Antero Resources (AR) 10-K 16 Feb 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Feb. 11, 2022	Jun. 30, 2021
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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		314,706,678
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0001433270
Amendment Flag	false
Entity Public Float			$ 4.3
Auditor Name	KPMG LLP
Auditor Firm ID	185
Auditor Location	Denver

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Accounts receivable	$ 78,998	$ 28,457
Accrued revenue	591,442	425,314
Derivative instruments	757	105,130
Other current assets	14,922	15,238
Total current assets	686,119	574,139
Oil and gas properties, at cost (successful efforts method):
Unproved properties	1,042,118	1,175,178
Proved properties	12,646,303	12,260,713
Gathering systems and facilities	5,802	5,802
Other property and equipment	116,522	74,361
Property and equipment, gross	13,810,745	13,516,054
Less accumulated depletion, depreciation, and amortization	(4,283,700)	(3,869,116)
Property and equipment, net	9,527,045	9,646,938
Operating leases right-of-use assets	3,419,912	2,613,603
Derivative instruments	14,369	47,293
Investment in unconsolidated affiliate	232,399	255,082
Other assets	16,684	13,790
Total assets	13,896,528	13,150,845
Current liabilities:
Accounts payable	24,819	26,728
Accounts payable, related parties	76,240	69,860
Accrued liabilities	457,244	343,524
Revenue distributions payable	444,873	198,117
Derivative instruments	559,851	31,242
Short-term lease liabilities	456,347	266,024
Deferred revenue, VPP	37,603	45,257
Other current liabilities	11,140	2,302
Total current liabilities	2,068,117	983,054
Long-term liabilities:
Long-term debt	2,125,444	3,001,593
Deferred income tax liability	318,126	412,252
Derivative instruments	181,806	99,172
Long-term lease liabilities	2,964,115	2,348,785
Deferred revenue, VPP	118,366	156,024
Other liabilities	54,462	59,694
Total liabilities	7,830,436	7,060,574
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; 268,672 shares and 313,930 shares issued and outstanding as of December 31, 2020 and 2021, respectively	3,139	2,686
Additional paid-in capital	6,371,398	6,195,497
Accumulated deficit	(617,377)	(430,478)
Total stockholders' equity	5,757,160	5,767,705
Noncontrolling interests	308,932	322,566
Total equity	6,066,092	6,090,271
Total liabilities and equity	$ 13,896,528	$ 13,150,845

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Thousands	Dec. 31, 2021	Dec. 31, 2020
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	313,930	268,672
Common stock, shares outstanding	313,930	268,672

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Loss - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenue and other:
Revenue	$ 6,509,680	$ 3,394,477	$ 3,940,558
Commodity derivative fair value gains (losses)	(1,936,509)	79,918	463,972
Amortization of deferred revenue, VPP	45,236	14,507
Other income	1,025	2,797	4,160
Total revenue	4,619,432	3,491,699	4,408,690
Operating expenses:
Lease operating	96,793	98,865	145,720
Production and ad valorem taxes	197,910	106,775	125,142
General and administrative (including equity-based compensation expense of $23,559, $23,317 and $20,437 in 2019, 2020 and 2021, respectively)	145,006	134,482	178,696
Depletion, depreciation, and amortization	742,009	861,870	914,867
Impairment of oil and gas properties	90,523	223,770	1,300,444
Impairment of midstream assets			14,782
Accretion of asset retirement obligations	3,820	3,421	3,762
Contract termination and rig stacking	4,305	14,290	14,026
(Gain) loss on sale of assets	(2,232)	348	951
Total operating expenses	4,595,572	4,445,146	5,395,735
Operating income (loss)	23,860	(953,447)	(987,045)
Other income (expense):
Interest expense, net	(181,868)	(199,872)	(228,111)
Equity in earnings (loss) of unconsolidated affiliate	77,085	(62,660)	(143,216)
Gain (loss) on early extinguishment of debt	(93,191)	175,962	36,419
Loss on convertible note equitizations	(50,777)
Loss on the sale of equity method investment shares			(108,745)
Gain on deconsolidation of Antero Midstream Partners LP			1,406,042
Water earnout			125,000
Impairment of equity method investment		(610,632)	(467,590)
Transaction expense	(3,295)	(7,244)
Total other income (expense)	(252,046)	(704,446)	619,799
Loss before income taxes	(228,186)	(1,657,893)	(367,246)
Income tax benefit	74,077	397,482	74,110
Net loss and comprehensive loss including noncontrolling interests	(154,109)	(1,260,411)	(293,136)
Less: net income and comprehensive income attributable to noncontrolling interests	32,790	7,486	46,993
Net loss and comprehensive loss attributable to Antero Resources Corporation	$ (186,899)	$ (1,267,897)	$ (340,129)
Loss per share-basic (in dollars per share)	$ (0.61)	$ (4.65)	$ (1.11)
Loss per share-diluted (in dollars per share)	$ (0.61)	$ (4.65)	$ (1.11)
Weighted average number of shares outstanding:
Basic (in shares)	308,146	272,433	306,400
Diluted (in shares)	308,146	272,433	306,400
Natural gas sales
Revenue and other:
Revenue	$ 3,442,028	$ 1,809,952	$ 2,247,162
Natural gas liquids sales
Revenue and other:
Revenue	2,147,499	1,161,683	1,219,162
Oil sales
Revenue and other:
Revenue	201,232	112,270	177,549
Gathering, compression, water handling and treatment, processing, and transportation
Revenue and other:
Revenue			4,478
Operating expenses:
Cost of goods and services sold	2,499,174	2,530,838	2,146,647
Marketing.
Revenue and other:
Revenue	718,921	310,572	292,207
Operating expenses:
Cost of goods and services sold	811,698	469,404	549,814
Exploration
Operating expenses:
Cost of goods and services sold	$ 6,566	$ 1,083	$ 884

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Loss (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Consolidated Statements of Operations and Comprehensive Loss
Equity-based compensation expense	$ 20,437	$ 23,317	$ 23,559

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, 2018	$ 3,086	$ 6,485,174	$ 1,177,548	$ 821,669	$ 8,487,477
Balances (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)
Effect of deconsolidation of Antero Midstream Partners LP		(336,172)		(784,744)	(1,120,916)
Distributions to non-controlling interest				(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
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 interest				(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
Increase (Decrease) in Stockholders' Equity
Issuance of common shares	$ 430	363,813			364,243
Issuance of common shares (in shares)	42,976
Issuance of common units in Martica Holdings, LLC				51,000	51,000
Equity component of 2026 Convertible Notes, net		(195,056)			(195,056)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 23	(13,293)			(13,270)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	2,282
Distributions to non-controlling interest				(97,424)	(97,424)
Equity-based compensation		20,437			20,437
Net income (loss) and comprehensive income (loss)			(186,899)	32,790	(154,109)
Balance at Dec. 31, 2021	$ 3,139	$ 6,371,398	$ (617,377)	$ 308,932	$ 6,066,092
Balance (in shares) at Dec. 31, 2021	313,930

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash flows provided by (used in) operating activities:
Net loss including noncontrolling interests	$ (154,109)	$ (1,260,411)	$ (293,136)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	745,829	865,291	918,629
Impairments	90,523	834,402	1,782,816
Commodity derivative fair value losses (gains)	1,936,509	(79,918)	(463,972)
Gains (losses) on settled commodity derivatives	(1,183,400)	794,684	325,090
Proceeds from (payments for) derivative monetizations	(4,569)	9,007
Deferred income tax benefit	(74,293)	(397,273)	(79,158)
Equity-based compensation expense	20,437	23,317	23,559
Equity in (earnings) loss of unconsolidated affiliate	(77,085)	62,660	143,216
Distributions/dividends of earnings from unconsolidated affiliate	136,609	171,022	157,956
Amortization of deferred revenue	(45,236)	(14,507)
Amortization of debt issuance costs, debt discount, debt premium and other	12,492	12,027	10,681
(Gain) loss on sale of assets	(2,232)	348	951
Loss on the sale of equity method investment shares			108,745
Water earnout			(125,000)
Gain on deconsolidation of Antero Midstream Partners LP			(1,406,042)
(Gain) loss on early extinguishment of debt	93,191	(175,962)	(36,419)
Loss on convertible note equitizations	50,777
Changes in current assets and liabilities:
Accounts receivable	(55,567)	(9,492)	31,631
Accrued revenue	(166,128)	(107,428)	156,941
Other current assets	316	(5,507)	(1,025)
Accounts payable including related parties	(1,184)	(19,282)	(27,996)
Accrued liabilities	77,584	37,954	(25,762)
Revenue distributions payable	246,757	(5,203)	(102,839)
Other current liabilities	12,895	(89)	4,592
Net cash provided by operating activities	1,660,116	735,640	1,103,458
Cash flows provided by (used in) investing activities:
Additions to unproved properties	(79,138)	(45,129)	(88,682)
Drilling and completion costs	(601,175)	(826,265)	(1,254,118)
Additions to water handling and treatment systems			(24,416)
Additions to gathering systems and facilities			(48,239)
Additions to other property and equipment	(35,623)	(2,963)	(6,700)
Settlement of water earnout		125,000
Investments in unconsolidated affiliates			(25,020)
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	3,192	701	1,983
Proceeds from VPP sale, net		215,789
Change in other liabilities	(672)
Change in other assets	2,632	2,806	7,091
Net cash used in investing activities	(710,784)	(530,061)	(1,041,490)
Cash flows provided by (used in) financing activities:
Repurchases of common stock		(43,443)	(38,772)
Issuance of senior notes	1,800,000		650,000
Issuance of convertible notes		287,500
Repayment of senior notes	(1,554,657)	(1,219,019)	(191,092)
Borrowings (repayments) on bank credit facilities, net	(1,017,000)	465,000	232,000
Payment of debt issuance costs	(31,474)	(8,984)	(4,547)
Sale of noncontrolling interest	51,000	351,000
Distributions to noncontrolling interests	(97,424)	(35,920)	(85,076)
Employee tax withholding for settlement of equity compensation awards	(13,270)	(422)	(2,389)
Convertible note equitizations	(85,648)
Other	(859)	(1,291)	(2,560)
Net cash provided by (used in) financing activities	(949,332)	(205,579)	557,564
Effect of deconsolidation of Antero Midstream Partners LP			(619,532)
Net increase in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	141,930	192,302	224,331
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$ 37,049	$ (94,619)	$ (15,897)

Organization

Organization	12 Months Ended
	Dec. 31, 2021
Organization
Organization	(1) Organization Antero Resources Corporation (individually referred to as “Antero” and together with its consolidated subsidiaries “Antero Resources,” or the “Company”) is 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 is located in Denver, Colorado.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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, 2020 and 2021, and its results of operations and cash flows for the years ended December 31, 2019, 2020 and 2021. 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 its variable interest entity (“VIE”), Martica Holdings LLC (“Martica”), for which the Company is the primary beneficiary. All 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 Simplification Transactions resulted in the exchange of the limited partner interest Antero Resources owned in Antero Midstream Partners for common stock of Antero Midstream Corporation (“Antero Midstream”) 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 that provides significant influence, but not control, over Antero Midstream. 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, 2020 and 2021, the Company had a interest, respectively, in Antero Midstream. 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 Simplification Transactions, respectively. For the years ended December 31, 2020 and 2021, the Company determined that 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. 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 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, 2021, 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, 2020 and 2021. The sale of a partial interest in a proved property is accounted for as a normal retirement, 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 cost recovery 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, 2020 and 2021. The Company did not record any impairment expenses associated with its proved properties in the Marcellus Shale during the years ended December 31, 2019, 2020 and 2021. As of December 31, 2021, 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 was $15 million for the year ended December 31, 2019, which was associated with midstream assets. There were no such impairments for the years ended December 31, 2020 and 2021. (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, 2019, 2020 and 2021, 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 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, 2021, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. The amortization and write-off related to deferred debt issuance costs was (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, 2020 and 2021, 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 on the Company’s consolidated statements of operations. 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 on the Company’s consolidated statements of operations. (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 FASB 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 Simplification 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, 2019, 2020 and 2021 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Six One Commodities LLC (1) ​ 15 % ​ 11 % ​ 10 % ​ Sabine Pass Liquefaction LLC ​ 16 % ​ 11 % ​ * ​ ​ (1) Six One Commodities LLC acquired WGL Midstream during the year ended December 31, 2021. WGL Midstream was the Company's major customer during the years ended December 31, 2019 and 2020. * Sabine Pass Liquefaction LLC was not a major customer during the year ended December 31, 2021. 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. As of December 31, 2021, the Company did not have any commodity derivative assets with bank counterparties under our Credit Facility (as defined below in Note 8—Long-Term Debt). 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, 2021 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 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) Reportable Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through the Company’s equity method investment in Antero Midstream. 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 due to its significance to the Company’s operations. See Note 3—Deconsolidation of Antero Midstream Partners LP and Note 18—Reportable Segments to the consolidated financial statements for further discussion on the Simplification 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 common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from outstanding equity awards and shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 8—Long-Term Debt). The Company includes restricted stock unit (“RSU”) awards, performance share unit (“PSU”) awards and stock options in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the a

Deconsolidation of Antero Midst

Deconsolidation of Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2021
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, dated as of October 9, 2018, by and among Antero Midstream GP LP, Antero Midstream Partners and certain of their affiliates (the “Simplification Agreement”), pursuant to which (i) Antero Midstream GP LP was converted from a limited 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 “ Simplification 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 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 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 continued to be included in the Company’s consolidated statement of operations and comprehensive income (loss) through March 12, 2019. ​

Transactions

Transactions	12 Months Ended
	Dec. 31, 2021
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 thresholds related to the third quarter of 2020 and the first quarter of 2021 as of September 30, 2020 and March 31, 2021, respectively. The Company received a $51 million cash distribution during each of the years ended December 31, 2020 and 2021. 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 or (b) the earlier of (i) April 1, 2023 or (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 as of the transaction closing. 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) 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, for the Company’s 2021 through 2024 drilling program . Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by Antero Resources during such tranche year. For 2021 and 2022, Antero Resources and QL agreed to the estimated internal rate of return (“IRR”) of the Company’s capital budget for each annual tranche, and QL agreed to participate in the 2021 and 2022 tranches. For each subsequent year through 2024, Antero Resources will propose a capital budget and estimated IRR for all wells to be spud during such year, and subject to the mutual agreement of the parties that the estimated IRR for the year exceeds a specified return, QL will be obligated to participate in such tranche. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche in which QL participates, Antero Resources and QL will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion. Under the terms of the arrangement, QL funded 20% of development capital for wells spud in 2021, is expected to fund 15% in 2022 and between 15% and 20% of development capital spending for wells spud on an annual basis from 2023 through 2024, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, Antero Resources may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later December 1 following the end of each tranche year . 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. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. 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 annual tranches. The Company has accounted for the drilling partnership as a conveyance under ASC 932 and such conveyances are recorded in the consolidated financial statements as QL obtains its proportionate working interest in each well.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2021
Revenue
Revenue	(5 ) Revenue ​ (a) Disaggregation of Revenue ​ The table set forth below presents revenue disaggregated by type and reportable segment to which it relates (in thousands). See Note 18—Reportable Segments to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2019 2020 2021 Reportable Segment ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,247,162 ​ ​ 1,809,952 ​ ​ 3,442,028 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 124,563 ​ ​ 113,811 ​ ​ 206,889 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 1,094,599 ​ ​ 1,047,872 ​ ​ 1,940,610 ​ Exploration and production ​ Oil sales ​ ​ 177,549 ​ ​ 112,270 ​ ​ 201,232 ​ Exploration and production ​ Marketing ​ ​ 292,207 ​ ​ 310,572 ​ ​ 718,921 ​ Marketing ​ Gathering and compression (1) ​ ​ 3,972 ​ ​ — ​ ​ — ​ Equity method investment in Antero Midstream ​ Water handling and treatment (1) ​ ​ 506 ​ ​ — ​ ​ — ​ Equity method investment in Antero Midstream ​ Total revenue from contracts with customers ​ ​ 3,940,558 ​ ​ 3,394,477 ​ ​ 6,509,680 ​ ​ ​ Income (loss) from derivatives, deferred revenue and other sources, net ​ ​ 468,132 ​ ​ 97,222 ​ ​ (1,890,248) ​ ​ ​ Total revenue ​ $ 4,408,690 ​ ​ 3,491,699 ​ ​ 4,619,432 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3—Deconsolidation of Antero Midstream Partners to the consolidated financial statements for further discussion on the Simplification 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, Revenue from Contracts with Customers 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 or less. (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, 2020 and 2021, the Company’s receivables from contracts with customers were

