska Marketing Ventures
Concentrations of Credit Risk
Sales to major customers (as a percent)			13.00%
Sabine Pass Liquefaction LLC
Concentrations of Credit Risk
Sales to major customers (as a percent)	11.00%	16.00%
WGL Midstream
Concentrations of Credit Risk
Sales to major customers (as a percent)	11.00%	15.00%

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Derivative Financial Instruments (Details) $ in Millions	Dec. 31, 2020USD ($)Counterparty
Derivative Financial Instruments
Number of counterparties | Counterparty	17
Fair value of commodity derivative contracts	$ 22
Morgan Stanley
Derivative Financial Instruments
Fair value of commodity derivative contracts	35
Scotiabank
Derivative Financial Instruments
Fair value of commodity derivative contracts	14
Canadian Imperial Bank of Commerce
Derivative Financial Instruments
Fair value of commodity derivative contracts	25
Natixis
Derivative Financial Instruments
Fair value of commodity derivative contracts	5
DNB Bank
Derivative Financial Instruments
Fair value of commodity derivative contracts	2
Truist
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 1

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - USD ($) shares in Thousands, $ in Thousands	Jan. 01, 2022	Jan. 12, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Aug. 21, 2020
Earnings per share and New Accounting Principle
Basic weighted average number of shares outstanding			272,433	306,400	316,036
Diluted weighted average number of shares outstanding			272,433	306,400	316,036
Long-term debt, gross			$ 3,129,198	$ 3,777,541
Number of shares of common stock issued (in shares)		31,400
4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Long-term debt, gross			$ 287,500			$ 287,500
Interest rate (as a percent)			4.25%				4.25%
Effective interest rate							15.10%
Debt repurchased		$ 150,000
Accounting Standards Update 2020-06 | 4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Diluted weighted average number of shares outstanding			0
Interest rate during the period			15.10%
Accounting Standards Update 2020-06 | Adjustment Effect | Forecast
Earnings per share and New Accounting Principle
Noncurrent liabilities	$ 85,000
Accounting Standards Update 2020-06 | Adjustment Effect | Forecast | 4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Diluted weighted average number of shares outstanding	63,000
Effective interest rate	4.80%
RSUs
Earnings per share and New Accounting Principle
Weighted Average Anti-dilutive Awards			6,810	2,357	2,844
Stock options
Earnings per share and New Accounting Principle
Weighted Average Anti-dilutive Awards			327	527	626
PSUs
Earnings per share and New Accounting Principle
Weighted Average Anti-dilutive Awards			432	1,443	1,705
4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Weighted Average Anti-dilutive Awards			31,388

Deconsolidation of Antero Mid_3

Deconsolidation of Antero Midstream Partners LP - Narrative (Details) - USD ($) shares in Thousands, $ in Thousands	Mar. 12, 2019	Dec. 31, 2019	Mar. 13, 2019
Deconsolidation
Cash received		$ 296,611
Antero Midstream Corporation
Deconsolidation
Cash received	$ 297,000
Shares of Antero Midstream's common stock received	158,400
Gain on deconsolidation	$ 1,400,000
Fair value of our retained equity method investment			$ 2,000,000
Antero Midstream Partners
Deconsolidation
Number of common units exchanged	98,870,335

Deconsolidation of Antero Mid_4

Deconsolidation of Antero Midstream Partners LP - Summarized Financial Information of Antero Midstream Partners (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Mar. 12, 2019	Dec. 31, 2018
Deconsolidation
Current assets	$ 574,139	$ 922,885
Property and equipment, net	9,646,938	9,978,739
Noncurrent assets	13,790	21,094
Total assets	13,150,845	15,197,569		$ 15,519,464
Current liabilities	983,054	1,040,139
Long-term debt	3,001,593	3,758,868
Other noncurrent liabilities	59,694	58,635
Total liabilities	$ 7,060,574	$ 8,226,826
Antero Midstream Partners
Deconsolidation
Current assets			$ 763,109
Property and equipment, net			3,003,693
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

Transactions (Details)

Transactions (Details) ft in Thousands, $ in Thousands	Aug. 10, 2020USD ($)	Jul. 01, 2020MMBTU	Jun. 15, 2020USD ($)ft	Dec. 31, 2020USD ($)	Dec. 31, 2020USD ($)	Feb. 17, 2021
Transactions
Proceeds from sale of interest in VPP properties	$ 216,000				$ 215,789
Sixth Street
Transactions
Cash contribution			$ 300,000
Additional contribution upon achievement of production target			$ 102,000
Amount of cash distribution received				$ 51,000
Initial PDP Override (as a percent)			1.25%
Development Override (as a percent)			3.75%
Horizontal wells turned to sales, threshold one (in lateral feet) | ft			2,200
Horizontal wells turned to sales, threshold two (in lateral feet) | ft			3,820
Incremental override (percentage)			2.00%
Internal rate of return threshold			13.00%
Cash on cash return threshold			150.00%
Percentage of distributions received			85.00%
JPM -VEC
Transactions
Overriding royalty interest , production volume, threshold one (in MMBtu) | MMBTU		136,589,000
VPP agreement term for overriding royalty interest (in years)		7 years
QL | Subsequent event
Transactions
Percent of total development capital spending in current year to be funded by drilling partner						20.00%
QL | Minimum | Subsequent event
Transactions
Percent of total development capital spending in years 2-4 to be funded by drilling partner						15.00%
QL | Maximum | Subsequent event
Transactions
Percent of total development capital spending in years 2-4 to be funded by drilling partner						20.00%

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disaggregation of Revenue
Revenue									$ 3,394,477	$ 3,940,558	$ 4,133,139
Income from derivatives, deferred revenue and other sources									97,222	468,132	6,487
Total revenue	$ 1,309,092	$ 380,591	$ 484,911	$ 1,317,105	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	3,491,699	4,408,690	4,139,626
Natural gas sales
Disaggregation of Revenue
Revenue									1,809,952	2,247,162	2,287,939
Oil sales
Disaggregation of Revenue
Revenue									112,270	177,549	187,178
Gathering and compression
Disaggregation of Revenue
Revenue										3,972	17,817
Water handling and treatment
Disaggregation of Revenue
Revenue										506	3,527
Marketing
Disaggregation of Revenue
Revenue									310,572	292,207	458,901
Exploration and production | Natural gas sales
Disaggregation of Revenue
Revenue									1,809,952	2,247,162	2,287,939
Exploration and production | Natural gas liquids sales (ethane)
Disaggregation of Revenue
Revenue									113,811	124,563	172,653
Exploration and production | Natural gas liquids sales (C3+ NGLs)
Disaggregation of Revenue
Revenue									1,047,872	1,094,599	1,005,124
Exploration and production | Oil sales
Disaggregation of Revenue
Revenue									112,270	177,549	187,178
Marketing | Marketing
Disaggregation of Revenue
Revenue									$ 310,572	$ 292,207	$ 458,901

Revenue - Transaction Price All

Revenue - Transaction Price Allocation and Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue
Original expected duration	true
Receivables from contracts with customers	$ 425	$ 318