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2021
Equity Method Investments.
Equity Method Investments	(6) Equity Method Investment ​ (a) Summary of Equity Method Investment ​ As of December 31, 2021, Antero owned approximately 29.1% of Antero Midstream’s common stock, which is reflected in Antero’s consolidated financial statements using the equity method of accounting. ​ The following table sets forth a reconciliation of Antero’s investment in unconsolidated affiliate (in thousands): ​ ​ ​ ​ ​ ​ Balances as of December 31, 2019 ​ $ 1,055,177 ​ Equity in loss of unconsolidated affiliate ​ ​ (62,660) ​ Dividends from unconsolidated affiliate ​ ​ (171,022) ​ Impairment (1) ​ ​ (610,632) ​ Elimination of intercompany profit ​ ​ 44,219 ​ Balance as of December 31, 2020 (2) ​ ​ 255,082 ​ Equity in earnings of unconsolidated affiliate ​ ​ 77,085 ​ Dividends from unconsolidated affiliate ​ ​ (136,609) ​ Elimination of intercompany profit ​ ​ 36,841 ​ Balance as of December 31, 2021 (2) ​ $ 232,399 ​ (1) Other-than-temporary impairment of the Company’s investment in Antero Midstream to reduce the carrying value of such investment to fair value, which was based on the quoted market share price of Antero Midstream as of March 31, 2020 (Level 1). (2) The fair value of the Company’s investment in Antero Midstream as of December 31, 2020 and 2021 was $1.1 billion and $1.3 billion, respectively, based on the quoted market share price of Antero Midstream. ​ (b) Summarized Financial Information of Antero Midstream ​ The tables set forth below present summarized financial information of Antero Midstream (in thousands). ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Current assets ​ $ 93,931 ​ ​ 83,804 ​ Noncurrent assets ​ ​ 5,516,981 ​ ​ 5,460,197 ​ Total assets ​ $ 5,610,912 ​ ​ 5,544,001 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 94,005 ​ ​ 114,009 ​ Noncurrent liabilities ​ ​ 3,098,621 ​ ​ 3,143,294 ​ Stockholders' equity ​ ​ 2,418,286 ​ ​ 2,286,698 ​ Total liabilities and stockholders' equity ​ $ 5,610,912 ​ ​ 5,544,001 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2020 2021 ​ Revenues ​ $ 900,719 ​ ​ 898,202 ​ Operating expenses ​ ​ 1,018,357 ​ ​ 342,875 ​ Income (loss) from operations ​ ​ (117,638) ​ ​ 555,327 ​ Net income (loss) ​ $ (122,527) ​ ​ 331,617 ​ ​

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2021
Accrued Liabilities
Accrued Liabilities	(7) Accrued Liabilities Accrued liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Capital expenditures ​ $ 32,372 ​ 46,983 ​ Gathering, compression, processing, and transportation expenses ​ ​ 152,724 ​ ​ 164,900 ​ Marketing expenses ​ ​ 68,193 ​ ​ 50,589 ​ Interest expense, net ​ 25,645 ​ 65,093 ​ Accrued production and ad valorem taxes ​ ​ 37,371 ​ ​ 44,298 ​ Derivative settlements payable ​ ​ 3,425 ​ ​ 35,202 ​ Accrued general and administrative expense ​ ​ 14,363 ​ ​ 27,740 ​ Other ​ 9,431 ​ 22,439 ​ Total accrued liabilities ​ $ 343,524 ​ 457,244 ​ ​

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2021
Long-Term Debt
Long-Term Debt	(8) Long-Term Debt Long-term debt consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Credit Facility (a) ​ $ 1,017,000 ​ ​ — ​ 5.125% senior notes due 2022 (b) ​ ​ 660,516 ​ ​ — ​ 5.625% senior notes due 2023 (c) ​ ​ 574,182 ​ ​ — ​ 5.00% senior notes due 2025 (d) ​ ​ 590,000 ​ ​ 584,635 ​ 8.375% senior notes due 2026 (e) ​ ​ — ​ ​ 325,000 ​ 7.625% senior notes due 2029 (f) ​ ​ — ​ ​ 584,000 ​ 5.375% senior notes due 2030 (g) ​ ​ — ​ ​ 600,000 ​ 4.25% convertible senior notes due 2026 (h) ​ ​ 287,500 ​ ​ 81,570 ​ Total principal ​ ​ 3,129,198 ​ ​ 2,175,205 ​ Unamortized discount, net ​ ​ (111,886) ​ ​ (27,772) ​ Unamortized debt issuance costs ​ ​ (15,719) ​ ​ (21,989) ​ Long-term debt ​ $ 3,001,593 ​ ​ 2,125,444 ​ ​ (a) Senior Secured Revolving Credit Facility Antero Resources has a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2021, Antero Resources entered into an amended and restated senior secured revolving credit facility, the New Credit Facility. 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. As of December 31, 2021, the borrowing base under the New Credit Facility was $3.5 billion and lender commitments were $1.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2022. . The Credit Facility contains requirements with respect to leverage and current ratios, and certain covenants, including restrictions on our ability to incur debt and limitations on our ability to pay dividends unless certain customary conditions are met, in each case, subject to customary carve-outs and exceptions. The Prior Credit Facility provides for borrowing under either an Alternate Base Rate or as a Eurodollar Loan (as each term is defined in the Prior Credit Facility), and the New Credit Facility provides for borrowing at either an Adjusted Term Secured Overnight Financing Rate (“SOFR”), an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the New Credit Facility). The Credit Facility provides for interest only payments until maturity at which time all outstanding borrowings are due. Interest is payable at a variable rate based on (i) LIBOR or the Alternate Base Rate, determined by Antero Resources’ election at the time of borrowing, plus an applicable margin rate under the Prior Credit Facility and (ii) SOFR or the Alternate Base Rate, determined by Antero Resources’ election at the time of borrowing, plus an applicable margin rate under the New Credit Facility. Interest at the time of borrowing is determined with reference to the Antero Resources’ then-current leverage ratio subject to certain exceptions. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) with respect to the New Credit Facility, determined with reference to borrowing base utilization, both rates subject to certain exceptions based on the leverage ratio then in effect. The New Credit Facility includes fall away covenants, lower interest rates and reduced collateral requirements that Antero Resources may elect if Antero Resources is assigned an Investment Grade Rating (as defined in the New Credit Facility). As of December 31, 2021, Antero Resources had no borrowings under the New Credit Facility and outstanding letters of credit of $531 million. 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. (b) 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 Company repurchased or otherwise fully redeemed all of the 2022 Notes between 2019 and the first quarter of 2021. Interest on the 2022 Notes was payable on June 1 and December 1 of each year. (c) 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 . (d) 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 . million principal amount of the 2025 Notes remained outstanding. 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’ existing subsidiaries that guarantee the Credit Facility 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 at redemption prices ranging from on or after March 1, 2023, which option the Company exercised on January 27, 2022 with its notice to redeem all remaining 2025 Notes on March 1, 2022. 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 (e) 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 Company redeemed $175 million of the 2026 Notes on July 1, 2021, and as of December 31, 2021, $325 amount of the 2026 Notes remained outstanding. See “—Debt Repurchase Program” below for further details on the 2026 Notes redemption. 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’ existing subsidiaries that guarantee the Credit Facility 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. 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 (f) 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 Company redeemed $116 million of the 2029 Notes on November 2, 2021, and as of December 31, 2021, $584 million principal amount of the 2029 Notes remained outstanding. See “—Debt Repurchase Program” below for further details on the 2029 Notes redemption. 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’ existing subsidiaries that guarantee the Credit Facility 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 million aggregate principal amount of outstanding 2029 Notes. 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 (g) 5.375% Senior Notes Due 2030 On June 1, 2021, Antero Resources issued $600 million of 5.375% senior notes due March 1, 2030 (the “2030 Notes”) at par. The 2030 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2030 Notes rank pari passu to Antero Resources’ other outstanding senior notes. The 2030 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Resources’ existing subsidiaries that guarantee the Credit Facility and certain of its future restricted subsidiaries. Interest on the 2030 Notes is payable on March 1 and September 1 of each year. Antero Resources may redeem all or part of the 2030 Notes at any time on or after March 1, 2025 at redemption prices ranging from on or after March 1, 2028. In addition, on or before March 1, 2025, Antero Resources may redeem up to of the principal amount of the 2030 Notes, plus accrued and unpaid interest. At any time prior to March 1, 2025, Antero Resources may also redeem the 2030 Notes, in whole or in part, at a price equal to of the principal amount of the 2030 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 2030 Notes will have the right to require Antero Resources to repurchase all or a portion of the notes at a price equal to (g) 4.25% Convertible Senior Notes Due 2026 On August 21, 2020, Antero Resources issued $250 million in aggregate principal amount of 4.25% convertible senior notes due September 1, 2026 (the “2026 Convertible Notes”). On September 2, 2020, Antero Resources issued an additional million of the 2026 Convertible Notes. 2026 Convertible Notes, and as of December 31, 2021, $82 million principal amount of the 2026 Convertible Notes remained outstanding. 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, 2021, the if-converted value of the 2026 Convertible Notes was $329 million, which exceeded the principal amount of the 2026 Convertible Notes by $247 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 (the “Stock Price Condition”) ; ● 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. The 2026 Convertible Notes have met the Stock Price Condition allowing holders of the 2026 Convertible Notes to exercise their conversion right as of December 31, 2021. 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. Partial Equitizations of 2026 Convertible Notes On January 12, 2021, the Company completed a registered direct offering (the “January 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 January 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 “January Convertible Note Repurchase,” and, collectively with the January Share Offering, the “January 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 January Equitization Transactions had the effect of increasing this conversion rate to 275.3525 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $39 million loss on convertible note equitization in the consolidated statements of operations and comprehensive loss for the year ended December 31, 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the January Equitization Transactions resulted in a loss on early extinguishment of debt of $41 million in the consolidated statement of operations and comprehensive loss for the year ended December 31, 2021. On May 13, 2021, the Company completed a registered direct offering (the “May Share Offering”) of an aggregate of 11.6 million shares of its common stock at a price of $11.01 per share to certain holders of the 2026 Convertible Notes. The Company used the proceeds from the May Share Offering and approximately $26 million of borrowings under the Credit Facility to repurchase from such holders $56 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “May Convertible Note Repurchase,” and, collectively with the May Share Offering, the “May 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 May Equitization Transactions had the effect of increasing this conversion rate to 245.2802 shares of common stock per $1,000 principal amount. The Company accounted for this transaction as an inducement of the 2026 Convertible Notes, and as a result, the Company recorded a $12 million loss on convertible note equitization in the consolidated statements of operations and comprehensive loss for the year ended December 31, 2021 for the consideration paid in excess of the original terms of the 2026 Convertible Notes. Additionally, the May Equitization Transactions resulted in a loss on early extinguishment of debt of $21 million in the consolidated statement of operations and comprehensive loss for the year ended December 31, 2021. The 2026 Convertible Notes consist of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ Liability component: ​ ​ ​ ​ ​ ​ ​ Principal ​ $ 287,500 ​ ​ 81,570 ​ Less: unamortized note discount ​ ​ (112,265) ​ ​ (27,772) ​ Less: unamortized debt issuance costs ​ ​ (5,852) ​ ​ (1,592) ​ Net carrying value ​ $ 169,383 ​ ​ 52,206 ​ Equity component (1) ​ $ 115,601 ​ ​ 32,799 ​ (1) As of December 31, 2020, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital, net of $3 million of issuance costs and $28 million of deferred taxes. As of December 31, 2021, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital net of $1 million of issuance costs and $8 million of deferred taxes. Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate, amortization of the debt discount and debt issuance costs totaled $8 million and $11 million for the years ended December 31, 2020 and 2021, respectively. (f) Debt Repurchase Program 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%. During the first quarter of 2021, the Company redeemed the remaining $661 million of the 2022 Notes at par, plus accrued and unpaid interest, and as a result, the 2022 Notes were fully retired as of February 10, 2021. The Company redeemed the remaining million of the 2023 Notes at par, plus accrued and unpaid interest, during the second quarter of 2021. The 2023 Notes were fully retired as of June 1, 2021. During the third quarter of 2021, the Company redeemed million. During the fourth quarter of 2021, the Company redeemed (g) Subsequent Event On January 27, 2022, Antero Resources announced that it will redeem all $585 million in aggregate principal amount of its 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest on March 1, 2022. Immediately following the redemption, the 2025 Notes will be fully retired. The

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligations
Asset Retirement Obligations	(9) Asset Retirement Obligations ​ The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ Beginning balance $ 54,845 ​ 54,452 ​ Obligations incurred ​ 1,814 ​ ​ 3,208 ​ Accretion expense ​ ​ 3,421 ​ ​ 3,820 ​ Settlement of obligations ​ ​ (229) ​ ​ (40) ​ Revisions to prior estimates ​ ​ (5,399) ​ ​ (7,488) ​ Ending balance ​ $ 54,452 ​ ​ 53,952 ​ ​ Revisions to prior estimates in 2020 and 2021 are primarily due to an increase in estimated well lives. Asset retirement obligations are included in other liabilities on the Company’s consolidated balance sheets.

Equity-Based Compensation and C

Equity-Based Compensation and Cash Awards	12 Months Ended
	Dec. 31, 2021
Equity-Based Compensation and Cash Awards
Equity-Based Compensation and Cash Awards	(10) Equity-Based Compensation and Cash 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 7,922,468 shares were available for future grant under the 2020 Plan as of December 31, 2021. 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 Simplification Transactions, each outstanding phantom unit award under the AMP Plan, was assumed by Antero Midstream and converted into 1.8926 RSUs (all such RSUs, the “Converted AM RSU Awards”) under the Antero Midstream Corporation Long Term Incentive Plan (the “AM Plan”). Each RSU award under the AM Plan represents a right to receive one share of Antero Midstream common stock. The Company’s equity-based compensation expense, by type of award, is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 ​ RSU awards ​ $ 10,343 ​ ​ 12,510 ​ ​ 13,232 ​ PSU awards ​ ​ 8,069 ​ ​ 7,219 ​ ​ 4,662 ​ Converted AM RSU Awards (1) ​ ​ 3,425 ​ ​ 2,519 ​ ​ 1,160 ​ Stock options ​ ​ 355 ​ ​ — ​ ​ — ​ Equity awards issued to directors ​ ​ 1,367 ​ ​ 1,069 ​ ​ 1,383 ​ Total expense ​ $ 23,559 ​ ​ 23,317 ​ ​ 20,437 ​ (1) Antero Resources recognized compensation expense for equity awards granted under both the 2013 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 Simplification 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 to the consolidated financial statements for further discussion on the Simplification 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 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number of ​ Grant Date ​ ​ Shares Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 8,432,397 ​ $ 4.06 ​ Granted ​ 1,447,806 ​ ​ 9.63 ​ Vested ​ (3,622,741) ​ ​ 4.37 ​ Forfeited ​ (326,855) ​ ​ 5.45 ​ Total awarded and unvested—December 31, 2021 ​ 5,930,607 ​ $ 5.15 ​ ​ As of December 31, 2021, there was approximately $24 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of approximately 2.5 years. (b) 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 were based on stock price targets. The vesting of these PSUs was 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 could vest before the first anniversary of the grant date; no more than one-third of the PSUs could vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs could vest before the third anniversary of the grant date. Any PSUs that had not vested by the fifth anniversary of the grant date expired in 2021. Expense related to these PSUs was recognized on a graded basis over three years . Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. One of the performance conditions was met, and vesting for one-third of these PSUs was achieved. Performance Share Unit Awards Based on Total Shareholder Return and Return on Capital Employed In 2018, the Company granted PSUs to certain of its employees and executive officers, a portion of which would vest based on the Company’s absolute total shareholder return (“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 were 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 could ultimately be earned with respect to the 2018 TSR PSUs ranged from zero to 200 % of the target number of 2018 TSR PSUs originally granted. Expense related to the 2018 TSR PSUs was recognized on a straight-line basis over three years . Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. The other portion of the PSUs granted in 2018 would vest based on the Company’s actual return on capital employed (“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 could ultimately be earned with respect to the ROCE PSUs ranged from zero to 200 % of the target number of ROCE PSUs originally granted. Expense related to the ROCE PSUs was recognized based on the number of shares of common stock that were expected to be issued at the end of the measurement period, and was reversed if the likelihood of achieving the performance condition decreased. 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 was not recognized during the years ended December 31, 2020 and 2021. The performance conditions for the 2018 TSR PSUs and ROCE PSUs were not met, and no vesting for these awards was achieved. Performance Share Unit Awards Based on Total Shareholder Return In 2016 and 2017, the Company granted PSUs to certain of its employees and executive officers that would 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 that were available to be earned ranged from zero to 200% of the PSUs granted. Expense related to these PSUs was recognized on a straight-line basis over three years . Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. The performance conditions for the 2016 and 2017 PSUs were not met, and no vesting was achieved. 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. The performance condition for the performance period ending April 15, 2021 was met, and 150% vesting was achieved for the award tranche. 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. the performance period ending April 15, 2021 was met, and 150% vesting was achieved for the award tranche. In 2021, 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, 2022, April 15, 2023, and April 15, 2024, and one cumulative three-year performance period ending on April 15, 2024, in each case, subject to the executive officer’s continued employment through April 15, 2024. The number of shares of common stock that may ultimately be earned following the end of the cumulative three-year performance period with respect to the TSR PSUs ranges from zero to 200% of the target number of TSR PSUs originally granted. Expense related to these PSUs is recognized on a graded-vested basis over the term of each performance period. 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 Leverage Ratio In April 2021, the Company granted PSUs to certain of its executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX ( ) determined as of the last day of each of three one-year performance periods ending on December 31, 2021, December 31, 2022, and December 31, 2023, in each case, subject to the executive officer’s continued employment through December 31, 2023 (“Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned with respect to the Leverage Ratio PSUs ranges from zero to 200% of the target number of Leverage Ratio PSUs originally granted. Expense related to the Leverage Ratio PSUs is recognized based on the number of shares of common stock that are expected to be issued at the end of each measurement period, and such expense is reversed if the likelihood of achieving the performance condition becomes improbable. As of December 31, 2021, the likelihood of achieving the performance conditions related to the Leverage Ratio PSUs was probable. Summary Information for Performance Share Unit Awards A summary of PSU activity is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ Number of ​ Average Grant ​ ​ Units Date Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 2,547,798 ​ $ 12.66 ​ Granted ​ 479,120 ​ ​ 9.71 ​ Forfeited ​ (67,000) ​ ​ 2.97 ​ Cancelled (unearned) ​ (1,112,639) ​ ​ 19.19 ​ Total awarded and unvested—December 31, 2021 ​ 1,847,279 ​ $ 8.31 ​ ​ 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 and Adjusted EBITDAX-based PSUs was based on the closing price of Antero Resources’ common stock on the date of the grant, assuming target achievement of the performance condition. The following table presents information regarding the weighted average fair values for market-based PSUs, and the assumptions used to determine the fair values: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ ​ Dividend yield ​ ​ — % ​ — % ​ — % ​ Volatility ​ ​ 36 % ​ 80 % ​ 85 % ​ Risk-free interest rate ​ ​ 2.35 % ​ 0.17 % ​ 0.32 % ​ Weighted average fair value of awards granted—Absolute TSR ​ $ 9.26 ​ ​ 2.63 ​ ​ 11.99 ​ ​ Weighted average fair value of awards granted—Relative TSR ​ $ — ​ ​ 3.30 ​ ​ — ​ ​ ​ As of December 31, 2021, there was $6 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 1.9 years. (c) Converted AM Restricted Share 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 Simplification Transactions, the Board of Directors of Antero Midstream adopted the AM Plan. In accordance with the terms of the Simplification Transactions, each outstanding phantom unit under the AMP Plan was assumed by Antero Midstream and converted into 1.8926 restricted stock units under the AM Plan. A summary of the Converted AM RSU Awards is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number of ​ Grant Date ​ ​ Units Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 296,390 ​ $ 15.06 ​ Granted ​ — ​ ​ — ​ Vested ​ (209,964) ​ ​ 15.73 ​ Forfeited ​ (4,719) ​ ​ 13.25 ​ Total awarded and unvested—December 31, 2021 ​ 81,707 ​ $ 13.46 ​ ​ As of December 31, 2021, there was $0.4 million of unamortized equity-based compensation expense related to unvested Converted AM RSU Awards. That expense is expected to be recognized over a weighted average period of approximately 0.3 years, and the Company’s proportionate share will be allocated to it as it is recognized (d) 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 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ Average ​ ​ ​ ​ ​ ​ ​ Average ​ Remaining ​ Intrinsic ​ ​ ​ Stock ​ Exercise ​ Contractual ​ Value ​ ​ Options Price Life (in thousands) ​ Outstanding—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Granted ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Forfeited ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Expired ​ (80,667) ​ ​ 50.00 ​ ​ ​ ​ ​ ​ Outstanding—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​ Vested—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​ Exercisable—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​ ​ 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. (e) Cash Awards In January 2020, the Company granted cash awards of approximately $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 $3 million to certain non-executive employees under the 2020 Plan that vest ratably over four years . As of December 31, 2020 and 2021, the Company has recorded approximately $3 million and $2 million, respectively, in Other liabilities in the consolidated balance sheets related to unvested cash awards.

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2021
Fair Value
Fair Value	(11) Fair Value The carrying values of accounts receivable and accounts payable as of December 31, 2020 and 2021 approximated market values because of their short- term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2020 and 2021 approximated fair value because the variable interest rates are reflective of current market conditions. The following table sets forth the fair value and carrying value of the senior notes and 2026 Convertible Notes (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 2022 Notes ​ $ 658,468 ​ ​ 658,400 ​ ​ — ​ ​ — ​ 2023 Notes ​ ​ 562,698 ​ ​ 571,370 ​ ​ — ​ ​ — ​ 2025 Notes ​ ​ 560,500 ​ ​ 585,440 ​ ​ 594,866 ​ ​ 581,117 ​ 2026 Notes ​ ​ — ​ ​ — ​ ​ 370,013 ​ ​ 321,738 ​ 2029 Notes ​ ​ — ​ ​ — ​ ​ 654,080 ​ ​ 577,149 ​ 2030 Notes ​ ​ — ​ ​ — ​ ​ 641,400 ​ ​ 593,234 ​ 2026 Convertible Notes ​ ​ 430,963 ​ ​ 169,383 ​ ​ 331,655 ​ ​ 52,206 ​ Total ​ $ 2,212,629 ​ ​ 1,984,593 ​ ​ 2,592,014 ​ ​ 2,125,444 ​ (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. 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, 2021
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, 2019, 2020 and 2021. 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 NYMEX index price and a local index price. 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, 2021, the Company’s fixed price swap positions excluding Martica, the Company’s consolidated VIE were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ ​ In addition, the Company has a swaption agreement, which entitles the counterparty 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, 2021, 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 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, 2021, the Company’s fixed price swap positions for Martica, the Company’s consolidated VIE, were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Henry Hub ​ 38,356 MMBtu/day ​ $ 2.39 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 35,616 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ethane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-March 2022 ​ Mont Belvieu Purity Ethane-OPIS ​ 521 Bbl/day ​ $ 6.68 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Propane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Mont Belvieu Propane-OPIS Non-TET ​ 934 Bbl/day ​ $ 19.20 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gasoline ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 282 Bbl/day ​ $ 34.37 /Bbl ​ January-December 2023 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 247 Bbl/day ​ ​ 40.74 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ West Texas Intermediate ​ 112 Bbl/day ​ $ 43.51 /Bbl ​ January-December 2023 ​ West Texas Intermediate ​ 99 Bbl/day ​ ​ 44.88 /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 88,748,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.55 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) Summary The table below presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets (in thousands). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ December 31, ​ December 31, ​ ​ Location 2020 ​ 2021 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current ​ Derivative instruments ​ $ 97,144 ​ ​ — ​ Embedded derivatives—current ​ Derivative instruments ​ ​ 7,986 ​ ​ 757 ​ Commodity derivatives—noncurrent ​ Derivative instruments ​ ​ 14,689 ​ ​ — ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ 32,604 ​ ​ 14,369 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives (1) ​ ​ ​ ​ 152,423 ​ ​ 15,126 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (2) ​ Derivative instruments ​ ​ 31,242 ​ ​ 559,851 ​ Commodity derivatives—noncurrent (2) ​ Derivative instruments ​ ​ 99,172 ​ ​ 181,806 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives (1) ​ ​ ​ ​ 130,414 ​ ​ 741,657 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives asset (liability) (1) ​ ​ ​ $ 22,009 ​ ​ (726,531) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs. (2) 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. As of December 31, 2021, approximately $55 million of commodity derivative liabilities, including $31 million of current commodity derivatives and $24 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica The following table sets forth 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, 2020 ​ December 31, 2021 ​ ​ ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ Gross ​ Gross ​ Assets ​ Gross ​ Gross ​ Assets ​ ​ ​ Amounts ​ Amounts Offset ​ (Liabilities) on ​ Amounts ​ Amounts Offset ​ (Liabilities) on ​ ​ Recognized Recognized Balance Sheet Recognized Recognized Balance Sheet Commodity derivative assets ​ $ 181,375 ​ ​ (69,542) ​ ​ 111,833 ​ ​ 2,177 ​ ​ (2,177) ​ ​ — ​ Embedded derivative assets ​ $ 40,590 ​ ​ — ​ ​ 40,590 ​ ​ 15,126 ​ ​ — ​ ​ 15,126 ​ Commodity derivative liabilities ​ $ (199,956) ​ ​ 69,542 ​ ​ (130,414) ​ ​ (743,834) ​ ​ 2,177 ​ ​ (741,657) ​ ​ The following table sets forth a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location 2019 ​ 2020 2021 ​ Commodity derivative fair value gains (losses) (1) ​ Revenue ​ $ 463,972 ​ ​ 40,565 ​ ​ (1,886,551) ​ Embedded derivative fair value gains (losses) (1) ​ Revenue ​ $ — ​ ​ 39,353 ​ ​ (49,958) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs . Commodity derivative fair value gains (losses) for the years ended December 31, 2020 and 2021, include a gain of $9 million and a loss of $5 million, respectively, related to certain natural gas derivatives that were monetized prior to their contractual settlement dates. Proceeds received from and payments for the monetizations are classified as operating cash flows on the Company’s consolidated statement of cash flows for the years ended December 31, 2020 and 2021. There were no commodity derivatives monetizations in the year ended December 31, 2019.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases
Leases	(13) Leases The Company leases certain office space, processing plants, drilling rigs and completion services, gas gathering lines, compressor stations, and other office and field equipment. Leases with an initial term of 12 months or less are considered short-term and are not recorded on the balance sheet. Instead, the short-term leases are recognized in expense on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms that can extend the lease from one or more. The exercise of the lease renewal options is at the Company’s sole discretion. The depreciable lives of the leased assets are limited by the expected lease term, unless there are 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 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. (a) Supplemental Balance Sheet Information Related to Leases The Company’s lease assets and liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ Leases Balance Sheet Classification 2020 2021 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,302,290 ​ ​ 1,739,550 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 29,894 ​ ​ 9,860 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,241,090 ​ ​ 1,634,928 ​ Office space ​ Operating lease right-of-use assets ​ ​ 36,879 ​ ​ 33,083 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 2,704 ​ ​ 2,009 ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 746 ​ ​ 482 ​ Total operating lease right-of-use assets ​ ​ ​ $ 2,613,603 ​ ​ 3,419,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease obligation ​ Short-term lease liabilities ​ $ 265,178 ​ ​ 455,950 ​ Long-term operating lease obligation ​ Long-term lease liabilities ​ ​ 2,348,425 ​ ​ 2,963,962 ​ Total operating lease obligation ​ ​ ​ $ 2,613,603 ​ ​ 3,419,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 1,206 ​ ​ 550 ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 1,206 ​ ​ 550 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease obligation ​ Short-term lease liabilities ​ $ 845 ​ ​ 397 ​ Long-term finance lease obligation ​ Long-term lease liabilities ​ ​ 361 ​ ​ 153 ​ Total finance lease obligation ​ ​ ​ $ 1,206 ​ ​ 550 ​ (1) Gas gathering lines and compressor stations leases includes $ 1.1 billion and $1.5 billion related to Antero Midstream as of December 31, 2020 and 2021 , respectively. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $3 million and $2 million as of December 31, 2020 and 2021 , respectively. ​ The processing plants, gathering lines and compressor stations that are classified as lease liabilities are classified as such under ASC 842, Leases ​ (b) Supplemental Information Related to Leases ​ Costs associated with operating and finance leases were included in the consolidated statement of operations and comprehensive loss (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, Cost Classification Location 2019 2020 2021 Operating lease cost ​ Statement of operations ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ ​ 1,498,221 ​ ​ 1,518,305 Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 11,228 ​ ​ 11,530 ​ ​ 10,901 Operating lease cost ​ Statement of operations ​ Contract termination and rig stacking ​ ​ 10,692 ​ ​ 8,528 ​ ​ 4,213 Operating lease cost ​ Statement of operations ​ Lease operating ​ ​ — ​ ​ — ​ ​ 142 Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 194,522 ​ ​ 104,146 ​ ​ 103,741 Total operating lease cost ​ ​ ​ ​ ​ $ 1,058,882 ​ ​ 1,622,425 ​ ​ 1,637,302 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation, and amortization ​ $ 1,471 ​ ​ 872 ​ ​ 522 Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 335 ​ ​ 208 ​ ​ — Total finance lease cost ​ ​ ​ ​ ​ $ 1,806 ​ ​ 1,080 ​ ​ 522 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 162,654 ​ ​ 122,577 ​ ​ 86,039 (1) Capitalized costs related to drilling and completion activities. ​ (c) Supplemental Cash Flow Information Related to Leases The following is the Company’s supplemental cash flow information related to leases (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases ​ $ 809,667 ​ ​ 1,576,984 ​ ​ 1,352,941 ​ Operating cash flows from finance leases ​ ​ 335 ​ ​ 208 ​ ​ — ​ Investing cash flows from operating leases ​ ​ 178,898 ​ ​ 106,867 ​ ​ 88,910 ​ Financing cash flows from finance leases ​ ​ 2,507 ​ ​ 1,291 ​ ​ 859 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease obligations ​ $ 3,720,945 ​ ​ 202,125 ​ ​ 437,045 ​ Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net (1) ​ $ (681,686) ​ ​ (173,563) ​ ​ 702,512 ​ (1) During the year ended December 31, 2019, the weighted average discount rate for remeasured operating leases increased from 6.0% as of January 1, 2019 to 12.4% as of December 31, 2019 . During the year ended December 31, 2020 , the weighted average discount rate for remeasured operating leases increased from 10.0% as of December 31, 2019 to 14.4% as of December 31, 2020 . During the year ended December 31, 2021 , the weighted average discount rate for remeasured operating leases decreased from 14.4% as of December 31, 2020 to 5.0% as of December 31, 2021. (d) Maturities of Lease Liabilities The table below is a schedule of future minimum payments for operating and financing lease liabilities as of December 31, 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2022 ​ $ 634,632 ​ ​ 424 ​ ​ 635,056 ​ 2023 ​ ​ 622,266 ​ ​ 76 ​ ​ 622,342 ​ 2024 ​ ​ 612,344 ​ ​ 67 ​ ​ 612,411 ​ 2025 ​ ​ 540,291 ​ ​ 22 ​ ​ 540,313 ​ 2026 ​ ​ 489,589 ​ ​ — ​ ​ 489,589 ​ Thereafter ​ ​ 1,386,882 ​ ​ — ​ ​ 1,386,882 ​ Total lease payments ​ ​ 4,286,004 ​ ​ 589 ​ ​ 4,286,593 ​ Less: imputed interest ​ ​ (866,092) ​ ​ (39) ​ ​ (866,131) ​ Total ​ $ 3,419,912 ​ ​ 550 ​ ​ 3,420,462 ​ ​ (e) Lease Term and Discount Rate ​ The following table sets forth the Company’s weighted-average remaining lease term and discount rate: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2020 ​ December 31, 2021 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ Operating Leases ​ Finance Leases ​ ​ Weighted average remaining lease term ​ 8.0 years ​ 1.5 years ​ 7.6 years ​ 1.9 years ​ ​ Weighted average discount rate ​ 13.7 % 6.2 % 5.5 % 5.6 % ​ ​ (f) Related Party Lease Disclosure ​ The Company has a gathering and compression agreement with Antero Midstream, whereby Antero Midstream 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 annual adjustments based on the consumer price index. If and to the extent the Company requests that Antero Midstream construct new high pressure lines and compressor stations, the gathering and compression agreement contains options at Antero Midstream’s election for either (i) minimum volume commitments that require Antero Resources to utilize or pay for ​ In December 2019, the Company and Antero Midstream 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 on or before the 180 th day prior to the anniversary of such effective date. The Company achieved the volumetric targets during each quarter for the year ended December 31, 2020, and earned rebates of $48 million. The Company achieved the volumetric target during the fourth quarter of 2021, and earned a rebate of $12 million. ​ For the years ended December 31, 2019, 2020 and 2021, gathering and compression fees paid by Antero related to this agreement were $643 million, $679 million and $705 million, respectively. As of