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Thousands	Dec. 16, 2019USD ($)	Mar. 12, 2019item	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Jun. 30, 2020USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Mar. 13, 2019	Dec. 31, 2017USD ($)
Investments in unconsolidated affiliates
Equity in net income (loss) of unconsolidated affiliates												$ (62,660)	$ (143,216)	$ 40,280
Distributions/dividends from unconsolidated affiliates												(171,022)	(157,956)	(46,415)
Impairment												(610,632)	(467,590)
Loss on the sale of equity method investment shares													108,745
Balance Sheet
Current assets			$ 574,139				$ 922,885				$ 922,885	574,139	922,885
Total assets			13,150,845				15,197,569				15,197,569	13,150,845	15,197,569	15,519,464
Current liabilities			983,054				1,040,139				1,040,139	983,054	1,040,139
Total equity			6,090,271				6,970,743				6,970,743	6,090,271	6,970,743	8,487,477		$ 8,876,136
Total liabilities and equity			13,150,845				15,197,569				$ 15,197,569	13,150,845	15,197,569
Sales and revenues			1,309,092	$ 380,591	$ 484,911	$ 1,317,105	952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407		3,491,699	4,408,690	4,139,626
Operating expenses			1,163,941	1,134,700	1,091,833	1,054,672	1,020,194	2,104,759	1,199,668	1,071,114		4,445,146	5,395,735	4,067,721
Loss from operations			145,151	(754,109)	(606,922)	262,433	(67,456)	(985,878)	99,996	(33,707)		(953,447)	(987,045)	71,905
Net loss including noncontrolling interests			$ 95,313	$ (553,846)	$ (463,068)	(338,810)	$ (482,196)	$ (878,864)	$ 42,168	1,025,756		$ (1,260,411)	$ (293,136)	(45,701)
Antero Midstream Corporation
Equity Method Investments
Ownership percentage			29.20%				28.70%				28.70%	29.20%	28.70%		31.00%
Balance Sheet
Current assets			$ 93,931				$ 108,558				$ 108,558	$ 93,931	$ 108,558
Noncurrent assets			5,516,981				6,174,320				6,174,320	5,516,981	6,174,320
Total assets			5,610,912				6,282,878				6,282,878	5,610,912	6,282,878
Current liabilities			94,005				242,084				242,084	94,005	242,084
Noncurrent liabilities			3,098,621				2,897,380				2,897,380	3,098,621	2,897,380
Total equity			2,418,286				3,143,414				3,143,414	2,418,286	3,143,414
Total liabilities and equity			5,610,912				6,282,878				6,282,878	5,610,912	6,282,878
Sales and revenues											792,588	900,719
Operating expenses											1,177,610	1,018,357
Loss from operations											(385,022)	(117,638)
Net loss including noncontrolling interests											(341,565)	(122,527)
Antero Midstream Corporation
Investments in unconsolidated affiliates
Balance at beginning of period						1,055,177						1,055,177
Equity in net income (loss) of unconsolidated affiliates												(62,660)	(155,480)
Distributions/dividends from unconsolidated affiliates												(171,022)	(145,351)
Return of investment													(208,745)
Impairment												(610,632)	(467,590)
Elimination of intercompany profit												44,219	44,548
Effects of deconsolidation													1,987,795
Balance at end of period			255,082				1,055,177				1,055,177	255,082	1,055,177
Loss on the sale of equity method investment shares	$ 109,000
Fair value of investment			1,100,000									1,100,000
Antero Midstream Partners
Equity Method Investments
Number of equity method investments | item		2
Investments in unconsolidated affiliates
Balance at beginning of period						$ 1,055,177				433,642		1,055,177	433,642
Investments													25,020
Equity in net income (loss) of unconsolidated affiliates												(62,660)	(143,216)
Distributions/dividends from unconsolidated affiliates												(171,022)	(157,956)
Return of investment													(208,745)
Impairment												(610,632)	(467,590)
Elimination of intercompany profit												44,219	44,548
Effects of deconsolidation													1,529,474
Balance at end of period			$ 255,082				$ 1,055,177				$ 1,055,177	$ 255,082	1,055,177	433,642
Antero Midstream Partners | Stonewall
Equity Method Investments
Ownership percentage		15.00%
Investments in unconsolidated affiliates
Balance at beginning of period										68,103			68,103
Equity in net income (loss) of unconsolidated affiliates													1,894
Distributions/dividends from unconsolidated affiliates													(3,000)
Effects of deconsolidation													(66,997)
Balance at end of period														68,103
Antero Midstream Partners | Appalachia joint venture
Equity Method Investments
Ownership percentage		50.00%
Investments in unconsolidated affiliates
Balance at beginning of period										$ 365,539			365,539
Investments													25,020
Equity in net income (loss) of unconsolidated affiliates													10,370
Distributions/dividends from unconsolidated affiliates													(9,605)
Effects of deconsolidation													$ (391,324)
Balance at end of period														$ 365,539
Antero Midstream Corporation
Investments in unconsolidated affiliates
Shares repurchased	$ 100,000

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accrued Liabilities
Capital expenditures	$ 32,372	$ 105,706
Gathering, compression, processing, and transportation expenses	152,724	134,153
Marketing expenses	68,193	52,612
Interest expense, net	25,645	30,834
Accrued taxes	40,796	39,332
Other	23,794	38,213
Total accrued liabilities	$ 343,524	$ 400,850

Long-Term Debt (Details)