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Taxes
Income Taxes	(14) Income Taxes ​ The Company’s income tax benefit consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 Current income tax expense (benefit) ​ $ 5,048 ​ ​ (209) ​ ​ 216 ​ Deferred income tax benefit ​ (79,158) ​ (397,273) ​ (74,293) ​ Total income tax benefit ​ $ (74,110) ​ ​ (397,482) ​ ​ (74,077) ​ ​ 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 income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 Federal income tax expense (benefit) ​ $ (77,122) ​ ​ (348,158) ​ ​ (47,919) ​ State income tax expense (benefit), net of federal benefit ​ (8,826) ​ (50,584) ​ (6,576) ​ Change in state tax rate, net of federal effect ​ ​ 24,041 ​ ​ 2,291 ​ ​ (30,910) ​ Nondeductible equity-based compensation ​ 6,920 ​ 4,490 ​ 1,117 ​ Dividends received deduction ​ ​ (4,201) ​ ​ (4,013) ​ ​ (3,832) ​ Noncontrolling interest ​ ​ (10,998) ​ ​ (1,801) ​ ​ (7,862) ​ Deconsolidation adjustment ​ ​ (6,626) ​ ​ — ​ ​ — ​ Change in valuation allowance ​ 1,325 ​ 789 ​ 4,606 ​ Nondeductible loss on 2026 Convertible Notes equitization ​ ​ — ​ ​ — ​ ​ 12,174 ​ Other ​ 1,377 ​ (496) ​ 5,125 ​ Total income tax benefit ​ $ (74,110) ​ ​ (397,482) ​ ​ (74,077) ​ ​ 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 is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 565,433 ​ ​ 569,523 ​ Equity-based compensation ​ ​ 8,445 ​ ​ 2,462 ​ Investment in Antero Midstream ​ ​ 330,301 ​ ​ 297,893 ​ Unrealized losses on derivative instruments ​ ​ — ​ ​ 158,779 ​ Asset retirement obligations and other ​ ​ 17,206 ​ ​ 15,051 ​ Total deferred tax assets ​ ​ 921,385 ​ ​ 1,043,708 ​ Valuation allowance ​ ​ (46,013) ​ ​ (50,304) ​ Net deferred tax assets ​ ​ 875,372 ​ ​ 993,404 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 13,189 ​ ​ — ​ Oil and gas properties ​ ​ 1,188,599 ​ ​ 1,254,182 ​ Investment in Martica ​ ​ 59,586 ​ ​ 51,166 ​ 2026 Convertible Notes and other ​ ​ 26,250 ​ ​ 6,182 ​ Total deferred tax liabilities ​ ​ 1,287,624 ​ ​ 1,311,530 ​ Net deferred tax liabilities ​ $ (412,252) ​ ​ (318,126) ​ ​ 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 $46 million and 31, 2020 and 2021, respectively. The valuation allowance as of December 31, 2020 and 2021, relates to Colorado, Oklahoma and West Virginia 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 2022. The Company has no unrecognized tax benefit balances through December 31, 2021. As of December 31, 2021, 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 2041. For tax years 2018 and thereafter, NOL carryforwards generated in these jurisdictions have no expiration date. The Pennsylvania NOL carryforwards expire between 2024 and 2041. Tax years 2018 through 2021 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 2017 through 2021.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2021
Commitments
Commitments	(15) Commitments ​ The following table sets forth 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 a lease term in excess of one year as of December 31, 2021 (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 2022 ​ $ 1,042,280 ​ ​ 52,265 ​ ​ 1,361 ​ ​ 456,345 ​ ​ 178,711 ​ ​ 1,730,962 ​ 2023 ​ ​ 1,072,523 ​ ​ 59,140 ​ ​ — ​ ​ 466,960 ​ ​ 155,382 ​ ​ 1,754,005 ​ 2024 ​ ​ 1,045,442 ​ ​ 59,262 ​ ​ — ​ ​ 481,688 ​ ​ 130,723 ​ ​ 1,717,115 ​ 2025 ​ ​ 1,024,783 ​ ​ 47,960 ​ ​ — ​ ​ 433,507 ​ ​ 106,806 ​ ​ 1,613,056 ​ 2026 ​ ​ 1,018,812 ​ ​ 14,783 ​ ​ — ​ ​ 404,381 ​ ​ 85,208 ​ ​ 1,523,184 ​ Thereafter ​ ​ 6,033,138 ​ ​ 98,596 ​ ​ — ​ ​ 1,177,581 ​ ​ 209,301 ​ ​ 7,518,616 ​ Total ​ $ 11,236,978 ​ ​ 332,006 ​ ​ 1,361 ​ ​ 3,420,462 ​ ​ 866,131 ​ ​ 15,856,938 ​ ​ (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 loss. There are no remaining payment obligations related to these delayed or cancelled drilling and completion contracts as of December 31, 2021.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2021
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 the 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 the 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 the EPA 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, including, but not limited to, royalty claims. 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, 2021
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 as an equity method investment. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for more discussion on the Simplification Transactions. ​ Substantially all of Antero Midstream Partners’ and Antero Midstream’s revenues were and are derived from transactions with Antero Resources. See Note 18—Reportable Segments to the consolidated financial statements for the operating results of the Company’s reportable segments. ​

Reportable Segments

Reportable Segments	12 Months Ended
	Dec. 31, 2021
Segment Information
Reportable Segments	(18) Reportable Segments See Note 2(t)—Summary of Significant Accounting Policies—Reportable 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 Simplification 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 Simplification 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 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation (1) Affiliates Total ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,107,845 ​ ​ 292,207 ​ ​ 50 ​ ​ — ​ ​ 4,400,102 ​ Intersegment ​ 5,812 ​ ​ — ​ ​ 792,538 ​ ​ (789,762) ​ ​ 8,588 ​ Total revenue ​ ​ 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 ​ General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 118,113 ​ ​ (99,819) ​ ​ 178,696 ​ Depletion, depreciation, and amortization ​ ​ 893,161 ​ ​ — ​ ​ 95,526 ​ ​ (73,820) ​ ​ 914,867 ​ Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 776,832 ​ ​ (762,050) ​ ​ 14,782 ​ Other ​ ​ 143,762 ​ ​ 549,814 ​ ​ 12,093 ​ ​ (11,090) ​ ​ 694,579 ​ Total operating expenses ​ ​ 4,901,858 ​ ​ 549,814 ​ ​ 1,205,953 ​ ​ (1,261,890) ​ ​ 5,395,735 ​ Operating loss ​ $ (788,201) ​ ​ (257,607) ​ ​ (413,365) ​ ​ 472,128 ​ ​ (987,045) ​ Equity in earnings 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 effective March 13, 2019. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,178,330 ​ ​ 310,572 ​ ​ — ​ ​ — ​ ​ 3,488,902 ​ Intersegment ​ 2,797 ​ ​ — ​ ​ 900,719 ​ ​ (900,719) ​ ​ 2,797 ​ Total revenue ​ ​ 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 ​ General and administrative ​ ​ 134,482 ​ ​ — ​ ​ 52,213 ​ ​ (52,213) ​ ​ 134,482 ​ Depletion, depreciation, and amortization ​ ​ 861,870 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 861,870 ​ Impairment of oil and gas properties ​ ​ 223,770 ​ ​ — ​ ​ — ​ ​ — ​ ​ 223,770 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 673,640 ​ ​ (673,640) ​ ​ — ​ Other ​ ​ 125,917 ​ ​ 469,404 ​ ​ 18,328 ​ ​ (18,328) ​ ​ 595,321 ​ Total operating expenses ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2021 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,899,486 ​ ​ 718,921 ​ ​ — ​ ​ — ​ ​ 4,618,407 ​ Intersegment ​ 1,025 ​ ​ — ​ ​ 898,202 ​ ​ (898,202) ​ ​ 1,025 ​ Total revenue ​ ​ 3,900,511 ​ ​ 718,921 ​ ​ 898,202 ​ ​ (898,202) ​ ​ 4,619,432 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 96,793 ​ ​ — ​ ​ — ​ ​ — ​ ​ 96,793 ​ Gathering, compression, processing, and transportation ​ ​ 2,499,174 ​ ​ — ​ ​ 157,120 ​ ​ (157,120) ​ ​ 2,499,174 ​ General and administrative ​ ​ 145,006 ​ ​ — ​ ​ 63,838 ​ ​ (63,838) ​ ​ 145,006 ​ Depletion, depreciation, and amortization ​ ​ 742,009 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 742,009 ​ Impairment of oil and gas properties ​ ​ 90,523 ​ ​ — ​ ​ — ​ ​ — ​ ​ 90,523 ​ Other ​ ​ 210,369 ​ ​ 811,698 ​ ​ 13,127 ​ ​ (13,127) ​ ​ 1,022,067 ​ Total operating expenses ​ ​ 3,783,874 ​ ​ 811,698 ​ ​ 342,875 ​ ​ (342,875) ​ ​ 4,595,572 ​ Operating income (loss) ​ $ 116,637 ​ ​ (92,777) ​ ​ 555,327 ​ ​ (555,327) ​ ​ 23,860 ​ Equity in earnings of unconsolidated affiliates ​ $ 77,085 ​ ​ — ​ ​ 90,451 ​ ​ (90,451) ​ ​ 77,085 ​ Investments in unconsolidated affiliates ​ $ 232,399 ​ ​ — ​ ​ 696,009 ​ ​ (696,009) ​ ​ 232,399 ​ Segment assets ​ $ 13,864,402 ​ ​ 32,126 ​ ​ 5,544,001 ​ ​ (5,544,001) ​ ​ 13,896,528 ​ Capital expenditures for segment assets ​ $ 715,936 ​ ​ — ​ ​ 232,825 ​ ​ (232,825) ​ ​ 715,936 ​ ​

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2021
Subsidiary Guarantors
Subsidiary Guarantors	(19) Subsidiary Guarantors Antero Resources’ senior notes are fully and unconditionally guaranteed by Antero Resources’ existing subsidiaries that guarantee the Credit Facility. 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 tables set forth below present summarized financial information of Antero, as parent, and its guarantor subsidiaries (in thousands). The Company’s wholly owned subsidiaries are not restricted from making distributions to the Company. ​ ​ ​ ​ ​ ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ Accounts receivable, non-guarantor subsidiaries ​ $ — ​ Accounts receivable, related parties ​ ​ — ​ Other current assets ​ ​ 633,014 ​ Total current assets ​ ​ 633,014 ​ Noncurrent assets ​ ​ 12,480,350 ​ Total assets ​ $ 13,113,364 ​ ​ ​ ​ ​ ​ Accounts payable, non-guarantor subsidiaries ​ $ — ​ Accounts payable, related parties ​ ​ 76,240 ​ Other current liabilities ​ ​ 1,961,041 ​ Total current liabilities ​ ​ 2,037,281 ​ Noncurrent liabilities ​ ​ 5,737,999 ​ Total liabilities ​ $ 7,775,280 ​ ​ ​ ​ ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, 2021 ​ Revenues ​ $ 4,545,912 ​ Operating expenses ​ ​ 4,561,383 ​ Loss from operations ​ ​ (15,471) ​ Net loss and comprehensive loss including noncontrolling interests ​ ​ (186,899) ​ Net loss and comprehensive loss attributable to Antero Resources Corporation ​ $ (186,899) ​ ​

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2021
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	(20) Supplemental Information on Oil and Gas Producing Activities (Unaudited) The following tables set forth supplemental information regarding the Company’s consolidated oil and gas producing activities (in thousands). 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, ​ ​ 2020 ​ 2021 ​ Proved properties ​ $ 12,260,713 ​ ​ 12,646,303 ​ Unproved properties ​ 1,175,178 ​ 1,042,118 ​ Total oil and gas properties ​ 13,435,891 ​ 13,688,421 ​ Accumulated depletion ​ (3,818,279) ​ (4,229,300) ​ Net capitalized costs ​ $ 9,617,612 ​ ​ 9,459,121 ​ ​ (b) Costs Incurred in Certain Oil and Gas Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ — ​ ​ — ​ ​ — ​ Unproved property ​ 88,682 ​ ​ 45,129 ​ ​ 79,138 ​ Development costs ​ 1,104,336 ​ ​ 823,271 ​ ​ 581,352 ​ Exploration costs ​ 149,782 ​ ​ 2,993 ​ ​ 19,822 ​ Total costs incurred ​ $ 1,342,800 ​ ​ 871,393 ​ ​ 680,312 ​ ​ (c) Results of Operations for Oil and Gas Producing Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 ​ 2020 ​ 2021 ​ Revenues ​ $ 3,643,873 ​ ​ 3,083,905 ​ ​ 5,790,759 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 2,417,509 ​ ​ 2,736,478 ​ ​ 2,793,877 ​ Exploration expenses ​ 884 ​ ​ 1,083 ​ ​ 1,164 ​ Depletion ​ 884,350 ​ ​ 854,331 ​ ​ 735,687 ​ Impairment of unproved properties ​ 1,300,444 ​ ​ 223,770 ​ ​ 90,523 ​ Results of operations before income tax (expense) benefit ​ (959,314) ​ ​ (731,757) ​ ​ 2,169,508 ​ Income tax (expense) benefit ​ 224,511 ​ ​ (176,061) ​ ​ 520,168 ​ Results of operations ​ $ (734,803) ​ ​ (907,818) ​ ​ 2,689,676 ​ ​ (d) Oil and Gas Reserves Net proved oil and gas reserves for the years ended December 31, 2019, 2020 and 2021 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. The tables below set forth the changes in quantities of proved reserves and net quantities of proved developed and proved undeveloped reserves for the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved 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) ​ 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) ​ December 31, 2020 (1) ​ 10,025 ​ 1,236 ​ 33 ​ 17,635 ​ Revisions ​ 993 ​ 77 ​ 6 ​ 1,486 ​ Extensions, discoveries and other additions ​ 349 ​ 18 ​ 2 ​ 472 ​ Production ​ (826) ​ (58) ​ (4) ​ (1,194) ​ Sales ​ (337) ​ (54) ​ (1) ​ (670) ​ December 31, 2021 (1) ​ 10,204 ​ 1,219 ​ 36 ​ 17,729 ​ (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. Proved reserves for the noncontrolling interest in Martica as of December 31, 2021 were 167 Bcfe, which consists of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ December 31, 2020 (1) ​ 6,901 ​ 810 ​ 19 ​ 11,873 ​ December 31, 2021 (1) ​ 7,395 ​ 876 ​ 17 ​ 12,753 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​ December 31, 2020 (2) ​ 3,124 ​ 426 ​ 14 ​ 5,762 ​ December 31, 2021 (2) ​ 2,809 ​ 343 ​ 19 ​ 4,976 ​ (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. Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2021 were 133 Bcfe, which consists of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 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. Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2021 were 34 Bcfe, which consists of 23 Bcf of natural gas, 2 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Significant changes in proved reserves for the years ended December 31, 2019, 2020 and 2021 include the following: Year Ended December 31, 2019 Proved Reserve Changes ● 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. Year Ended December 31, 2020 Proved Reserve Changes ● 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. Year Ended December 31, 2021 Proved Reserve Changes ● Extensions, discoveries, and other additions of 472 Bcfe resulted from delineation and development drilling in the Appalachian Basin. ● Net upward revisions of 1,486 Bcfe include: ● Upward revisions of 149 Bcfe due to increases in prices for natural gas, NGLs and oil. ● Upward revisions of 121 Bcfe are due to an increase in the Company’s assumed future ethane recovery. ● Net upward performance revisions of 565 Bcfe. ● Net upward revision of 651 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 1,475 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 824 Bcfe for locations that were not developed within five years of initial booking as proved reserves. ● Sales of reserves of 670 Bcfe related to the drilling partnership. (e) Standardized Measure of Discounted Future Net Cash Flow The standardized measure relating to proved oil and reserves was prepared in accordance with the provisions of ASC 932. 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. The following table sets forth the Standardized Measure of the discounted future net cash flows attributable to the Company’s proved reserves (in millions): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 Future cash inflows ​ $ 54,228 ​ ​ 37,845 ​ ​ 74,622 ​ Future production costs ​ (36,524) ​ ​ (32,202) ​ ​ (34,665) ​ Future development costs ​ (2,772) ​ ​ (1,685) ​ ​ (1,704) ​ Future net cash flows before income tax ​ 14,932 ​ ​ 3,958 ​ ​ 38,253 ​ Future income tax expense (1) ​ (1,639) ​ ​ — ​ ​ (7,813) ​ Future net cash flows ​ 13,293 ​ ​ 3,958 ​ ​ 30,440 ​ 10% annual discount for estimated timing of cash flows ​ (7,824) ​ ​ (2,748) ​ ​ (17,007) ​ Standardized measure of discounted future net cash flows (2) ​ $ 5,469 ​ ​ 1,210 ​ ​ 13,433 ​ (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 was expected to be less than its NOL carryforward deductions and therefore, under the standardized measure, there was 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 and $501 million for the years ended December 31, 2020 and 2021, respectively. The Company used the following 12-month weighted average prices to estimate its total equivalent reserves (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ 12-month weighted average price ​ $ 2.87 ​ ​ 2.15 ​ ​ 4.21 ​ ​ (f) Changes in Standardized Measure of Discounted Future Net Cash Flow ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Sales of oil and gas, net of productions costs ​ $ (1,116) ​ ​ (347) ​ ​ (2,917) ​ Net changes in prices and production costs (1) ​ (6,729) ​ ​ (5,455) ​ ​ 14,099 ​ Development costs incurred during the period ​ 758 ​ ​ 704 ​ ​ 454 ​ Net changes in future development costs (2) ​ (92) ​ ​ 249 ​ ​ (117) ​ Extensions, discoveries and other additions ​ 782 ​ ​ 31 ​ ​ 504 ​ Divestitures ​ ​ — ​ ​ (174) ​ ​ (125) ​ Revisions of previous quantity estimates ​ (1,011) ​ ​ (379) ​ ​ 2,543 ​ Accretion of discount ​ 1,259 ​ ​ 607 ​ ​ 121 ​ Net change in income taxes ​ 1,513 ​ ​ 598 ​ ​ (3,115) ​ Changes in timing and other ​ (373) ​ ​ (93) ​ ​ 776 ​ Net increase (decrease) ​ (5,009) ​ ​ (4,259) ​ ​ 12,223 ​ Beginning of year ​ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ End of year (3) ​ $ 5,469 ​ ​ 1,210 ​ ​ 13,433 ​ (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 for the noncontrolling interest in Martica was $359 million and $501 million for the years ended December 31, 2020 and 2021, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Basis of Presentation	(a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2020 and 2021, and its results of operations and cash flows for the years ended December 31, 2019, 2020 and 2021. 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.
Principles of Consolidation	(b) Principles of Consolidation The accompanying consolidated financial statements include the accounts of Antero Resources Corporation, its wholly owned subsidiaries, any entities in which the Company owns a controlling interest and its variable interest entity (“VIE”), Martica Holdings LLC (“Martica”), for which the Company is the primary beneficiary. All 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 Simplification Transactions resulted in the exchange of the limited partner interest Antero Resources owned in Antero Midstream Partners for common stock of Antero Midstream Corporation (“Antero Midstream”) 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 that provides significant influence, but not control, over Antero Midstream. 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, 2020 and 2021, the Company had a interest, respectively, in Antero Midstream. 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 Simplification Transactions, respectively. For the years ended December 31, 2020 and 2021, the Company determined that 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. 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 and the amount of underlying equity in the net assets of Antero Midstream Partners as of the date of deconsolidation. The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under this approach, distributions received from equity method investees are classified on the basis of the nature of the activity or activities of the investee that generated the distribution as either a return on investment (classified as cash inflows from operating activities) or a return of investment (classified as cash inflows from investing activities).
Use of Estimates	(c) Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect revenues, expenses, assets, 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.
Risks and Uncertainties	(d) Risks and Uncertainties The markets for natural gas, NGLs and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of 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.
Cash and Cash Equivalents	(e) Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable and revenue distributions payable within its consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its consolidated statements of cash flows. As of December 31, 2020, the book overdraft included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2021, the book overdraft included within accounts payable and revenue distributions payable were
Oil and Gas Properties	(f) Oil and Gas Properties The Company accounts for its natural gas, NGLs and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells-in- progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. 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, 2020 and 2021. The sale of a partial interest in a proved property is accounted for as a normal retirement, 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 cost recovery 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, 2020 and 2021. The Company did not record any impairment expenses associated with its proved properties in the Marcellus Shale during the years ended December 31, 2019, 2020 and 2021. As of December 31, 2021, 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
Impairment of Long Lived Assets Other than Oil and Gas Properties	(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 was $15 million for the year ended December 31, 2019, which was associated with midstream assets. There were no such impairments for the years ended December 31, 2020 and 2021.
Other Property and Equipment	(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, 2019, 2020 and 2021, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment.
Debt Issuance costs	(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 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, 2021, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. The amortization and write-off related to deferred debt issuance costs was
Derivative Financial Instruments	(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.
Asset Retirement Obligations	(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.
Environmental Liabilities	(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, 2020 and 2021, 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.
Revenue	(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 FASB 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.
Gathering, Compression, Water Handling and Treatment Revenue	(p) Gathering, Compression, Water Handling and Treatment Revenue Substantially all revenues from the gathering, compression, water handling and treatment operations were derived from transactions for services Antero Midstream Partners provided to 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 Simplification 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.
Concentrations of Credit Risk	(q) Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry. The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables. The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2019, 2020 and 2021 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Six One Commodities LLC (1) ​ 15 % ​ 11 % ​ 10 % ​ Sabine Pass Liquefaction LLC ​ 16 % ​ 11 % ​ * ​ ​ (1) Six One Commodities LLC acquired WGL Midstream during the year ended December 31, 2021. WGL Midstream was the Company's major customer during the years ended December 31, 2019 and 2020. * Sabine Pass Liquefaction LLC was not a major customer during the year ended December 31, 2021. 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. As of December 31, 2021, the Company did not have any commodity derivative assets with bank counterparties under our Credit Facility (as defined below in Note 8—Long-Term Debt). 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, 2021 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	(r) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss (“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.
Fair Value Measurements	(s) Fair Value Measurements The 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.
Reportable Segments and Geographic Information	(t) Reportable Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through the Company’s equity method investment in Antero Midstream. 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 due to its significance to the Company’s operations. See Note 3—Deconsolidation of Antero Midstream Partners LP and Note 18—Reportable Segments to the consolidated financial statements for further discussion on the Simplification 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.
Earnings (loss) Per Common Share	(u) Earnings (Loss) Per Common Share Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from outstanding equity awards and shares of common stock issuable upon conversion of the 2026 Convertible Notes (as defined below in Note 8—Long-Term Debt). The Company includes restricted stock unit (“RSU”) awards, performance share unit (“PSU”) awards and stock options in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. The potential dilutive effect of the 2026 Convertible Notes is calculated using the (i) treasury stock method for the year ended December 31, 2020 as a result of the Company’s intent to settle the principal amount of such convertible notes in cash upon conversion during year ended December 31, 2020, and (ii) if-converted method for the year ended December 31, 2021, as a result of the partial equitizations of the 2026 Convertible Notes during the year ended December 31, 2021. See Note 8—Long-Term Debt for further discussion on the equitization transactions. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effects of all equity awards and the 2026 Convertible Notes are anti-dilutive. The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 ​ Basic weighted average number of shares outstanding ​ 306,400 ​ 272,433 ​ 308,146 ​ Add: Dilutive effect of RSUs ​ — ​ — ​ — ​ Add: Dilutive effect of PSUs ​ — ​ — ​ — ​ Add: Dilutive effect of outstanding stock options ​ — ​ — ​ — ​ Add: Dilutive effect of 2026 Convertible Notes ​ — ​ — ​ — ​ Diluted weighted average number of shares outstanding ​ 306,400 ​ 272,433 ​ 308,146 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 2,357 ​ 6,810 ​ 6,407 ​ PSUs ​ 1,443 ​ 432 ​ 2,832 ​ Outstanding stock options ​ 527 ​ 327 ​ 379 ​ 2026 Convertible Notes (2) ​ — ​ 31,388 ​ 18,778 ​ (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—diluted because the inclusion of these awards would have been anti-dilutive. (2) Under the treasury stock method, only the amount by which the conversion value exceeds the aggregate principal amount of the 2026 Convertible Notes is considered in the diluted earnings per share computation. As of December 31, 2020, the conversion value did not exceed the principal amount of the notes. On January 12, 2021, the Company completed the January 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.
Treasury Share Retirement	(v) Treasury Share Retirement The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first to additional paid-in capital and then to accumulated earnings (deficit) thereafter. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares outstanding, to the balance of additional paid-in capital as of retirement.
Equity-Based Compensation	(w) Equity-Based Compensation The Company recognizes compensation cost related to all equity-based awards in the financial statements based on their estimated grant date fair value. The Company is to grant various types of equity-based compensation awards including stock options, stock appreciation rights, restricted stock awards, restricted share unit awards, performance share unit awards, dividend equivalent awards and other types of awards. The grant date fair values are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note
Recently Issued Accounting Standard	(x) Recently Issued Accounting Standard Convertible Instruments In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity Debt with Conversion and Other Options , that require separate accounting for conversion features, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. It is effective for interim and annual reporting periods beginning after December 15, 2021. The Company will adopt the standard effective January 1, 2022 under the modified retrospective transition method. Upon adoption of this new standard, the Company will reclassify $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increase long-term debt by $27 million, reduce deferred income tax liability by $6 million and reduce accumulated deficit by $3 million as of January 1, 2022. Additionally, annual interest expense for the 2026 Convertible Notes beginning January 1, 2022 will be based on an effective interest rate of for the year ended December 31, 2021. The Company does not believe that adoption of the standard will impact its operational strategies or development prospects. Income Taxes In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes . Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods beginning after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company's consolidated financial statements.
Natural Gas, NGLs and Oil Revenues
Revenue	(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 on the Company’s consolidated statements of operations. 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
Marketing Revenues and Expenses
Revenue	(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 on the Company’s consolidated statements of operations.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
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, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Six One Commodities LLC (1) ​ 15 % ​ 11 % ​ 10 % ​ Sabine Pass Liquefaction LLC ​ 16 % ​ 11 % ​ * ​ ​ (1) Six One Commodities LLC acquired WGL Midstream during the year ended December 31, 2021. WGL Midstream was the Company's major customer during the years ended December 31, 2019 and 2020. * Sabine Pass Liquefaction LLC was not a major customer during the year ended December 31, 2021.
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, ​ ​ 2019 2020 2021 ​ Basic weighted average number of shares outstanding ​ 306,400 ​ 272,433 ​ 308,146 ​ Add: Dilutive effect of RSUs ​ — ​ — ​ — ​ Add: Dilutive effect of PSUs ​ — ​ — ​ — ​ Add: Dilutive effect of outstanding stock options ​ — ​ — ​ — ​ Add: Dilutive effect of 2026 Convertible Notes ​ — ​ — ​ — ​ Diluted weighted average number of shares outstanding ​ 306,400 ​ 272,433 ​ 308,146 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted earnings per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 2,357 ​ 6,810 ​ 6,407 ​ PSUs ​ 1,443 ​ 432 ​ 2,832 ​ Outstanding stock options ​ 527 ​ 327 ​ 379 ​ 2026 Convertible Notes (2) ​ — ​ 31,388 ​ 18,778 ​ (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—diluted because the inclusion of these awards would have been anti-dilutive. (2) Under the treasury stock method, only the amount by which the conversion value exceeds the aggregate principal amount of the 2026 Convertible Notes is considered in the diluted earnings per share computation. As of December 31, 2020, the conversion value did not exceed the principal amount of the notes. On January 12, 2021, the Company completed the January 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.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue
Schedule of disaggregation of revenue	The table set forth below presents revenue disaggregated by type and reportable segment to which it relates (in thousands). See Note 18—Reportable Segments to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2019 2020 2021 Reportable Segment ​ Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 2,247,162 ​ ​ 1,809,952 ​ ​ 3,442,028 ​ Exploration and production ​ Natural gas liquids sales (ethane) ​ ​ 124,563 ​ ​ 113,811 ​ ​ 206,889 ​ Exploration and production ​ Natural gas liquids sales (C3+ NGLs) ​ ​ 1,094,599 ​ ​ 1,047,872 ​ ​ 1,940,610 ​ Exploration and production ​ Oil sales ​ ​ 177,549 ​ ​ 112,270 ​ ​ 201,232 ​ Exploration and production ​ Marketing ​ ​ 292,207 ​ ​ 310,572 ​ ​ 718,921 ​ Marketing ​ Gathering and compression (1) ​ ​ 3,972 ​ ​ — ​ ​ — ​ Equity method investment in Antero Midstream ​ Water handling and treatment (1) ​ ​ 506 ​ ​ — ​ ​ — ​ Equity method investment in Antero Midstream ​ Total revenue from contracts with customers ​ ​ 3,940,558 ​ ​ 3,394,477 ​ ​ 6,509,680 ​ ​ ​ Income (loss) from derivatives, deferred revenue and other sources, net ​ ​ 468,132 ​ ​ 97,222 ​ ​ (1,890,248) ​ ​ ​ Total revenue ​ $ 4,408,690 ​ ​ 3,491,699 ​ ​ 4,619,432 ​ ​ ​ (1) Gathering and compression and water handling and treatment revenues were included through March 12, 2019. See Note 3—Deconsolidation of Antero Midstream Partners to the consolidated financial statements for further discussion on the Simplification Transactions.

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2021
Antero Midstream Corporation
Equity Method Investments
Schedule of reconciliation of investments in unconsolidated affiliates and summarized financial information	The following table sets forth a reconciliation of Antero’s investment in unconsolidated affiliate (in thousands): ​ ​ ​ ​ ​ ​ Balances as of December 31, 2019 ​ $ 1,055,177 ​ Equity in loss of unconsolidated affiliate ​ ​ (62,660) ​ Dividends from unconsolidated affiliate ​ ​ (171,022) ​ Impairment (1) ​ ​ (610,632) ​ Elimination of intercompany profit ​ ​ 44,219 ​ Balance as of December 31, 2020 (2) ​ ​ 255,082 ​ Equity in earnings of unconsolidated affiliate ​ ​ 77,085 ​ Dividends from unconsolidated affiliate ​ ​ (136,609) ​ Elimination of intercompany profit ​ ​ 36,841 ​ Balance as of December 31, 2021 (2) ​ $ 232,399 ​ (1) Other-than-temporary impairment of the Company’s investment in Antero Midstream to reduce the carrying value of such investment to fair value, which was based on the quoted market share price of Antero Midstream as of March 31, 2020 (Level 1). (2) The fair value of the Company’s investment in Antero Midstream as of December 31, 2020 and 2021 was $1.1 billion and $1.3 billion, respectively, based on the quoted market share price of Antero Midstream. ​ (b) Summarized Financial Information of Antero Midstream ​ The tables set forth below present summarized financial information of Antero Midstream (in thousands). ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Current assets ​ $ 93,931 ​ ​ 83,804 ​ Noncurrent assets ​ ​ 5,516,981 ​ ​ 5,460,197 ​ Total assets ​ $ 5,610,912 ​ ​ 5,544,001 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 94,005 ​ ​ 114,009 ​ Noncurrent liabilities ​ ​ 3,098,621 ​ ​ 3,143,294 ​ Stockholders' equity ​ ​ 2,418,286 ​ ​ 2,286,698 ​ Total liabilities and stockholders' equity ​ $ 5,610,912 ​ ​ 5,544,001 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2020 2021 ​ Revenues ​ $ 900,719 ​ ​ 898,202 ​ Operating expenses ​ ​ 1,018,357 ​ ​ 342,875 ​ Income (loss) from operations ​ ​ (117,638) ​ ​ 555,327 ​ Net income (loss) ​ $ (122,527) ​ ​ 331,617 ​

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Capital expenditures ​ $ 32,372 ​ 46,983 ​ Gathering, compression, processing, and transportation expenses ​ ​ 152,724 ​ ​ 164,900 ​ Marketing expenses ​ ​ 68,193 ​ ​ 50,589 ​ Interest expense, net ​ 25,645 ​ 65,093 ​ Accrued production and ad valorem taxes ​ ​ 37,371 ​ ​ 44,298 ​ Derivative settlements payable ​ ​ 3,425 ​ ​ 35,202 ​ Accrued general and administrative expense ​ ​ 14,363 ​ ​ 27,740 ​ Other ​ 9,431 ​ 22,439 ​ Total accrued liabilities ​ $ 343,524 ​ 457,244 ​

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Long-Term Debt
Schedule of long-term debt	Long-term debt consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Credit Facility (a) ​ $ 1,017,000 ​ ​ — ​ 5.125% senior notes due 2022 (b) ​ ​ 660,516 ​ ​ — ​ 5.625% senior notes due 2023 (c) ​ ​ 574,182 ​ ​ — ​ 5.00% senior notes due 2025 (d) ​ ​ 590,000 ​ ​ 584,635 ​ 8.375% senior notes due 2026 (e) ​ ​ — ​ ​ 325,000 ​ 7.625% senior notes due 2029 (f) ​ ​ — ​ ​ 584,000 ​ 5.375% senior notes due 2030 (g) ​ ​ — ​ ​ 600,000 ​ 4.25% convertible senior notes due 2026 (h) ​ ​ 287,500 ​ ​ 81,570 ​ Total principal ​ ​ 3,129,198 ​ ​ 2,175,205 ​ Unamortized discount, net ​ ​ (111,886) ​ ​ (27,772) ​ Unamortized debt issuance costs ​ ​ (15,719) ​ ​ (21,989) ​ Long-term debt ​ $ 3,001,593 ​ ​ 2,125,444 ​ ​
4.25% convertible senior notes due 2026
Long-Term Debt
Schedule of long-term debt	The 2026 Convertible Notes consist of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ Liability component: ​ ​ ​ ​ ​ ​ ​ Principal ​ $ 287,500 ​ ​ 81,570 ​ Less: unamortized note discount ​ ​ (112,265) ​ ​ (27,772) ​ Less: unamortized debt issuance costs ​ ​ (5,852) ​ ​ (1,592) ​ Net carrying value ​ $ 169,383 ​ ​ 52,206 ​ Equity component (1) ​ $ 115,601 ​ ​ 32,799 ​ (1) As of December 31, 2020, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital, net of $3 million of issuance costs and $28 million of deferred taxes. As of December 31, 2021, the equity component attributable to the outstanding 2026 Convertible Notes was recorded in additional paid-in capital net of $1 million of issuance costs and $8 million of deferred taxes.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligations
Schedule of reconciliation of asset retirement obligations	​ The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ Beginning balance $ 54,845 ​ 54,452 ​ Obligations incurred ​ 1,814 ​ ​ 3,208 ​ Accretion expense ​ ​ 3,421 ​ ​ 3,820 ​ Settlement of obligations ​ ​ (229) ​ ​ (40) ​ Revisions to prior estimates ​ ​ (5,399) ​ ​ (7,488) ​ Ending balance ​ $ 54,452 ​ ​ 53,952 ​