Long-Term Debt (Details) $ / shares in Units, $ in Thousands	Jan. 26, 2021USD ($)	Jan. 12, 2021USD ($)$ / sharesshares	Jan. 04, 2021USD ($)	Aug. 21, 2020USD ($)Dshares	Dec. 31, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 10, 2021USD ($)	Jan. 16, 2021USD ($)	Sep. 30, 2020USD ($)	Sep. 02, 2020USD ($)	Dec. 21, 2016USD ($)	Mar. 17, 2015USD ($)	Sep. 18, 2014USD ($)	May 06, 2014USD ($)	Nov. 05, 2013USD ($)
Long- term Debt
Long-term debt, gross					$ 3,777,541	$ 3,129,198	$ 3,777,541
Less: unamortized note discount					791	(111,886)	791
Less: unamortized debt issuance costs					(19,464)	(15,719)	(19,464)
Long-term debt					3,758,868	3,001,593	3,758,868
Issuance of convertible notes						287,500
Payments of deferred financing costs						8,984	4,547	$ 2,169
Amount of debt repurchased						$ 1,400,000
Weighted average percentage discount on repurchases of debt						13.00%
Gain on extinguishment of debt repurchased						$ 175,962	36,419
Number of shares of common stock issued (in shares) | shares		31,400,000
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%
Tender Offer
Long- term Debt
Amount of debt repurchased						$ 367,000
Weighted average percentage discount on repurchases of debt						10.00%
Subsequent event | Equitization Transaction
Long- term Debt
Notional amount debt repurchased		$ 150,000
Credit Facility
Long- term Debt
Long-term debt, gross					$ 552,000	$ 1,017,000	$ 552,000
Current borrowing base						2,850,000
Lender commitments						$ 2,640,000
Weighted average interest rate (as a percent)					3.28%	3.26%	3.28%
Outstanding letters of credit					$ 623,000	$ 730,000	$ 623,000
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%
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%
5.375% senior notes due 2021
Long- term Debt
Long-term debt, gross					952,500		952,500
Interest rate (as a percent)						5.375%											5.375%
Senior notes issued																	$ 1,000,000
Issue price as percentage of par value																	100.00%
5.125 senior notes due 2022
Long- term Debt
Long-term debt, gross					923,041	$ 660,516	923,041
Interest rate (as a percent)						5.125%										5.125%
Senior notes issued															$ 500,000	$ 600,000
Issue price as percentage of par value															100.50%	100.00%
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 | On or after June 1, 2020
Long- term Debt
Redemption price						100.00%
5.125 senior notes due 2022 | Subsequent event
Long- term Debt
Notional amount debt repurchased									$ 311,000	$ 350,000
5.625% senior notes due 2023
Long- term Debt
Long-term debt, gross					750,000	$ 574,182	750,000
Interest rate (as a percent)						5.625%								5.625%
Senior notes issued														$ 750,000
Issue price as percentage of par value														100.00%
Redemption price						101.406%
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 | On Or After June 1, 2021
Long- term Debt
Redemption price						100.00%
5.00% senior notes due 2025
Long- term Debt
Long-term debt, gross					$ 600,000	$ 590,000	$ 600,000
Interest rate (as a percent)						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 | 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%
4.25% convertible senior notes due 2026
Long- term Debt
Long-term debt, gross						$ 287,500					$ 287,500
Less: unamortized note discount				$ 116,000		(112,265)
Less: unamortized debt issuance costs						(5,852)
Long-term debt						$ 169,383
Interest rate (as a percent)				4.25%		4.25%
Issuance of convertible notes				$ 278,500
Payments of deferred financing costs				$ 9,000
Equity component						$ 115,601
Conversion rate in shares of Antero Resources' common stock per $1,000 principal amount | shares				230.2026
If-converted value						361,000
If-converted value above principal amount						73,000
Effective interest rate				15.10%
Debt issuance cost						3,000
Deferred taxes						$ 28,000
Senior notes issued				$ 250,000								$ 37,500
Notional amount debt repurchased		$ 150,000
4.25% convertible senior notes due 2026 | Convertible debt threshold minimum percentage
Long- term Debt
Stock price trigger				98.00%
Trading days | D				5
Consecutive trading days | D				10
4.25% convertible senior notes due 2026 | Convertible debt threshold maximum percentage
Long- term Debt
Stock price trigger				130.00%
Trading days | D				20
Consecutive trading days | D				30
4.25% convertible senior notes due 2026 | Subsequent event
Long- term Debt
Conversion price | $ / shares		$ 0.2302026
Number of shares of common stock issued (in shares) | shares		31,400,000
Share price | $ / shares		$ 6.35
4.25% convertible senior notes due 2026 | Subsequent event | Equitization Transaction
Long- term Debt
Conversion price | $ / shares		$ 0.2753525
Proceeds from Issuance or Sale of Equity		$ 63,000
4.25% convertible senior notes due 2026 | Fair value
Long- term Debt
Fair value				$ 172,000
8.375% Senior Notes Due 2026 | Subsequent event
Long- term Debt
Interest rate (as a percent)			8.375%
Senior notes issued			$ 500,000
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%
8.375% Senior Notes Due 2026 | Subsequent event | On or after 15 January, 2024
Long- term Debt
Redemption price			104.188%
8.375% Senior Notes Due 2026 | Subsequent event | On or after 15 January, 2026
Long- term Debt
Redemption price			100.00%
8.375% Senior Notes Due 2026 | Subsequent event | On or before 15 January, 2024
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)			108.375%
8.375% Senior Notes Due 2026 | Subsequent event | Prior to 15 January 2024
Long- term Debt
Redemption price			100.00%
7.625% Senior Notes Due 2029 | Subsequent event
Long- term Debt
Interest rate (as a percent)	7.625%
Senior notes issued	$ 700,000
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%
7.625% Senior Notes Due 2029 | Subsequent event | On or after 01 February, 2024
Long- term Debt
Redemption price	103.813%
7.625% Senior Notes Due 2029 | Subsequent event | On or after 01 February, 2027
Long- term Debt
Redemption price	100.00%
7.625% Senior Notes Due 2029 | Subsequent event | On or before 01 February, 2024
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)	107.625%
7.625% Senior Notes Due 2029 | Subsequent event | Prior to 01 February 2024
Long- term Debt
Redemption price	100.00%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 54,845	$ 58,979
Obligations incurred	1,814	2,312
Accretion expense	3,421	3,762	$ 2,819
Settlement of obligations	(229)	(153)
Revisions to prior estimates	(5,399)	(2,537)
Effect of deconsolidation of Antero Midstream Partners LP		(7,518)
Asset retirement obligations - end of period	$ 54,452	$ 54,845	$ 58,979

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Jun. 17, 2020
Stock-based compensation expense
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Equity based compensation expense recognized	$ 23,317	$ 23,559	$ 70,414
2020 Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized				10,050,000
Number of shares available for future grant under the Plan	6,921,638
Midstream Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized	10,000,000
RSUs
Stock-based compensation expense
Equity based compensation expense recognized	$ 12,510	10,343	41,505
Stock options
Stock-based compensation expense
Equity based compensation expense recognized		355	1,799
PSUs
Stock-based compensation expense
Equity based compensation expense recognized	$ 7,219	8,069	9,659
Granted (in shares)	469,000
Antero Midstream Partners Phantom Unit Awards
Stock-based compensation expense
Equity based compensation expense recognized	$ 2,519	3,425	15,351
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized	$ 1,069	$ 1,367	$ 2,100
Antero Midstream Corporation | AMC Plan
Stock-based compensation expense
Conversion rate of units converted into restricted stock	1.8926
Antero Midstream Corporation | AMC Plan | Common Stock
Stock-based compensation expense
Conversion rate of units converted into restricted stock	1
Antero Midstream Corporation | RSUs
Stock-based compensation expense
Conversion rate of units converted into restricted stock	1.8926

Equity-Based Compensation - Res

Equity-Based Compensation - Restricted Stock and RSU Awards (Details) - RSUs $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / sharesshares
Number of shares
Total awarded and unvested at the beginning of the period (in shares) | shares	2,370,575
Granted (in shares) | shares	7,001,802
Vested (in shares) | shares	(809,008)
Forfeited (in shares) | shares	(130,972)
Total awarded and unvested at the end of the period (in shares) | shares	8,432,397
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 12.81
Granted (in dollars per share) | $ / shares	2.57
Vested (in dollars per share) | $ / shares	15.62
Forfeited (in dollars per share) | $ / shares	11.91
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 4.06
Aggregate intrinsic value
Total awarded and unvested at the beginning of the period | $	$ 6,756
Total awarded and unvested at the end of the period | $	45,957
Additional equity compensation to be recognized over the remaining period | $	$ 23,000
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 2 months 12 days

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Options (Details) - Stock options - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stock options
Outstanding at the beginning of the period (in shares)	467,633
Options expired (in shares)	(35,172)
Outstanding at the end of the period (in shares)	432,461	467,633
Vested (in shares)	432,461
Exercisable (in shares)	432,461
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.64
Options expired (in dollars per share)	50.56
Outstanding at the end of the period (in dollars per share)	50.64	$ 50.64
Vested (in dollars per share)	50.64
Exercisable (in dollars per share)	$ 50.64
Weighted average remaining contractual life
Outstanding	4 years 1 month 6 days	5 years 1 month 6 days
Vested	4 years 1 month 6 days
Exercisable	4 years 1 month 6 days
Additional disclosures
Assumed dividend yield	0.00%
Maximum
Stock-based compensation
Contractual life	10 years

Equity-Based Compensation - PSU

Equity-Based Compensation - PSU awards (Details) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended				24 Months Ended
	Jul. 31, 2020USD ($)	Jan. 31, 2020USD ($)tranche$ / sharesshares	Dec. 31, 2020USD ($)item$ / sharesshares	Dec. 31, 2019$ / sharesshares	Dec. 31, 2018$ / shares	Dec. 31, 2016	Dec. 31, 2017
PSUs
Number of performance period | item			3
Number of cumulative performance periods | item			1
Vesting period			3 years
Amortization period of PSU expense			3 years
Number of units
Total awarded and unvested at the beginning of the period (in shares) | shares		2,537,283	2,537,283
Granted (in shares) | shares			469,000
Forfeited (in shares) | shares			(29,316)
Cancelled (unearned) | shares			(429,169)
Total awarded and unvested at the end of the period (in shares) | shares			2,547,798	2,537,283
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share)		$ 16.74	$ 16.74
Granted (in dollars per share)			2.97
Forfeited (in dollars per share)			12.21
Cancelled (unearned) (in dollars per share)			26.21
Total awarded and unvested at the end of the period (in dollars per share)			$ 12.66	$ 16.74
Additional disclosures
Additional equity compensation to be recognized over the remaining period | $			$ 8
Weighted average period for recognizing unrecognized stock-based compensation expense			1 year 2 months 12 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)			80.00%	36.00%	41.00%
Risk-free interest rate (as a percent)			0.17%	2.35%	2.49%
Weighted average fair value of awards granted-Absolute TSR			$ 2.63	$ 9.26	$ 24.85
Weighted average fair value of awards granted-Absolute Relative TSR			$ 3.30
PSUs | Minimum
Number of PSUs that may vest, as a percent			0.00%
PSUs | Maximum
Number of PSUs that may vest, as a percent			150.00%
PSUs | One Year Period
Service period			1 year
PSUs | Three Year Period
Service period			3 years
Cash Awards
Vesting period	4 years
Additional disclosures
Cash awards granted | $	$ 2.6	$ 3.3
Number of tranches | tranche		3
Cash awards accrued in other liabilities | $			$ 3.2
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%				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%

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Unit Awards (Details) - AMC Plan $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)$ / sharesshares
Aggregate intrinsic value
Additional equity compensation to be recognized over the remaining period | $	$ 2,200
Weighted average period for recognizing unrecognized stock-based compensation expense	1 year
Antero Midstream Corporation
Number of units
Total awarded and unvested at the beginning of the period (in shares)	657,757
Vested (in shares)	(338,412)
Forfeited (in shares)	(22,955)
Total awarded and unvested at the end of the period (in shares)	296,390
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 14.71
Vested (in dollars per share) | $ / shares	14.44
Forfeited (in dollars per share) | $ / shares	14.08
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 15.06
Aggregate intrinsic value
Outstanding at the beginning of the period | $	$ 4,992
Outstanding at the end of the period | $	$ 2,285
Conversion rate of units converted into restricted stock	1.8926

Fair Value (Details)

Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Aug. 21, 2020	Dec. 31, 2019	Dec. 21, 2016	Mar. 17, 2015	May 06, 2014	Nov. 05, 2013
5.375% senior notes due 2021
Financial Instruments
Interest rate (as a percent)	5.375%						5.375%
5.125 senior notes due 2022
Financial Instruments
Interest rate (as a percent)	5.125%					5.125%
5.625% senior notes due 2023
Financial Instruments
Interest rate (as a percent)	5.625%				5.625%
5.00% senior notes due 2025
Financial Instruments
Interest rate (as a percent)	5.00%			5.00%
4.25% convertible senior notes due 2026
Financial Instruments
Interest rate (as a percent)	4.25%	4.25%
Equity component	$ 115,601
Fair value | Level 2 market data
Financial Instruments
Value	2,212,629		$ 2,783,360
Fair value | Level 2 market data | 5.375% senior notes due 2021
Financial Instruments
Value			906,304
Fair value | Level 2 market data | 5.125 senior notes due 2022
Financial Instruments
Value	658,468		823,906
Fair value | Level 2 market data | 5.625% senior notes due 2023
Financial Instruments
Value	562,698		602,550
Fair value | Level 2 market data | 5.00% senior notes due 2025
Financial Instruments
Value	560,500		450,600
Fair value | Level 2 market data | 4.25% convertible senior notes due 2026
Financial Instruments
Value	430,963
Carrying value
Financial Instruments
Value	1,984,593		3,206,868
Carrying value | 5.375% senior notes due 2021
Financial Instruments
Value			948,904
Carrying value | 5.125 senior notes due 2022
Financial Instruments
Value	658,400		918,640
Carrying value | 5.625% senior notes due 2023
Financial Instruments
Value	571,370		744,938
Carrying value | 5.00% senior notes due 2025
Financial Instruments
Value	585,440		$ 594,386
Carrying value | 4.25% convertible senior notes due 2026
Financial Instruments
Value	$ 169,383

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details)	12 Months Ended
	Dec. 31, 2020MMBTU / d$ / gal$ / MMBTU$ / bblbblgal
OPIS Propane Mt Belv Non-TET | January-December 2021
Derivative Instruments
Notional amount | bbl	1,121
Weighted average index price | $ / gal	18.90
OPIS Propane Mt Belv Non-TET | January-December 2022
Derivative Instruments
Notional amount | bbl	934
Weighted average index price | $ / gal	19.32
OPIS Natural Gasoline Mt Belv Non-TET | January-December 2021
Derivative Instruments
Notional amount | bbl	282
Weighted average index price | $ / gal	29.82
OPIS Natural Gasoline Mt Belv Non-TET | January-December 2022
Derivative Instruments
Notional amount | bbl	282
Weighted average index price | $ / gal	34.44
OPIS Ethane Mt Belv | January-December 2021
Derivative Instruments
Notional amount | bbl	987
Weighted average index price | $ / gal	7.14
OPIS Ethane Mt Belv | January-March 2022
Derivative Instruments
Notional amount | bbl	521
Weighted average index price | $ / gal	6.72
Natural gas | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	46,536
Weighted average index price | $ / MMBTU	2.62
Natural gas | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	38,356
Weighted average index price | $ / MMBTU	2.39
Natural gas | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	35,615
Weighted average index price | $ / MMBTU	2.35
Natural gas | January-December 2024
Derivative Instruments
Notional amount (MMBtu/day)	23,885
Weighted average index price | $ / MMBTU	2.33
Natural gas | January-March 2025
Derivative Instruments
Notional amount (MMBtu/day)	18,021
Weighted average index price | $ / MMBTU	2.53
Natural gas | NYMEX to TCO | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	40,000
Natural gas | NYMEX to TCO | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	60,000
Natural gas | NYMEX to TCO | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	50,000
Natural gas | NYMEX to TCO | January-December 2024
Derivative Instruments
Notional amount (MMBtu/day)	50,000
Oil | January-December 2021
Derivative Instruments
Notional amount | gal	117
Weighted average index price | $ / bbl	39.94
Oil | January-December 2022
Derivative Instruments
Notional amount | gal	71
Weighted average index price | $ / bbl	41.09
Oil | January-December 2023
Derivative Instruments
Notional amount | gal	52
Weighted average index price | $ / bbl	42.45
Oil | January-December 2024
Derivative Instruments
Notional amount | gal	43
Weighted average index price | $ / bbl	44.02
Oil | January-March 2025
Derivative Instruments
Notional amount | gal	39
Weighted average index price | $ / bbl	45.06
Swaps | OPIS Ethane Mt Belv | January-March 2021
Derivative Instruments
Notional amount | bbl	19,000
Weighted average index price | $ / gal	8.40
Swaps | Natural gas | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	2,160,000
Weighted average index price | $ / MMBTU	2.77
Swaps | Natural gas | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	1,155,486
Weighted average index price | $ / MMBTU	2.50
Swaps | Natural gas | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	43,000
Weighted average index price | $ / MMBTU	2.37
Swaps | Oil | January-December 2021
Derivative Instruments
Notional amount | gal	3,000
Weighted average index price | $ / gal	55.16
Fixed price swap agreement
Derivative Instruments
Notional amount (MMBtu/day)	427,500
Fixed price ($/MMBtu) | $ / MMBTU	2.77