Equity-Based Compensation and_2

Equity-Based Compensation and Cash Awards (Tables)	12 Months Ended
	Dec. 31, 2021
Equity-Based Compensation and Cash Awards
Schedule of equity-based compensation expense	The Company’s equity-based compensation expense, by type of award, is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 ​ RSU awards ​ $ 10,343 ​ ​ 12,510 ​ ​ 13,232 ​ PSU awards ​ ​ 8,069 ​ ​ 7,219 ​ ​ 4,662 ​ Converted AM RSU Awards (1) ​ ​ 3,425 ​ ​ 2,519 ​ ​ 1,160 ​ Stock options ​ ​ 355 ​ ​ — ​ ​ — ​ Equity awards issued to directors ​ ​ 1,367 ​ ​ 1,069 ​ ​ 1,383 ​ Total expense ​ $ 23,559 ​ ​ 23,317 ​ ​ 20,437 ​ (1) Antero Resources recognized compensation expense for equity awards granted under both the 2013 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 Simplification 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 to the consolidated financial statements for further discussion on the Simplification Transactions.
Summary of RSU award activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number of ​ Grant Date ​ ​ Shares Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 8,432,397 ​ $ 4.06 ​ Granted ​ 1,447,806 ​ ​ 9.63 ​ Vested ​ (3,622,741) ​ ​ 4.37 ​ Forfeited ​ (326,855) ​ ​ 5.45 ​ Total awarded and unvested—December 31, 2021 ​ 5,930,607 ​ $ 5.15 ​
Summary of PSU award activity	A summary of PSU activity is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ Number of ​ Average Grant ​ ​ Units Date Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 2,547,798 ​ $ 12.66 ​ Granted ​ 479,120 ​ ​ 9.71 ​ Forfeited ​ (67,000) ​ ​ 2.97 ​ Cancelled (unearned) ​ (1,112,639) ​ ​ 19.19 ​ Total awarded and unvested—December 31, 2021 ​ 1,847,279 ​ $ 8.31 ​
Schedule of weighted average fair value assumptions used for PSUs granted	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ ​ Dividend yield ​ ​ — % ​ — % ​ — % ​ Volatility ​ ​ 36 % ​ 80 % ​ 85 % ​ Risk-free interest rate ​ ​ 2.35 % ​ 0.17 % ​ 0.32 % ​ Weighted average fair value of awards granted—Absolute TSR ​ $ 9.26 ​ ​ 2.63 ​ ​ 11.99 ​ ​ Weighted average fair value of awards granted—Relative TSR ​ $ — ​ ​ 3.30 ​ ​ — ​ ​
Schedule of Converted AM RSU Awards	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number of ​ Grant Date ​ ​ Units Fair Value ​ Total awarded and unvested—December 31, 2020 ​ 296,390 ​ $ 15.06 ​ Granted ​ — ​ ​ — ​ Vested ​ (209,964) ​ ​ 15.73 ​ Forfeited ​ (4,719) ​ ​ 13.25 ​ Total awarded and unvested—December 31, 2021 ​ 81,707 ​ $ 13.46 ​
Summary of stock option activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ Average ​ ​ ​ ​ ​ ​ ​ Average ​ Remaining ​ Intrinsic ​ ​ ​ Stock ​ Exercise ​ Contractual ​ Value ​ ​ Options Price Life (in thousands) ​ Outstanding—December 31, 2020 ​ 432,461 ​ $ 50.64 ​ 4.1 ​ $ — ​ Granted ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Exercised ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Forfeited ​ — ​ ​ — ​ ​ ​ ​ ​ ​ Expired ​ (80,667) ​ ​ 50.00 ​ ​ ​ ​ ​ ​ Outstanding—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​ Vested—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​ Exercisable—December 31, 2021 ​ 351,794 ​ $ 50.79 ​ 3.0 ​ $ — ​

Fair value (Tables)

Fair value (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value
Schedule of fair value and carrying value of the senior notes and 2026 Convertible Notes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2020 ​ 2021 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 2022 Notes ​ $ 658,468 ​ ​ 658,400 ​ ​ — ​ ​ — ​ 2023 Notes ​ ​ 562,698 ​ ​ 571,370 ​ ​ — ​ ​ — ​ 2025 Notes ​ ​ 560,500 ​ ​ 585,440 ​ ​ 594,866 ​ ​ 581,117 ​ 2026 Notes ​ ​ — ​ ​ — ​ ​ 370,013 ​ ​ 321,738 ​ 2029 Notes ​ ​ — ​ ​ — ​ ​ 654,080 ​ ​ 577,149 ​ 2030 Notes ​ ​ — ​ ​ — ​ ​ 641,400 ​ ​ 593,234 ​ 2026 Convertible Notes ​ ​ 430,963 ​ ​ 169,383 ​ ​ 331,655 ​ ​ 52,206 ​ Total ​ $ 2,212,629 ​ ​ 1,984,593 ​ ​ 2,592,014 ​ ​ 2,125,444 ​ (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.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Schedule of outstanding commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​
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 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 ​
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	The table below presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets (in thousands). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ December 31, ​ December 31, ​ ​ Location 2020 ​ 2021 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current ​ Derivative instruments ​ $ 97,144 ​ ​ — ​ Embedded derivatives—current ​ Derivative instruments ​ ​ 7,986 ​ ​ 757 ​ Commodity derivatives—noncurrent ​ Derivative instruments ​ ​ 14,689 ​ ​ — ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ 32,604 ​ ​ 14,369 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total asset derivatives (1) ​ ​ ​ ​ 152,423 ​ ​ 15,126 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (2) ​ Derivative instruments ​ ​ 31,242 ​ ​ 559,851 ​ Commodity derivatives—noncurrent (2) ​ Derivative instruments ​ ​ 99,172 ​ ​ 181,806 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total liability derivatives (1) ​ ​ ​ ​ 130,414 ​ ​ 741,657 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives asset (liability) (1) ​ ​ ​ $ 22,009 ​ ​ (726,531) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs. (2) 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. As of December 31, 2021, approximately $55 million of commodity derivative liabilities, including $31 million of current commodity derivatives and $24 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 sets forth 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, 2020 ​ December 31, 2021 ​ ​ ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ ​ ​ Net Amounts of ​ ​ ​ Gross ​ Gross ​ Assets ​ Gross ​ Gross ​ Assets ​ ​ ​ Amounts ​ Amounts Offset ​ (Liabilities) on ​ Amounts ​ Amounts Offset ​ (Liabilities) on ​ ​ Recognized Recognized Balance Sheet Recognized Recognized Balance Sheet Commodity derivative assets ​ $ 181,375 ​ ​ (69,542) ​ ​ 111,833 ​ ​ 2,177 ​ ​ (2,177) ​ ​ — ​ Embedded derivative assets ​ $ 40,590 ​ ​ — ​ ​ 40,590 ​ ​ 15,126 ​ ​ — ​ ​ 15,126 ​ Commodity derivative liabilities ​ $ (199,956) ​ ​ 69,542 ​ ​ (130,414) ​ ​ (743,834) ​ ​ 2,177 ​ ​ (741,657) ​
Summary of derivative fair value gains (losses)	The following table sets forth a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location 2019 ​ 2020 2021 ​ Commodity derivative fair value gains (losses) (1) ​ Revenue ​ $ 463,972 ​ ​ 40,565 ​ ​ (1,886,551) ​ Embedded derivative fair value gains (losses) (1) ​ Revenue ​ $ — ​ ​ 39,353 ​ ​ (49,958) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs .
VIE, Martica
Schedule of outstanding commodity derivatives	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Henry Hub ​ 38,356 MMBtu/day ​ $ 2.39 /MMBtu ​ January-December 2023 ​ Henry Hub ​ 35,616 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Ethane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-March 2022 ​ Mont Belvieu Purity Ethane-OPIS ​ 521 Bbl/day ​ $ 6.68 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Propane ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Mont Belvieu Propane-OPIS Non-TET ​ 934 Bbl/day ​ $ 19.20 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural Gasoline ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 282 Bbl/day ​ $ 34.37 /Bbl ​ January-December 2023 ​ Mont Belvieu Natural Gasoline-OPIS Non-TET ​ 247 Bbl/day ​ ​ 40.74 /Bbl ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2022 ​ West Texas Intermediate ​ 112 Bbl/day ​ $ 43.51 /Bbl ​ January-December 2023 ​ West Texas Intermediate ​ 99 Bbl/day ​ ​ 44.88 /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, 2021
Leases
Summary of supplemental balance sheet information related to leases	The Company’s lease assets and liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ Leases Balance Sheet Classification 2020 2021 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,302,290 ​ ​ 1,739,550 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 29,894 ​ ​ 9,860 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,241,090 ​ ​ 1,634,928 ​ Office space ​ Operating lease right-of-use assets ​ ​ 36,879 ​ ​ 33,083 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 2,704 ​ ​ 2,009 ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 746 ​ ​ 482 ​ Total operating lease right-of-use assets ​ ​ ​ $ 2,613,603 ​ ​ 3,419,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease obligation ​ Short-term lease liabilities ​ $ 265,178 ​ ​ 455,950 ​ Long-term operating lease obligation ​ Long-term lease liabilities ​ ​ 2,348,425 ​ ​ 2,963,962 ​ Total operating lease obligation ​ ​ ​ $ 2,613,603 ​ ​ 3,419,912 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 1,206 ​ ​ 550 ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 1,206 ​ ​ 550 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease obligation ​ Short-term lease liabilities ​ $ 845 ​ ​ 397 ​ Long-term finance lease obligation ​ Long-term lease liabilities ​ ​ 361 ​ ​ 153 ​ Total finance lease obligation ​ ​ ​ $ 1,206 ​ ​ 550 ​ (1) Gas gathering lines and compressor stations leases includes $ 1.1 billion and $1.5 billion related to Antero Midstream as of December 31, 2020 and 2021 , respectively. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $3 million and $2 million as of December 31, 2020 and 2021 , respectively.
Summary of costs associated with operating leases and finance leases	Costs associated with operating and finance leases were included in the consolidated statement of operations and comprehensive loss (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, Cost Classification Location 2019 2020 2021 Operating lease cost ​ Statement of operations ​ Gathering, compression, processing, and transportation ​ $ 842,440 ​ ​ 1,498,221 ​ ​ 1,518,305 Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 11,228 ​ ​ 11,530 ​ ​ 10,901 Operating lease cost ​ Statement of operations ​ Contract termination and rig stacking ​ ​ 10,692 ​ ​ 8,528 ​ ​ 4,213 Operating lease cost ​ Statement of operations ​ Lease operating ​ ​ — ​ ​ — ​ ​ 142 Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 194,522 ​ ​ 104,146 ​ ​ 103,741 Total operating lease cost ​ ​ ​ ​ ​ $ 1,058,882 ​ ​ 1,622,425 ​ ​ 1,637,302 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation, and amortization ​ $ 1,471 ​ ​ 872 ​ ​ 522 Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 335 ​ ​ 208 ​ ​ — Total finance lease cost ​ ​ ​ ​ ​ $ 1,806 ​ ​ 1,080 ​ ​ 522 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 162,654 ​ ​ 122,577 ​ ​ 86,039 (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 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases ​ $ 809,667 ​ ​ 1,576,984 ​ ​ 1,352,941 ​ Operating cash flows from finance leases ​ ​ 335 ​ ​ 208 ​ ​ — ​ Investing cash flows from operating leases ​ ​ 178,898 ​ ​ 106,867 ​ ​ 88,910 ​ Financing cash flows from finance leases ​ ​ 2,507 ​ ​ 1,291 ​ ​ 859 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease obligations ​ $ 3,720,945 ​ ​ 202,125 ​ ​ 437,045 ​ Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net (1) ​ $ (681,686) ​ ​ (173,563) ​ ​ 702,512 ​ (1) During the year ended December 31, 2019, the weighted average discount rate for remeasured operating leases increased from 6.0% as of January 1, 2019 to 12.4% as of December 31, 2019 . During the year ended December 31, 2020 , the weighted average discount rate for remeasured operating leases increased from 10.0% as of December 31, 2019 to 14.4% as of December 31, 2020 . During the year ended December 31, 2021 , the weighted average discount rate for remeasured operating leases decreased from 14.4% as of December 31, 2020 to 5.0% as of December 31, 2021.
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, 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2022 ​ $ 634,632 ​ ​ 424 ​ ​ 635,056 ​ 2023 ​ ​ 622,266 ​ ​ 76 ​ ​ 622,342 ​ 2024 ​ ​ 612,344 ​ ​ 67 ​ ​ 612,411 ​ 2025 ​ ​ 540,291 ​ ​ 22 ​ ​ 540,313 ​ 2026 ​ ​ 489,589 ​ ​ — ​ ​ 489,589 ​ Thereafter ​ ​ 1,386,882 ​ ​ — ​ ​ 1,386,882 ​ Total lease payments ​ ​ 4,286,004 ​ ​ 589 ​ ​ 4,286,593 ​ Less: imputed interest ​ ​ (866,092) ​ ​ (39) ​ ​ (866,131) ​ Total ​ $ 3,419,912 ​ ​ 550 ​ ​ 3,420,462 ​
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, 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2022 ​ $ 634,632 ​ ​ 424 ​ ​ 635,056 ​ 2023 ​ ​ 622,266 ​ ​ 76 ​ ​ 622,342 ​ 2024 ​ ​ 612,344 ​ ​ 67 ​ ​ 612,411 ​ 2025 ​ ​ 540,291 ​ ​ 22 ​ ​ 540,313 ​ 2026 ​ ​ 489,589 ​ ​ — ​ ​ 489,589 ​ Thereafter ​ ​ 1,386,882 ​ ​ — ​ ​ 1,386,882 ​ Total lease payments ​ ​ 4,286,004 ​ ​ 589 ​ ​ 4,286,593 ​ Less: imputed interest ​ ​ (866,092) ​ ​ (39) ​ ​ (866,131) ​ Total ​ $ 3,419,912 ​ ​ 550 ​ ​ 3,420,462 ​
Summary of weighted-average remaining lease term and discount rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2020 ​ December 31, 2021 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ Operating Leases ​ Finance Leases ​ ​ Weighted average remaining lease term ​ 8.0 years ​ 1.5 years ​ 7.6 years ​ 1.9 years ​ ​ Weighted average discount rate ​ 13.7 % 6.2 % 5.5 % 5.6 % ​

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Taxes
Schedule of income tax expense from continuing operations	​ The Company’s income tax benefit consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 Current income tax expense (benefit) ​ $ 5,048 ​ ​ (209) ​ ​ 216 ​ Deferred income tax benefit ​ (79,158) ​ (397,273) ​ (74,293) ​ Total income tax benefit ​ $ (74,110) ​ ​ (397,482) ​ ​ (74,077) ​
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 income or loss before taxes as a result of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 2020 2021 Federal income tax expense (benefit) ​ $ (77,122) ​ ​ (348,158) ​ ​ (47,919) ​ State income tax expense (benefit), net of federal benefit ​ (8,826) ​ (50,584) ​ (6,576) ​ Change in state tax rate, net of federal effect ​ ​ 24,041 ​ ​ 2,291 ​ ​ (30,910) ​ Nondeductible equity-based compensation ​ 6,920 ​ 4,490 ​ 1,117 ​ Dividends received deduction ​ ​ (4,201) ​ ​ (4,013) ​ ​ (3,832) ​ Noncontrolling interest ​ ​ (10,998) ​ ​ (1,801) ​ ​ (7,862) ​ Deconsolidation adjustment ​ ​ (6,626) ​ ​ — ​ ​ — ​ Change in valuation allowance ​ 1,325 ​ 789 ​ 4,606 ​ Nondeductible loss on 2026 Convertible Notes equitization ​ ​ — ​ ​ — ​ ​ 12,174 ​ Other ​ 1,377 ​ (496) ​ 5,125 ​ Total income tax benefit ​ $ (74,110) ​ ​ (397,482) ​ ​ (74,077) ​
Schedule of net deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2020 2021 ​ Deferred tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 565,433 ​ ​ 569,523 ​ Equity-based compensation ​ ​ 8,445 ​ ​ 2,462 ​ Investment in Antero Midstream ​ ​ 330,301 ​ ​ 297,893 ​ Unrealized losses on derivative instruments ​ ​ — ​ ​ 158,779 ​ Asset retirement obligations and other ​ ​ 17,206 ​ ​ 15,051 ​ Total deferred tax assets ​ ​ 921,385 ​ ​ 1,043,708 ​ Valuation allowance ​ ​ (46,013) ​ ​ (50,304) ​ Net deferred tax assets ​ ​ 875,372 ​ ​ 993,404 ​ Deferred tax liabilities: ​ ​ ​ ​ ​ ​ ​ Unrealized gains on derivative instruments ​ ​ 13,189 ​ ​ — ​ Oil and gas properties ​ ​ 1,188,599 ​ ​ 1,254,182 ​ Investment in Martica ​ ​ 59,586 ​ ​ 51,166 ​ 2026 Convertible Notes and other ​ ​ 26,250 ​ ​ 6,182 ​ Total deferred tax liabilities ​ ​ 1,287,624 ​ ​ 1,311,530 ​ Net deferred tax liabilities ​ $ (412,252) ​ ​ (318,126) ​

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments
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	​ The following table sets forth 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 a lease term in excess of one year as of December 31, 2021 (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 2022 ​ $ 1,042,280 ​ ​ 52,265 ​ ​ 1,361 ​ ​ 456,345 ​ ​ 178,711 ​ ​ 1,730,962 ​ 2023 ​ ​ 1,072,523 ​ ​ 59,140 ​ ​ — ​ ​ 466,960 ​ ​ 155,382 ​ ​ 1,754,005 ​ 2024 ​ ​ 1,045,442 ​ ​ 59,262 ​ ​ — ​ ​ 481,688 ​ ​ 130,723 ​ ​ 1,717,115 ​ 2025 ​ ​ 1,024,783 ​ ​ 47,960 ​ ​ — ​ ​ 433,507 ​ ​ 106,806 ​ ​ 1,613,056 ​ 2026 ​ ​ 1,018,812 ​ ​ 14,783 ​ ​ — ​ ​ 404,381 ​ ​ 85,208 ​ ​ 1,523,184 ​ Thereafter ​ ​ 6,033,138 ​ ​ 98,596 ​ ​ — ​ ​ 1,177,581 ​ ​ 209,301 ​ ​ 7,518,616 ​ Total ​ $ 11,236,978 ​ ​ 332,006 ​ ​ 1,361 ​ ​ 3,420,462 ​ ​ 866,131 ​ ​ 15,856,938 ​