Derivative Instruments (Details

Derivative Instruments (Details)	12 Months Ended
	Dec. 31, 2020MMBTU / d$ / MMBTU$ / bbl$ / galbblgal
Put option | Year ending December 31, 2026
Derivative Instruments
Notional amount (MMBtu/day)	111,743,000
Weighted average strike price | $ / MMBTU	2.60
Natural gas | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	46,536
Weighted average hedged differential | $ / MMBTU	2.62
Natural gas | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	38,356
Weighted average hedged differential | $ / MMBTU	2.39
Natural gas | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	35,615
Weighted average hedged differential | $ / MMBTU	2.35
Natural gas | January-December 2024
Derivative Instruments
Notional amount (MMBtu/day)	23,885
Weighted average hedged differential | $ / MMBTU	2.33
Natural gas | NYMEX to TCO | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	40,000
Weighted average payout ratio	0.414
Natural gas | NYMEX to TCO | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	60,000
Weighted average payout ratio	0.515
Natural gas | NYMEX to TCO | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	50,000
Weighted average payout ratio	0.525
Natural gas | NYMEX to TCO | January-December 2024
Derivative Instruments
Notional amount (MMBtu/day)	50,000
Weighted average payout ratio	0.530
Natural gas | Swaps | January-December 2021
Derivative Instruments
Notional amount (MMBtu/day)	2,160,000
Weighted average hedged differential | $ / MMBTU	2.77
Natural gas | Swaps | January-December 2022
Derivative Instruments
Notional amount (MMBtu/day)	1,155,486
Weighted average hedged differential | $ / MMBTU	2.50
Natural gas | Swaps | January-December 2023
Derivative Instruments
Notional amount (MMBtu/day)	43,000
Weighted average hedged differential | $ / MMBTU	2.37
Oil | January-December 2021
Derivative Instruments
Notional amount | gal	117
Weighted average hedged differential | $ / bbl	39.94
Oil | January-December 2022
Derivative Instruments
Notional amount | gal	71
Weighted average hedged differential | $ / bbl	41.09
Oil | January-December 2023
Derivative Instruments
Notional amount | gal	52
Weighted average hedged differential | $ / bbl	42.45
Oil | January-December 2024
Derivative Instruments
Notional amount | gal	43
Weighted average hedged differential | $ / bbl	44.02
Oil | Swaps | January-December 2021
Derivative Instruments
Notional amount | gal	3,000
Weighted average hedged differential | $ / gal	55.16
Natural gas liquids | Swaps | Mont Belvieu Natural Gasoline to WTI | January-December 2021
Derivative Instruments
Notional amount | bbl	9,325
Weighted average payout ratio	78

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) $ in Thousands	Dec. 31, 2020USD ($)item	Dec. 31, 2019USD ($)item
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 105,130	$ 422,849
Noncurrent portion of fair value of derivative assets	47,293	333,174
Current portion of fair value of derivative liabilities	31,242	6,721
Noncurrent portion of fair value of derivative liabilities	99,172	3,519
Commodity derivative
Fair value of derivative instruments
Total asset derivatives	111,833	756,023
Total liability derivatives	130,414	10,240
Embedded derivatives
Fair value of derivative instruments
Total asset derivatives	40,590
Derivatives not designated as hedges for accounting purposes
Fair value of derivative instruments
Total asset derivatives	152,423	756,023
Total liability derivatives	130,414	10,240
Derivatives not designated as hedges for accounting purposes | Commodity derivative
Fair value of derivative instruments
Current portion of fair value of derivative assets	97,144	422,849
Noncurrent portion of fair value of derivative assets	14,689	333,174
Current portion of fair value of derivative liabilities	31,242	6,721
Noncurrent portion of fair value of derivative liabilities	99,172	$ 3,519
Derivatives not designated as hedges for accounting purposes | Commodity derivative | VIE, Martica
Fair value of derivative instruments
Current portion of fair value of derivative liabilities	7,000
Noncurrent portion of fair value of derivative liabilities	7,000
Total liability derivatives	14,000
Derivatives not designated as hedges for accounting purposes | Embedded derivatives
Fair value of derivative instruments
Current portion of fair value of derivative assets	7,986
Noncurrent portion of fair value of derivative assets	$ 32,604
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 assets (liabilities)	$ 22,009	$ 745,783

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Commodity derivative
Commodity derivative assets
Gross amounts on balance sheet	$ 181,375	$ 882,817
Gross amounts offset on balance sheet	(69,542)	(126,794)
Total asset derivatives	111,833	756,023
Commodity derivative liabilities
Gross amounts on balance sheet	(199,956)	(137,034)
Gross amounts offset on balance sheet	69,542	126,794
Total liability derivatives	(130,414)	$ (10,240)
Embedded derivatives
Commodity derivative assets
Gross amounts on balance sheet	40,590
Total asset derivatives	$ 40,590

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, 2020	Dec. 31, 2019	Dec. 31, 2018
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value (gains) losses		$ 79,918	$ 463,972	$ (87,594)
Marketing Derivative		0	0	94,081
Proceeds from marketing derivative				73,000
Commodity derivative fair value gains (losses) on derivatives monetized prior to settlement dates		9,000	0	370,000
Premium paid for a collar agreement	$ 13,000
Commodity derivative | Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value (gains) losses		40,565	$ 463,972	$ (87,594)
Embedded derivatives | Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value (gains) losses		$ 39,353

Leases (Details)

Leases (Details)	12 Months Ended
	Dec. 31, 2020
Leases
Options to renew - Operating lease	true
Options to renew - Finance lease	true
Minimum
Leases
Renewal terms - Operating lease	1 year
Renewal terms - Finance lease	1 year
Maximum
Leases
Renewal terms - Operating lease	20 years
Renewal terms - Finance lease	20 years

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information Related to Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lease Assets
Operating lease right-of-use assets	$ 2,613,603	$ 2,886,500
Short-term operating lease obligation	$ 265,178	$ 304,397
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Short-term operating lease obligation	Short-term operating lease obligation
Long-term operating lease obligation	$ 2,348,425	$ 2,582,103
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Long-term operating lease obligation	Long-term operating lease obligation
Total operating lease obligation	$ 2,613,603	$ 2,886,500
Finance leases, right of use assets	1,206	2,498
Short-term lease liabilities, finance leases	$ 845	$ 923
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Short-term lease liabilities, finance leases	Short-term lease liabilities, finance leases
Long-term lease liabilities, finance leases	$ 361	$ 1,575
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Long-term lease liabilities, finance leases	Long-term lease liabilities, finance leases
Total	$ 1,206	$ 2,498
Finance leases, accumulated amortization	3,000	9,000
Vehicles
Lease Assets
Operating lease right-of-use assets	$ 2,704	$ 4,983
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets
Finance leases, right of use assets	$ 1,206	$ 2,328
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Property, Plant and Equipment, Other, Gross	Property, Plant and Equipment, Other, Gross
Other office and field equipment
Lease Assets
Operating lease right-of-use assets	$ 746	$ 166
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets
Finance leases, right of use assets		$ 170
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Property, Plant and Equipment, Other, Gross
Processing plants
Lease Assets
Operating lease right-of-use assets	$ 1,302,290	$ 1,460,770
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets
Drilling and completion rigs
Lease Assets
Operating lease right-of-use assets	$ 29,894	$ 71,662
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets
Gas gathering lines and compressor stations
Lease Assets
Operating lease right-of-use assets	$ 1,241,090	$ 1,308,428
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets
Gas gathering lines and compressor stations | Antero Midstream Corporation
Lease Assets
Operating lease right-of-use assets	$ 1,100,000	$ 1,100,000
Office space
Lease Assets
Operating lease right-of-use assets	$ 36,879	$ 40,491
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating lease right-of-use assets	Operating lease right-of-use assets

Leases - Supplemental Informati

Leases - Supplemental Information Related to Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases
Total lease expense	$ 1,622,425	$ 1,058,882
Total finance lease cost	1,080	1,806
Short-term lease payments	122,577	162,654
Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases	1,576,984	809,667
Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from financing leases	208	335
Cash paid for amounts included in the measurement of lease liabilities: Investing cash flows from operating leases	106,867	178,898
Cash paid for amounts included in the measurement of lease liabilities: Financing cash flows from finance leases	1,291	2,507
ROU assets obtained in exchange for new operating lease obligations	202,125	3,720,945
Gathering, compression, water handling and treatment
Leases
Total lease expense	1,498,221	842,440
General and administrative
Leases
Total lease expense	11,530	11,228
Contract termination and rig stacking
Leases
Total lease expense	8,528	10,692
Proved properties
Leases
Total lease expense	104,146	194,522
Depletion, Depreciation, And Amortization
Leases
Amortization of right-of-use assets	872	1,471
Interest expense
Leases
Interest on lease liabilities	$ 208	$ 335

Leases - Maturities of Lease Li

Leases - Maturities of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Future minimum payments for operating lease liabilities
2021	$ 611,093
2022	579,079
2023	575,228
2024	566,461
2025	493,783
Thereafter	1,558,470
Total lease payments	4,384,114
Less: imputed interest	(1,770,511)
Total operating lease obligation	2,613,603	$ 2,886,500
Future minimum payments for financing lease liabilities
2021	901
2022	366
2023	8
Total lease payments	1,275
Less: imputed interest	(69)
Total	1,206	$ 2,498
Future minimum payments for total lease liabilities
2021	611,994
2022	579,445
2023	575,236
2024	566,461
2025	493,783
Thereafter	1,558,470
Total lease payments	4,385,389
Less: imputed interest	(1,770,580)
Total	$ 2,614,809

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2020
Leases
Weighted-average remaining lease term: Operating lease	8 years
Weighted-average discount rate: Operating lease	13.70%
Weighted-average remaining lease term: Finance lease	1 year 6 months
Weighted-average discount rate: Finance lease	6.20%

Leases - Related party disclosu

Leases - Related party disclosure (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases
Accounts payable, related parties	$ 69,860	$ 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
Notice period	180 days
Rebate received	$ 48,000
Gathering and compression fees paid	679,000	643,000
Accounts payable, related parties	$ 55,000	$ 57,000

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income tax expense from continuing operations
Federal income tax expense (benefit)	$ (209)	$ 5,048
State income tax expense (benefit), net of federal benefit	(397,273)	(79,158)	$ (128,857)
Income tax expense (benefit)	$ (397,482)	$ (74,110)	$ (128,857)
U.S. Statutory federal income tax rate (as a percent)	21.00%	21.00%	21.00%
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)	$ (348,158)	$ (77,122)	$ (36,657)
State income tax expense (benefit), net of federal benefit	(50,584)	(8,826)	(12,627)
Change in State tax rate, net of federal effect	2,291	24,041	(40,415)
Nondeductible stock compensation	4,490	6,920	6,079
Dividends received deduction	(4,013)	(4,201)
Noncontrolling interest	(1,801)	(10,998)	(73,881)
Deconsolidation adjustment		(6,626)
Change in valuation allowance	789	1,325	28,116
Other	(496)	1,377	528
Total income tax expense from continuing operations	(397,482)	(74,110)	$ (128,857)
Deferred tax assets:
Net operating loss carryforwards	565,433	560,136
Equity based compensation	8,445	7,669
Investment in Antero Midstream	330,301	172,460
Other	17,206	15,754
Total deferred tax assets	921,385	756,019
Valuation allowance	(46,013)	(46,802)
Net deferred tax assets	875,372	709,217
Deferred tax liabilities:
Unrealized gains on derivative instruments	13,189	206,677
Oil and gas properties	1,188,599	1,284,528
Investment in Martica	59,586
2026 Convertible Notes	26,250
Total deferred tax liabilities	1,287,624	1,491,205
Net deferred tax liabilities	(412,252)	(781,988)
Valuation allowance on net operating loss carryforwards	$ 46,000	$ 47,000

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) $ in Thousands	Dec. 31, 2020USD ($)
Unrecognized tax benefits
Unrecognized tax benefits	$ 0
U.S Federal
Income Taxes
Net operating loss carryforward	2,300,000
State
Income Taxes
Net operating loss carryforward	$ 2,000,000

Commitments (Details)

Commitments (Details) $ in Thousands	Dec. 31, 2020USD ($)
Future minimum payments
2021	$ 1,749,876
2022	1,669,541
2023	1,699,357
2024	1,650,556
2025	1,526,486
Thereafter	8,619,800
Total	16,915,616
Firm transportation
Future minimum payments
2021	1,080,150
2022	1,037,503
2023	1,064,981
2024	1,024,833
2025	984,743
Thereafter	6,947,951
Total	12,140,161
Gas processing, gathering and compression
Future minimum payments
2021	54,873
2022	52,265
2023	59,140
2024	59,262
2025	47,960
Thereafter	113,379
Total	386,879
Land payment obligations
Future minimum payments
2021	2,859
2022	328
Total	3,187
Operating and Financing Leases
Future minimum payments
2021	265,849
2022	267,888
2023	300,971
2024	334,694
2025	306,918
Thereafter	1,138,489
Total	2,614,809
Imputed Interest for Leases
Future minimum payments
2021	346,145
2022	311,557
2023	274,265
2024	231,767
2025	186,865
Thereafter	419,981
Total	$ 1,770,580

Commitments - Contract terminat

Commitments - Contract termination and rig stacking (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Contract Termination and Rig Stacking
Contract termination and rig stacking	$ 14,290	$ 14,026

Contingencies (Details)

Contingencies (Details) $ in Millions	Jan. 31, 2021USD ($)	Jun. 20, 2019USD ($)	Dec. 31, 2019USD ($)	Jun. 30, 2019lawsuit	Mar. 31, 2017USD ($)
SJGC | Settled Litigation
Contingencies
Settlement amount received			$ 82
WGL
Contingencies
Damages awarded		$ 96
WGL | Pending Litigation
Contingencies
Number of lawsuits | lawsuit				2
Damages sought					$ 40
WGL | Judicial Ruling
Contingencies
Settlement amount received	$ 107