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2021
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 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2019 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation (1) Affiliates Total ​ Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,107,845 ​ ​ 292,207 ​ ​ 50 ​ ​ — ​ ​ 4,400,102 ​ Intersegment ​ 5,812 ​ ​ — ​ ​ 792,538 ​ ​ (789,762) ​ ​ 8,588 ​ Total revenue ​ ​ 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 ​ General and administrative ​ ​ 160,402 ​ ​ — ​ ​ 118,113 ​ ​ (99,819) ​ ​ 178,696 ​ Depletion, depreciation, and amortization ​ ​ 893,161 ​ ​ — ​ ​ 95,526 ​ ​ (73,820) ​ ​ 914,867 ​ Impairment of oil and gas properties ​ ​ 1,300,444 ​ ​ — ​ ​ — ​ ​ — ​ ​ 1,300,444 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 776,832 ​ ​ (762,050) ​ ​ 14,782 ​ Other ​ ​ 143,762 ​ ​ 549,814 ​ ​ 12,093 ​ ​ (11,090) ​ ​ 694,579 ​ Total operating expenses ​ ​ 4,901,858 ​ ​ 549,814 ​ ​ 1,205,953 ​ ​ (1,261,890) ​ ​ 5,395,735 ​ Operating loss ​ $ (788,201) ​ ​ (257,607) ​ ​ (413,365) ​ ​ 472,128 ​ ​ (987,045) ​ Equity in earnings 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 effective March 13, 2019. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2020 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,178,330 ​ ​ 310,572 ​ ​ — ​ ​ — ​ ​ 3,488,902 ​ Intersegment ​ 2,797 ​ ​ — ​ ​ 900,719 ​ ​ (900,719) ​ ​ 2,797 ​ Total revenue ​ ​ 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 ​ General and administrative ​ ​ 134,482 ​ ​ — ​ ​ 52,213 ​ ​ (52,213) ​ ​ 134,482 ​ Depletion, depreciation, and amortization ​ ​ 861,870 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 861,870 ​ Impairment of oil and gas properties ​ ​ 223,770 ​ ​ — ​ ​ — ​ ​ — ​ ​ 223,770 ​ Impairment of midstream assets ​ ​ — ​ ​ — ​ ​ 673,640 ​ ​ (673,640) ​ ​ — ​ Other ​ ​ 125,917 ​ ​ 469,404 ​ ​ 18,328 ​ ​ (18,328) ​ ​ 595,321 ​ Total operating expenses ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2021 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ Elimination of ​ ​ ​ ​ ​ ​ ​ ​ ​ Investment in ​ Intersegment ​ ​ ​ ​ ​ Exploration ​ ​ ​ Antero ​ Transactions and ​ ​ ​ ​ ​ and ​ ​ ​ Midstream ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Corporation Affiliates Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,899,486 ​ ​ 718,921 ​ ​ — ​ ​ — ​ ​ 4,618,407 ​ Intersegment ​ 1,025 ​ ​ — ​ ​ 898,202 ​ ​ (898,202) ​ ​ 1,025 ​ Total revenue ​ ​ 3,900,511 ​ ​ 718,921 ​ ​ 898,202 ​ ​ (898,202) ​ ​ 4,619,432 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 96,793 ​ ​ — ​ ​ — ​ ​ — ​ ​ 96,793 ​ Gathering, compression, processing, and transportation ​ ​ 2,499,174 ​ ​ — ​ ​ 157,120 ​ ​ (157,120) ​ ​ 2,499,174 ​ General and administrative ​ ​ 145,006 ​ ​ — ​ ​ 63,838 ​ ​ (63,838) ​ ​ 145,006 ​ Depletion, depreciation, and amortization ​ ​ 742,009 ​ ​ — ​ ​ 108,790 ​ ​ (108,790) ​ ​ 742,009 ​ Impairment of oil and gas properties ​ ​ 90,523 ​ ​ — ​ ​ — ​ ​ — ​ ​ 90,523 ​ Other ​ ​ 210,369 ​ ​ 811,698 ​ ​ 13,127 ​ ​ (13,127) ​ ​ 1,022,067 ​ Total operating expenses ​ ​ 3,783,874 ​ ​ 811,698 ​ ​ 342,875 ​ ​ (342,875) ​ ​ 4,595,572 ​ Operating income (loss) ​ $ 116,637 ​ ​ (92,777) ​ ​ 555,327 ​ ​ (555,327) ​ ​ 23,860 ​ Equity in earnings of unconsolidated affiliates ​ $ 77,085 ​ ​ — ​ ​ 90,451 ​ ​ (90,451) ​ ​ 77,085 ​ Investments in unconsolidated affiliates ​ $ 232,399 ​ ​ — ​ ​ 696,009 ​ ​ (696,009) ​ ​ 232,399 ​ Segment assets ​ $ 13,864,402 ​ ​ 32,126 ​ ​ 5,544,001 ​ ​ (5,544,001) ​ ​ 13,896,528 ​ Capital expenditures for segment assets ​ $ 715,936 ​ ​ — ​ ​ 232,825 ​ ​ (232,825) ​ ​ 715,936 ​

Subsidiary Guarantors (Tables)

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2021
Subsidiary Guarantors
Schedule of summarized financial information of Antero and its guarantor subsidiaries	​ ​ ​ ​ ​ ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 ​ Accounts receivable, non-guarantor subsidiaries ​ $ — ​ Accounts receivable, related parties ​ ​ — ​ Other current assets ​ ​ 633,014 ​ Total current assets ​ ​ 633,014 ​ Noncurrent assets ​ ​ 12,480,350 ​ Total assets ​ $ 13,113,364 ​ ​ ​ ​ ​ ​ Accounts payable, non-guarantor subsidiaries ​ $ — ​ Accounts payable, related parties ​ ​ 76,240 ​ Other current liabilities ​ ​ 1,961,041 ​ Total current liabilities ​ ​ 2,037,281 ​ Noncurrent liabilities ​ ​ 5,737,999 ​ Total liabilities ​ $ 7,775,280 ​ ​ ​ ​ ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ December 31, 2021 ​ Revenues ​ $ 4,545,912 ​ Operating expenses ​ ​ 4,561,383 ​ Loss from operations ​ ​ (15,471) ​ Net loss and comprehensive loss including noncontrolling interests ​ ​ (186,899) ​ Net loss and comprehensive loss attributable to Antero Resources Corporation ​ $ (186,899) ​

Supplemental Information on O_2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Schedule of capitalized costs relating to oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2020 ​ 2021 ​ Proved properties ​ $ 12,260,713 ​ ​ 12,646,303 ​ Unproved properties ​ 1,175,178 ​ 1,042,118 ​ Total oil and gas properties ​ 13,435,891 ​ 13,688,421 ​ Accumulated depletion ​ (3,818,279) ​ (4,229,300) ​ Net capitalized costs ​ $ 9,617,612 ​ ​ 9,459,121 ​
Schedule of costs incurred in certain oil and gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved property ​ $ — ​ ​ — ​ ​ — ​ Unproved property ​ 88,682 ​ ​ 45,129 ​ ​ 79,138 ​ Development costs ​ 1,104,336 ​ ​ 823,271 ​ ​ 581,352 ​ Exploration costs ​ 149,782 ​ ​ 2,993 ​ ​ 19,822 ​ Total costs incurred ​ $ 1,342,800 ​ ​ 871,393 ​ ​ 680,312 ​
Schedule of results of operations for oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2019 ​ 2020 ​ 2021 ​ Revenues ​ $ 3,643,873 ​ ​ 3,083,905 ​ ​ 5,790,759 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 2,417,509 ​ ​ 2,736,478 ​ ​ 2,793,877 ​ Exploration expenses ​ 884 ​ ​ 1,083 ​ ​ 1,164 ​ Depletion ​ 884,350 ​ ​ 854,331 ​ ​ 735,687 ​ Impairment of unproved properties ​ 1,300,444 ​ ​ 223,770 ​ ​ 90,523 ​ Results of operations before income tax (expense) benefit ​ (959,314) ​ ​ (731,757) ​ ​ 2,169,508 ​ Income tax (expense) benefit ​ 224,511 ​ ​ (176,061) ​ ​ 520,168 ​ Results of operations ​ $ (734,803) ​ ​ (907,818) ​ ​ 2,689,676 ​
Schedule of proved developed and undeveloped reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved 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) ​ 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) ​ December 31, 2020 (1) ​ 10,025 ​ 1,236 ​ 33 ​ 17,635 ​ Revisions ​ 993 ​ 77 ​ 6 ​ 1,486 ​ Extensions, discoveries and other additions ​ 349 ​ 18 ​ 2 ​ 472 ​ Production ​ (826) ​ (58) ​ (4) ​ (1,194) ​ Sales ​ (337) ​ (54) ​ (1) ​ (670) ​ December 31, 2021 (1) ​ 10,204 ​ 1,219 ​ 36 ​ 17,729 ​ (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. Proved reserves for the noncontrolling interest in Martica as of December 31, 2021 were 167 Bcfe, which consists of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 7,229 ​ 731 ​ 21 ​ 11,740 ​ December 31, 2020 (1) ​ 6,901 ​ 810 ​ 19 ​ 11,873 ​ December 31, 2021 (1) ​ 7,395 ​ 876 ​ 17 ​ 12,753 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2019 ​ 4,265 ​ 460 ​ 21 ​ 7,153 ​ December 31, 2020 (2) ​ 3,124 ​ 426 ​ 14 ​ 5,762 ​ December 31, 2021 (2) ​ 2,809 ​ 343 ​ 19 ​ 4,976 ​ (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. Proved developed reserves for the noncontrolling interest in Martica as of December 31, 2021 were 133 Bcfe, which consists of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 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. Proved undeveloped reserves for the noncontrolling interest in Martica as of December 31, 2021 were 34 Bcfe, which consists of 23 Bcf of natural gas, 2 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, ​ ​ ​ 2019 ​ 2020 ​ 2021 Future cash inflows ​ $ 54,228 ​ ​ 37,845 ​ ​ 74,622 ​ Future production costs ​ (36,524) ​ ​ (32,202) ​ ​ (34,665) ​ Future development costs ​ (2,772) ​ ​ (1,685) ​ ​ (1,704) ​ Future net cash flows before income tax ​ 14,932 ​ ​ 3,958 ​ ​ 38,253 ​ Future income tax expense (1) ​ (1,639) ​ ​ — ​ ​ (7,813) ​ Future net cash flows ​ 13,293 ​ ​ 3,958 ​ ​ 30,440 ​ 10% annual discount for estimated timing of cash flows ​ (7,824) ​ ​ (2,748) ​ ​ (17,007) ​ Standardized measure of discounted future net cash flows (2) ​ $ 5,469 ​ ​ 1,210 ​ ​ 13,433 ​ (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 was expected to be less than its NOL carryforward deductions and therefore, under the standardized measure, there was 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 and $501 million for the years ended December 31, 2020 and 2021, respectively.
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ 12-month weighted average price ​ $ 2.87 ​ ​ 2.15 ​ ​ 4.21 ​
Schedule of changes in standardized measure of discounted future net cash flow	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2019 ​ 2020 ​ 2021 ​ Sales of oil and gas, net of productions costs ​ $ (1,116) ​ ​ (347) ​ ​ (2,917) ​ Net changes in prices and production costs (1) ​ (6,729) ​ ​ (5,455) ​ ​ 14,099 ​ Development costs incurred during the period ​ 758 ​ ​ 704 ​ ​ 454 ​ Net changes in future development costs (2) ​ (92) ​ ​ 249 ​ ​ (117) ​ Extensions, discoveries and other additions ​ 782 ​ ​ 31 ​ ​ 504 ​ Divestitures ​ ​ — ​ ​ (174) ​ ​ (125) ​ Revisions of previous quantity estimates ​ (1,011) ​ ​ (379) ​ ​ 2,543 ​ Accretion of discount ​ 1,259 ​ ​ 607 ​ ​ 121 ​ Net change in income taxes ​ 1,513 ​ ​ 598 ​ ​ (3,115) ​ Changes in timing and other ​ (373) ​ ​ (93) ​ ​ 776 ​ Net increase (decrease) ​ (5,009) ​ ​ (4,259) ​ ​ 12,223 ​ Beginning of year ​ 10,478 ​ ​ 5,469 ​ ​ 1,210 ​ End of year (3) ​ $ 5,469 ​ ​ 1,210 ​ ​ 13,433 ​ (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 for the noncontrolling interest in Martica was $359 million and $501 million for the years ended December 31, 2020 and 2021, respectively.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation and Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Mar. 12, 2019	Dec. 31, 2021	Dec. 31, 2020	Mar. 13, 2019
Accounts Payable
Basis of Presentation
Book overdrafts		$ 5	$ 7
Revenue distributions payable
Basis of Presentation
Book overdrafts		$ 52	$ 18
Antero Midstream Partners LP
Basis of Presentation
Ownership interest	53.00%
Antero Midstream Corporation
Basis of Presentation
Ownership percentage		29.10%	29.20%	31.00%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Other Property and equipment (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property and Equipment
Depreciation expense		$ 742,009	$ 861,870	$ 914,867
Oil and Gas Properties
Impairment of oil and gas properties		90,523	223,770	1,300,444
Impairment of unproved oil and gas properties		91,000	224,000	393,000
Depreciation, depletion, and amortization expense for oil and gas properties		736,000	854,000	884,000
Impairment of long-lived assets other than oil and gas properties		0	0	15,000
Deferred Financing Costs
Unamortized debt issuance costs		22,000	16,000
Amounts amortized and the write-off of previously deferred debt issuance costs		7,000	8,000	11,000
Utica Shale
Oil and Gas Properties
Impairment of oil and gas properties	$ 881,000
Other long term assets
Deferred Financing Costs
Unamortized debt issuance costs			3,000
Long-term debt
Deferred Financing Costs
Unamortized debt issuance costs		8,000
Other property and equipment
Property and Equipment
Depreciation expense		$ 6,000	8,000	8,000
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	$ 0	$ 26,000

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Concentrations Credit Risk (Details) - Sales - Customer concentration	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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%
Six One Commodities LLC
Concentrations of Credit Risk
Sales to major customers (as a percent)	10.00%

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Derivative Financial Instruments (Details)	Dec. 31, 2021Counterparty
Summary of Significant Accounting Policies
Number of counterparties	10

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Earnings (Loss) Per Common Share and Recently Issued Accounting Standard (Details) - USD ($) shares in Thousands, $ in Millions	Jan. 12, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2022	Aug. 21, 2020
Earnings per share and New Accounting Principle
Basic weighted average number of shares outstanding		308,146	272,433	306,400
Diluted weighted average number of shares outstanding		308,146	272,433	306,400
Number of shares of common stock issued (in shares)	31,400
Accounting Standards Update 2020-06 | Adjustment Effect | Subsequent event
Earnings per share and New Accounting Principle
Amount expected to be reclassified from additional paid-in capital to long-term debt, deferred income tax liability and accumulated deficit					$ 24
4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Debt repurchased	$ 150
Effective interest rate (as a percent)		15.30%				15.10%
4.25% convertible senior notes due 2026 | Accounting Standards Update 2020-06 | Adjustment Effect | Subsequent event
Earnings per share and New Accounting Principle
Effective interest rate (as a percent)					4.90%
RSUs
Earnings per share and New Accounting Principle
Weighted average anti-dilutive awards		6,407	6,810	2,357
PSUs
Earnings per share and New Accounting Principle
Weighted average anti-dilutive awards		2,832	432	1,443
Stock options
Earnings per share and New Accounting Principle
Weighted average anti-dilutive awards		379	327	527
4.25% convertible senior notes due 2026
Earnings per share and New Accounting Principle
Weighted average anti-dilutive awards		18,778	31,388

Deconsolidation of Antero Mid_2

Deconsolidation of Antero Midstream Partners LP - Narrative (Details) - USD ($) $ in Thousands	Mar. 12, 2019	Dec. 31, 2019	Mar. 13, 2019
Deconsolidation
Cash received		$ 296,611
Gain on deconsolidation of Antero Midstream Partners LP		$ 1,406,042
Antero Midstream Corporation
Deconsolidation
Cash received	$ 297,000
Shares of Antero Midstream's common stock received	158,400,000
Gain on deconsolidation of Antero Midstream Partners LP	$ 1,400,000
Fair value of our retained equity method investment			$ 2,000,000
Antero Midstream Partners LP
Deconsolidation
Number of common units exchanged	98,870,335

Transactions (Details)

Transactions (Details) ft in Thousands, $ in Thousands	Aug. 10, 2020USD ($)	Jul. 01, 2020MMBTU	Jun. 15, 2020USD ($)ft	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Transactions
Cash contribution				$ 51,000	$ 351,000
Net proceeds from VPP transaction					215,789
ORRI
Transactions
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%
Percentage of distributions received			85.00%
ORRI | Sixth Street
Transactions
Cash contribution			$ 300,000
Additional contribution upon achievement of production target			$ 102,000
Cash distributions received				$ 51,000	$ 51,000
Internal rate of return threshold			13.00%
Cash on cash return threshold			150.00%
VPP
Transactions
Net proceeds from VPP transaction	$ 216,000
VPP | JPM -VEC
Transactions
Overriding royalty interest conveyed in proved developed producing oil and gas properties (in MMBtu) | MMBTU		136,589,000
VPP agreement term for overriding royalty interest (in years)		7 years
Drilling Partnership | QL
Transactions
Percent of total development capital spending in current year funded by drilling partner				20.00%
Percent of total development capital spending in the next year to be funded by drilling partner				15.00%
Gain (loss) on interests conveyed				$ 0
Drilling Partnership | QL | Minimum
Transactions
Percent of total development capital spending in years 2-4 to be funded by drilling partner				15.00%
Drilling Partnership | QL | Maximum
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	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue
Revenue	$ 6,509,680	$ 3,394,477	$ 3,940,558
Income (loss) from derivatives, deferred revenue and other sources	(1,890,248)	97,222	468,132
Total revenue	4,619,432	3,491,699	4,408,690
Natural gas sales
Disaggregation of Revenue
Revenue	3,442,028	1,809,952	2,247,162
Oil sales
Disaggregation of Revenue
Revenue	201,232	112,270	177,549
Gathering and compression
Disaggregation of Revenue
Revenue			3,972
Water handling and treatment
Disaggregation of Revenue
Revenue			506
Marketing
Disaggregation of Revenue
Revenue	718,921	310,572	292,207
Exploration and production | Natural gas sales
Disaggregation of Revenue
Revenue	3,442,028	1,809,952	2,247,162
Exploration and production | Natural gas liquids sales (ethane)
Disaggregation of Revenue
Revenue	206,889	113,811	124,563
Exploration and production | Natural gas liquids sales (C3+ NGLs)
Disaggregation of Revenue
Revenue	1,940,610	1,047,872	1,094,599
Exploration and production | Oil sales
Disaggregation of Revenue
Revenue	201,232	112,270	177,549
Marketing | Marketing
Disaggregation of Revenue
Revenue	$ 718,921	$ 310,572	$ 292,207