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Sales and revenues:
Sales and revenues - Third-party									$ 3,488,902	$ 4,400,102	$ 4,139,626
Sales and revenues - Intersegment									2,797	8,588
Sales and revenues	$ 1,309,092	$ 380,591	$ 484,911	$ 1,317,105	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	3,491,699	4,408,690	4,139,626
Operating expenses:
Impairment of oil and gas properties									223,770	1,300,444	549,437
Impairment of midstream assets										14,782	9,658
Depletion, depreciation, and amortization									861,870	914,867	972,465
General and administrative									134,482	178,696	240,344
Other									595,321	694,579	820,306
Total operating expenses	1,163,941	1,134,700	1,091,833	1,054,672	1,020,194	2,104,759	1,199,668	1,071,114	4,445,146	5,395,735	4,067,721
Operating income (loss)	145,151	$ (754,109)	$ (606,922)	$ 262,433	(67,456)	$ (985,878)	$ 99,996	$ (33,707)	(953,447)	(987,045)	71,905
Equity in net income (loss) of unconsolidated affiliates									(62,660)	(143,216)	40,280
Investment in unconsolidated affiliate	255,082				1,055,177				255,082	1,055,177
Segment assets	13,150,845				15,197,569				13,150,845	15,197,569	15,519,464
Capital expenditures for segment assets									874,357	1,422,155	2,210,586
Lease operating
Operating expenses:
Cost of goods and services sold									98,865	145,720	136,153
Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									2,530,838	2,146,647	1,339,358
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues - Third-party									3,178,330	4,107,845	3,565,300
Sales and revenues - Intersegment									2,797	5,812	(87,472)
Sales and revenues									3,181,127	4,113,657	3,477,828
Operating expenses:
Impairment of oil and gas properties									223,770	1,300,444	549,437
Depletion, depreciation, and amortization									861,870	893,161	841,645
General and administrative									134,482	160,402	181,305
Other									125,917	143,762	129,947
Total operating expenses									3,975,742	4,901,858	3,637,466
Operating income (loss)									(794,615)	(788,201)	(159,638)
Equity in net income (loss) of unconsolidated affiliates									(62,660)
Investment in unconsolidated affiliate	255,082								255,082
Segment assets	13,150,845				14,121,523				13,150,845	14,121,523	12,986,945
Capital expenditures for segment assets									874,357	1,369,003	1,923,488
Operating segments | Exploration and production | Lease operating
Operating expenses:
Cost of goods and services sold									98,865	146,990	142,234
Operating segments | Exploration and production | Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									2,530,838	2,257,099	1,792,898
Operating segments | Marketing
Sales and revenues:
Sales and revenues - Third-party									310,572	292,207	552,982
Sales and revenues									310,572	292,207	552,982
Operating expenses:
Other									469,404	549,814	686,055
Total operating expenses									469,404	549,814	686,055
Operating income (loss)									(158,832)	(257,607)	(133,073)
Segment assets					20,869					20,869	34,499
Operating segments | Antero Midstream Corporation
Sales and revenues:
Sales and revenues - Third-party										50	21,344
Sales and revenues - Intersegment									900,719	792,538	1,007,178
Sales and revenues									900,719	792,588	1,028,522
Operating expenses:
Impairment of midstream assets									673,640	776,832	9,658
Depletion, depreciation, and amortization									108,790	95,526	130,820
General and administrative									52,213	118,113	61,629
Other									18,328	12,093	(88,715)
Total operating expenses									1,018,357	1,205,953	425,646
Operating income (loss)									(117,638)	(413,365)	602,876
Equity in net income (loss) of unconsolidated affiliates									86,430	51,315	40,280
Investment in unconsolidated affiliate					709,639					709,639
Segment assets	5,610,912				6,282,878				5,610,912	6,282,878	3,542,862
Capital expenditures for segment assets									196,724	391,990	542,112
Operating segments | Antero Midstream Corporation | Lease operating
Operating expenses:
Cost of goods and services sold										162,376	262,704
Operating segments | Antero Midstream Corporation | Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									165,386	41,013	49,550
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues - Intersegment									(900,719)	(789,762)	(919,706)
Sales and revenues									(900,719)	(789,762)	(919,706)
Operating expenses:
Impairment of midstream assets									(673,640)	(762,050)
Depletion, depreciation, and amortization									(108,790)	(73,820)
General and administrative									(52,213)	(99,819)	(2,590)
Other									(18,328)	(11,090)	93,019
Total operating expenses									(1,018,357)	(1,261,890)	(681,446)
Operating income (loss)									117,638	472,128	(238,260)
Equity in net income (loss) of unconsolidated affiliates									(86,430)	(194,531)
Investment in unconsolidated affiliate					345,538					345,538
Segment assets	$ (5,610,912)				$ (5,227,701)				(5,610,912)	(5,227,701)	(1,044,842)
Capital expenditures for segment assets									(196,724)	(338,838)	(255,014)
Elimination of intersegment transaction | Lease operating
Operating expenses:
Cost of goods and services sold										(163,646)	(268,785)
Elimination of intersegment transaction | Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									$ (165,386)	$ (151,465)	$ (503,090)

Subsidiary Guarantors - Balance

Subsidiary Guarantors - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Accounts receivable, non-guarantor subsidiaries	$ 28,457	$ 46,419
Accounts receivable, related parties		125,000
Other current assets	15,238	10,731
Total current assets	574,139	922,885
Total assets	13,150,845	15,197,569	$ 15,519,464
Liabilities and Stockholders' Equity
Accounts payable, non-guarantor subsidiaries	26,728	14,498
Accounts payable, related parties	69,860	97,883
Other current liabilities	2,302	6,879
Total current liabilities	983,054	1,040,139
Total liabilities	7,060,574	$ 8,226,826
Noncontrolling interests	322,566
Parent (Antero)
Current assets:
Other current assets	543,841
Total current assets	543,841
Noncurrent assets	11,783,502
Total assets	12,327,343
Liabilities and Stockholders' Equity
Accounts payable, related parties	69,860
Other current liabilities	906,348
Total current liabilities	976,208
Noncurrent liabilities	6,070,388
Total liabilities	$ 7,046,596

Subsidiary Guarantors - Stateme

Subsidiary Guarantors - Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Condensed consolidated statement of operations and comprehensive income (loss)
Revenue									$ 3,394,477	$ 3,940,558	$ 4,133,139
Operating expenses	$ 1,163,941	$ 1,134,700	$ 1,091,833	$ 1,054,672	$ 1,020,194	$ 2,104,759	$ 1,199,668	$ 1,071,114	4,445,146	5,395,735	4,067,721
Loss from operations	145,151	(754,109)	(606,922)	262,433	(67,456)	(985,878)	99,996	(33,707)	(953,447)	(987,045)	71,905
Net income (loss) and comprehensive income (loss) including noncontrolling interests	95,313	(553,846)	(463,068)	(338,810)	(482,196)	(878,864)	42,168	1,025,756	(1,260,411)	(293,136)	(45,701)
Net income (loss) attributable to Antero Resources Corporation	$ 69,830	$ (535,613)	$ (463,304)	$ (338,810)	$ (482,196)	$ (878,864)	$ 42,168	$ 978,763	(1,267,897)	$ (340,129)	$ (397,517)
Parent (Antero)
Condensed consolidated statement of operations and comprehensive income (loss)
Revenue									3,458,390
Operating expenses									4,419,323
Loss from operations									(960,933)
Net income (loss) and comprehensive income (loss) including noncontrolling interests									(1,267,897)
Net income (loss) attributable to Antero Resources Corporation									$ (1,267,897)

Quarterly Financial Informati_3

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Selected Quarterly Financial Information [Abstract]
Total operating revenues	$ 1,309,092	$ 380,591	$ 484,911	$ 1,317,105	$ 952,738	$ 1,118,881	$ 1,299,664	$ 1,037,407	$ 3,491,699	$ 4,408,690	$ 4,139,626
Total operating expenses	1,163,941	1,134,700	1,091,833	1,054,672	1,020,194	2,104,759	1,199,668	1,071,114	4,445,146	5,395,735	4,067,721
Operating income (loss)	145,151	(754,109)	(606,922)	262,433	(67,456)	(985,878)	99,996	(33,707)	(953,447)	(987,045)	71,905
Gain on deconsolidation of Antero Midstream Partners LP								1,406,042		1,406,042
Net income (loss) and comprehensive income (loss) including noncontrolling interests	95,313	(553,846)	(463,068)	(338,810)	(482,196)	(878,864)	42,168	1,025,756	(1,260,411)	(293,136)	(45,701)
Net income (loss) attributable to noncontrolling interest	25,483	(18,233)	236					46,993	7,486	46,993	351,816
Net income (loss) attributable to Antero Resources Corporation	$ 69,830	$ (535,613)	$ (463,304)	$ (338,810)	$ (482,196)	$ (878,864)	$ 42,168	$ 978,763	$ (1,267,897)	$ (340,129)	$ (397,517)
Earnings (loss) per common share - basic:
Earnings (loss) per common share - basic	$ 0.26	$ (1.99)	$ (1.73)	$ (1.19)	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (4.65)	$ (1.11)	$ (1.26)
Earnings (loss) per share - diluted:
Earnings (loss) per common share - diluted	$ 0.24	$ (1.99)	$ (1.73)	$ (1.19)	$ (1.61)	$ (2.86)	$ 0.14	$ 3.17	$ (4.65)	$ (1.11)	$ (1.26)

Supplemental Information on O_3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 12,260,713	$ 11,859,817
Unproved properties	1,175,178	1,368,854
Total	13,435,891	13,228,671
Accumulated depletion and depreciation	(3,818,279)	(3,284,330)
Net capitalized costs	9,617,612	9,944,341
Costs Incurred in Certain Oil and Gas Activities
Unproved property	45,129	88,682	$ 172,387
Development costs	823,271	1,104,336	1,164,800
Exploration costs	2,993	149,782	323,773
Total costs incurred	871,393	1,342,800	1,660,960
Results of Operations for Oil and Gas Producing Activities
Revenues	3,083,905	3,643,873	3,652,894
Operating expenses:
Production expenses	2,736,478	2,417,509	1,601,985
Exploration expenses	1,083	884	4,958
Depletion and depreciation	854,331	884,350	832,326
Impairment of unproved properties	223,770	1,300,444	549,437
Results of operations before income tax (expense) benefit	(731,757)	(959,314)	664,188
Income tax (expense) benefit	(176,061)	224,511	(156,350)
Results of operations	$ (907,818)	$ (734,803)	$ 507,838

Supplemental Information on O_4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details)	12 Months Ended
	Dec. 31, 2020BcfeMMcfeBcfMMBbls	Dec. 31, 2019MMcfeBcfMMBbls	Dec. 31, 2018MMcfeMMBblsBcf
Proved developed and undeveloped reserves:
Balance at the beginning of the period | MMcfe	18,893,000	18,011,000	17,261,000
Revisions | MMcfe	(940,000)	(1,648,000)	(1,042,000)
Extensions, discoveries and other additions | MMcfe	1,105,000	3,705,000	2,781,000
Production | MMcfe	(1,310,000)	(1,175,000)	(989,000)
Sales | MMcfe	(113,000)
Balance at the end of the period | MMcfe	17,635,000	18,893,000	18,011,000
Oil and Gas Reserves
Proved developed reserves | MMcfe	11,873	11,740	10,389
Proved undeveloped reserves | MMcfe	5,762	7,153	7,622
VIE, Martica
Proved developed and undeveloped reserves:
Balance at the end of the period | MMcfe	254,000
Oil and Gas Reserves
Proved developed reserves | Bcf	181
Proved undeveloped reserves | Bcf	73
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	11,494	11,425	11,098
Revisions | Bcf	(1,280)	(1,735)	(1,087)
Extensions, discoveries and other additions | Bcf	799	2,626	2,125
Production | Bcf	(875)	(822)	(711)
Sales | Bcf	(113)
Balance at the end of the period | Bcf	10,025	11,494	11,425
Oil and Gas Reserves
Proved developed reserves | Bcf	6,901	7,229	6,669
Proved undeveloped reserves | Bcf	3,124	4,265	4,756
Natural gas | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the end of the period | Bcf	159
Oil and Gas Reserves
Proved developed reserves | Bcfe	110
Proved undeveloped reserves | Bcfe	49
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	1,191	1,052	989
Revisions	65	25	8
Extensions, discoveries and other additions	48	169	98
Production	(68)	(55)	(43)
Balance at the end of the period	1,236	1,191	1,052
Oil and Gas Reserves
Proved developed reserves	810	731	600
Proved undeveloped reserves	426	460	452
NGLS | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the end of the period	15
Oil and Gas Reserves
Proved developed reserves | MMcfe	11
Proved undeveloped reserves | MMcfe	4
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	42	46	38
Revisions	(8)	(11)	(1)
Extensions, discoveries and other additions	3	11	12
Production	(4)	(4)	(3)
Balance at the end of the period	33	42	46
Oil and Gas Reserves
Proved developed reserves	19	21	20
Proved undeveloped reserves	14	21	26
Oil and condensate | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the end of the period	0.5
Oil and Gas Reserves
Proved developed reserves | MMcfe	0.3
Proved undeveloped reserves | MMcfe	0.2

Supplemental Information on O_5

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes In Reserves (Details) - MMcfe MMcfe in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Extensions, discoveries and other additions	1,105	3,705	2,781
Revisions	(940)	(1,648)	(1,042)
Time period of the development plan	5 years	5 years	5 years
Increase (decrease) in proved reserves due to performance revisions			(433)
Increase (decrease) in proved reserves due to development plan revisions		(1,705)	(742)
Increase in proved reserves due to additions to development plan		595	1,722
Decrease in proved reserves due to reclassifications related to five-year rule	(922)	(2,300)	(2,464)
Increase in proved reserves due to improved well performance	491	63
Increase (decrease) in proved reserves resulting from price revisions	(1,126)	(157)	18
Increase (decrease) in proved reserves due to ethane recovery	485	315	115
Increase (decrease) in proved undeveloped properties reclassified from non-proved to proved undeveloped	132
IncreaseDecreaseInProvedReservesDueToDeconsolidationOfEquityMethod		(164)
Production	1,310	1,175	989
Sales of reserves	113

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, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and gas reserves
Future cash inflows computation period	12 months
Discount rate for annual net cash inflows (as a percent)	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	$ 37,845	$ 54,228	$ 64,199
Future production costs	(32,202)	(36,524)	(30,007)
Future development costs	(1,685)	(2,772)	(3,453)
Future net cash flows before income tax	3,958	14,932	30,739
Future income tax expense		(1,639)	(5,505)
Future net cash flows	3,958	13,293	25,234
10% annual discount for estimated timing of cash flows	(2,748)	(7,824)	(14,756)
Standardized measure of discounted future net cash flows	1,210	$ 5,469	$ 10,478	$ 8,627
VIE, Martica
Annual net cash inflows
Standardized measure of discounted future net cash flows	$ 359

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, 2020USD ($)$ / MMcfe	Dec. 31, 2019USD ($)$ / MMcfe	Dec. 31, 2018USD ($)$ / MMcfe
Reserve Quantities [Line Items]
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe	2.15	2.87	3.56
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs	$ (347)	$ (1,116)	$ (2,051)
Net changes in prices and production costs	(5,455)	(6,729)	707
Development costs incurred during the period	704	758	755
Net changes in future development costs	249	(92)	37
Extensions, discoveries and other additions	31	782	1,925
Divestitures	(174)
Revisions of previous quantity estimates	(379)	(1,011)	(53)
Accretion of discount	607	1,259	1,018
Net change in income taxes	598	1,513	(563)
Changes in timing and other	(93)	(373)	76
Net increase (decrease)	(4,259)	(5,009)	1,851
Beginning of year	5,469	10,478	8,627
End of year	1,210	5,469	$ 10,478
Increased production costs		3,300,000
Increased future development costs		$ 185,000
VIE, Martica
Changes in Standardized Measure of Discounted Future Net Cash Flow
End of year	$ 359