Revenue - Transaction Price All

Revenue - Transaction Price Allocation and Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue
Original expected duration	true
Receivables from contracts with customers	$ 591,442	$ 425,314

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Mar. 13, 2019	Dec. 31, 2018
Investments in unconsolidated affiliates
Equity in earnings of unconsolidated affiliates	$ 77,085	$ (62,660)	$ (143,216)
Dividends from unconsolidated affiliates	(136,609)	(171,022)	(157,956)
Impairment		(610,632)	(467,590)
Balance Sheet
Current assets	686,119	574,139
Total assets	13,896,528	13,150,845	15,197,569
Current liabilities	2,068,117	983,054
Total equity	6,066,092	6,090,271	6,970,743		$ 8,487,477
Total liabilities and equity	13,896,528	13,150,845
Revenues	4,619,432	3,491,699	4,408,690
Operating expenses	4,595,572	4,445,146	5,395,735
Income (loss) from operations	23,860	(953,447)	(987,045)
Net loss including noncontrolling interests	$ (154,109)	$ (1,260,411)	(293,136)
Antero Midstream Corporation
Equity Method Investments
Ownership percentage	29.10%	29.20%		31.00%
Equity Method Investment, Nonconsolidated Investee or Group of Investees | Antero Midstream Corporation
Investments in unconsolidated affiliates
Balance at beginning of period	$ 255,082	$ 1,055,177
Equity in earnings of unconsolidated affiliates	77,085	(62,660)
Dividends from unconsolidated affiliates	(136,609)	(171,022)
Impairment		(610,632)
Elimination of intercompany profit	36,841	44,219
Balance at end of period	232,399	255,082	$ 1,055,177
Fair value of investment	1,300,000	1,100,000
Balance Sheet
Current assets	83,804	93,931
Noncurrent assets	5,460,197	5,516,981
Total assets	5,544,001	5,610,912
Current liabilities	114,009	94,005
Noncurrent liabilities	3,143,294	3,098,621
Total equity	2,286,698	2,418,286
Total liabilities and equity	5,544,001	5,610,912
Revenues	898,202	900,719
Operating expenses	342,875	1,018,357
Income (loss) from operations	555,327	(117,638)
Net loss including noncontrolling interests	$ 331,617	$ (122,527)

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Accrued Liabilities
Capital expenditures	$ 46,983	$ 32,372
Gathering, compression, processing, and transportation expenses	164,900	152,724
Marketing expenses	50,589	68,193
Interest expense, net	65,093	25,645
Accrued production and ad valorem taxes	44,298	37,371
Derivative settlements payable	35,202	3,425
Accrued General and Administrative Expenses, Current	27,740	14,363
Other	22,439	9,431
Total accrued liabilities	$ 457,244	$ 343,524

Long-Term Debt (Details)

Long-Term Debt (Details) $ / shares in Units, $ in Thousands	Jan. 27, 2022USD ($)	Jun. 01, 2021USD ($)	May 13, 2021USD ($)$ / sharesshares	Jan. 26, 2021USD ($)	Jan. 12, 2021USD ($)$ / sharesshares	Jan. 04, 2021USD ($)	Aug. 21, 2020USD ($)Dshares	Mar. 31, 2022USD ($)	Dec. 31, 2021USD ($)	Sep. 30, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Nov. 02, 2021USD ($)	Oct. 18, 2021USD ($)	Jul. 01, 2021USD ($)	Jun. 30, 2021USD ($)	Mar. 31, 2021USD ($)	Sep. 02, 2020USD ($)	Dec. 21, 2016USD ($)	Mar. 17, 2015USD ($)	Sep. 18, 2014USD ($)	May 06, 2014USD ($)
Long-Term Debt
Total principal									$ 2,175,205		$ 2,175,205	$ 3,129,198
Unamortized premium (discount), net									(27,772)		(27,772)	(111,886)
Unamortized debt issuance costs									(21,989)		(21,989)	(15,719)
Long-term debt									2,125,444		2,125,444	3,001,593
Issuance of convertible notes												287,500
Payments of deferred financing costs											31,474	8,984	$ 4,547
Loss on convertible note equitizations											50,777
Gain (loss) on extinguishment of debt repurchased											(93,191)	$ 175,962	$ 36,419
Number of shares of common stock issued (in shares) | shares					31,400,000
Debt Repurchase Program
Long-Term Debt
Weighted average percentage discount on repurchases of debt												13.00%
Principal amount of debt repurchased												$ 1,400,000
Gain (loss) on extinguishment of debt repurchased												176,000
Prior credit facility
Long-Term Debt
Credit facility												$ 1,017,000
Weighted average interest rate (as a percent)												3.26%
Outstanding letters of credit									531,000		$ 531,000	$ 730,000
Prior 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%
Prior 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%
New Credit Facility
Long-Term Debt
Credit facility									0		$ 0
Current borrowing base									3,500,000		3,500,000
Lender commitments									1,500,000		$ 1,500,000
New 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)											0.375%
New 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)											0.50%
Senior notes due in 2021, 2022 and 2023 | Debt Repurchase Program
Long-Term Debt
Weighted average percentage discount on repurchases of debt												10.00%
Principal amount of debt repurchased												$ 367,000
5.125 senior notes due 2022
Long-Term Debt
Senior notes												$ 660,516
Total principal																						$ 500,000	$ 600,000
Interest rate (as a percent)												5.125%											5.125%
Issue price as percentage of par value																						100.50%	100.00%
5.125 senior notes due 2022 | Debt Repurchase Program
Long-Term Debt
Amount of debt repurchased																		$ 661,000
5.625% senior notes due 2023
Long-Term Debt
Senior notes												$ 574,182
Total principal																					$ 750,000
Interest rate (as a percent)												5.625%									5.625%
Issue price as percentage of par value																					100.00%
5.625% senior notes due 2023 | Debt Repurchase Program
Long-Term Debt
Amount of debt repurchased																	$ 574,000
5.00% senior notes due 2025
Long-Term Debt
Senior notes									$ 584,635		$ 584,635	$ 590,000
Total principal																				$ 600,000
Interest rate (as a percent)									5.00%		5.00%	5.00%								5.00%
Issue price as percentage of par value																				100.00%
Redemption price											102.50%
Redemption price at which notes may be required to be repurchased in event of change of control											101.00%
Amount of debt repurchased									$ 15,000		$ 15,000
5.00% senior notes due 2025 | On or after March 1, 2023
Long-Term Debt
Redemption price											100.00%
5.00% senior notes due 2025 | Subsequent event | Forecast
Long-Term Debt
Amount of debt repurchased	$ 585,000
Percentage of redeemed amount	101.25%
Premium on amount received								$ 7,000
8.375% Senior Notes Due 2026
Long-Term Debt
Senior notes						$ 500,000			$ 325,000		$ 325,000
Interest rate (as a percent)						8.375%			8.375%		8.375%
Issue price as percentage of par value						1.00%
Redemption price of the debt instrument in the event of change of control (as a percent)						101.00%
8.375% Senior Notes Due 2026 | Debt Repurchase Program
Long-Term Debt
Amount of debt repurchased									$ 116,000	$ 175,000	$ 116,000					$ 175,000
Gain (loss) on extinguishment of debt repurchased									$ (10,000)	$ (17,000)
Percentage of redeemed amount									107.625%	108.375%
8.375% Senior Notes Due 2026 | On or after January 15, 2024
Long-Term Debt
Redemption price						104.188%
8.375% Senior Notes Due 2026 | On or after January 15, 2026
Long-Term Debt
Redemption price						100.00%
8.375% Senior Notes Due 2026 | Prior to January 15, 2024
Long-Term Debt
Redemption price						100.00%
7.625% Senior Notes Due 2029
Long-Term Debt
Senior notes				$ 700,000					$ 584,000		$ 584,000
Interest rate (as a percent)				7.625%					7.625%		7.625%
Redemption price of the debt instrument in the event of change of control (as a percent)				101.00%
Amount of debt repurchased														$ 116,000	$ 116,000
7.625% Senior Notes Due 2029 | On or after February 1, 2024
Long-Term Debt
Redemption price				103.813%
7.625% Senior Notes Due 2029 | On or after February 1, 2027
Long-Term Debt
Redemption price				100.00%
7.625% Senior Notes Due 2029 | On or before February 1, 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 | Prior to February 1, 2024
Long-Term Debt
Redemption price				100.00%
5.375% senior notes due 2030
Long-Term Debt
Senior notes		$ 600,000							$ 600,000		$ 600,000
Interest rate (as a percent)		5.375%							5.375%		5.375%
Redemption price of the debt instrument in the event of change of control (as a percent)		101.00%
5.375% senior notes due 2030 | On or after March 1, 2025
Long-Term Debt
Redemption price		102.688%
5.375% senior notes due 2030 | On or after March 1, 2028
Long-Term Debt
Redemption price		100.00%
5.375% senior notes due 2030 | On or Before March 1, 2025
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)		105.375%
5.375% senior notes due 2030 | Prior to March 1, 2025
Long-Term Debt
Redemption price		100.00%
4.25% convertible senior notes due 2026
Long-Term Debt
Convertible senior notes									$ 81,570		$ 81,570	$ 287,500
Total principal							$ 250,000												$ 37,500
Unamortized premium (discount), net							$ 116,000		(27,772)		(27,772)	(112,265)
Unamortized debt issuance costs									(1,592)		(1,592)	(5,852)
Long-term debt									$ 52,206		$ 52,206	$ 169,383
Interest rate (as a percent)							4.25%		4.25%		4.25%	4.25%
Issuance of convertible notes							$ 278,500
Payments of deferred financing costs							$ 9,000
Equity component									$ 32,799		$ 32,799	$ 115,601
Conversion rate in shares of Antero Resources' common stock per $1,000 principal amount | shares							230.2026
If-converted value									329,000		329,000
If-converted value above principal amount									$ 247,000		$ 247,000
Effective interest rate (as a percent)							15.10%		15.30%		15.30%
Deferred taxes									$ 8,000		$ 8,000	28,000
Debt issuance cost									$ 1,000		1,000	3,000
Interest expenses											11,000	$ 8,000
Amount of debt converted											206,000
Amount of debt repurchased					$ 150,000
4.25% convertible senior notes due 2026 | January Share Offering
Long-Term Debt
Conversion rate in shares of Antero Resources' common stock per $1,000 principal amount | shares					275.3525
Amount of debt converted					$ 150,000
Loss on convertible note equitizations											39,000
Gain (loss) on extinguishment of debt repurchased											41,000
Line of credit proceeds used to repurchase convertible notes					$ 63,000
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 | May Share Offering
Long-Term Debt
Conversion rate in shares of Antero Resources' common stock per $1,000 principal amount | shares			245.2802
Amount of debt converted			$ 56,000
Loss on convertible note equitizations											12,000
Gain (loss) on extinguishment of debt repurchased											$ 21,000
Line of credit proceeds used to repurchase convertible notes			$ 26,000
Number of shares of common stock issued (in shares) | shares			11,600,000
Share price | $ / shares			$ 11.01
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 | Fair value
Long-Term Debt
Fair value							$ 172,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 54,452	$ 54,845
Obligations incurred	3,208	1,814
Accretion expense	3,820	3,421	$ 3,762
Settlement of obligations	(40)	(229)
Revisions to prior estimates	(7,488)	(5,399)
Asset retirement obligations - end of period	$ 53,952	$ 54,452	$ 54,845

Equity-Based Compensation and_3

Equity-Based Compensation and Cash Awards (Details) - USD ($) $ in Thousands	Jun. 15, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jun. 17, 2020
Stock-based compensation expense
Equity based compensation expense recognized		$ 20,437	$ 23,317	$ 23,559
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		7,922,468
AMP Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized		10,000,000
AMC Plan RSUs
Stock-based compensation expense
Conversion rate		1.8926
RSUs
Stock-based compensation expense
Equity based compensation expense recognized		$ 13,232	12,510	10,343
Stock options
Stock-based compensation expense
Equity based compensation expense recognized				355
PSUs
Stock-based compensation expense
Equity based compensation expense recognized		4,662	7,219	8,069
Converted AM RSU Awards
Stock-based compensation expense
Equity based compensation expense recognized		1,160	2,519	3,425
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized		$ 1,383	$ 1,069	$ 1,367
Antero Midstream Corporation | AMC Plan | Common Stock
Stock-based compensation expense
Conversion rate	1
Antero Midstream Corporation | AMC Plan RSUs
Stock-based compensation expense
Conversion rate	1.8926

Equity-Based Compensation and_4

Equity-Based Compensation and Cash Awards - Restricted Stock and RSU Awards (Details) - RSUs $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)$ / sharesshares
Number of shares
Total awarded and unvested at the beginning of the period (in shares) | shares	8,432,397
Granted (in shares) | shares	1,447,806
Vested (in shares) | shares	(3,622,741)
Forfeited (in shares) | shares	(326,855)
Total awarded and unvested at the end of the period (in shares) | shares	5,930,607
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 4.06
Granted (in dollars per share) | $ / shares	9.63
Vested (in dollars per share) | $ / shares	4.37
Forfeited (in dollars per share) | $ / shares	5.45
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 5.15
Unamortized equity-based compensation expense | $	$ 24
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 6 months

Equity-Based Compensation and_5

Equity-Based Compensation and Cash Awards - Stock Options (Details) - Stock options - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Stock options
Outstanding at the beginning of the period (in shares)	432,461
Options expired (in shares)	(80,667)
Outstanding at the end of the period (in shares)	351,794	432,461
Vested (in shares)	351,794
Exercisable (in shares)	351,794
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.64
Options expired (in dollars per share)	50
Outstanding at the end of the period (in dollars per share)	50.79	$ 50.64
Vested (in dollars per share)	50.79
Exercisable (in dollars per share)	$ 50.79
Weighted average remaining contractual life
Outstanding	3 years	4 years 1 month 6 days
Vested	3 years
Exercisable	3 years
Weighted-average assumptions used to calculate fair value of stock options granted
Dividend yield (as a percent)	0.00%
Maximum
Stock-based compensation
Contractual life	10 years

Equity-Based Compensation and_6

Equity-Based Compensation and Cash Awards - PSU awards (Details) $ / shares in Units, $ in Millions	Apr. 15, 2021	Apr. 30, 2021item	Jul. 31, 2020USD ($)	Jan. 31, 2020USD ($)tranche	Dec. 31, 2021USD ($)item$ / sharesshares	Dec. 31, 2020USD ($)item$ / sharesshares	Dec. 31, 2019$ / shares	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash Awards
Unvested cash awards recorded in other liabilities | $					$ 2	$ 3
2013 Plan
Additional disclosures
Number of tranches | tranche				3
Cash Awards
Cash awards granted | $				$ 3
2020 Plan
Stock-based compensation
Vesting period			4 years
Cash Awards
Cash awards granted | $			$ 3
PSUs
Number of units
Total awarded and unvested at the beginning of the period (in shares) | shares					2,547,798
Granted (in shares) | shares					479,120
Forfeited (in shares) | shares					(67,000)
Cancelled (unearned) | shares					(1,112,639)
Total awarded and unvested at the end of the period (in shares) | shares					1,847,279	2,547,798
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share)					$ 12.66
Granted (in dollars per share)					9.71
Forfeited (in dollars per share)					2.97
Cancelled (unearned) (in dollars per share)					19.19
Total awarded and unvested at the end of the period (in dollars per share)					$ 8.31	$ 12.66
Additional disclosures
Unamortized equity-based compensation expense | $					$ 6
Weighted average period for recognizing unrecognized stock-based compensation expense					1 year 10 months 24 days
Weighted-average assumptions used to calculate fair value of performance share units granted
Volatility (as a percent)					85.00%	80.00%	36.00%
Risk-free interest rate (as a percent)					0.32%	0.17%	2.35%
Weighted average fair value of awards granted-Absolute TSR					$ 11.99	$ 2.63	$ 9.26
Weighted average fair value of awards granted-Absolute Relative TSR						$ 3.30
PSU Awards Based on Absolute TSR
Stock-based compensation
Price target as a percentage of beginning price							125.00%	125.00%
Number of performance periods | item					3	3
Number of cumulative performance periods					1	1
Service period					3 years	3 years	3 years	3 years
Amortization period of PSU expense						3 years		3 years
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent	150.00%
PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent					0.00%	0.00%
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent							0.00%	0.00%
PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent					200.00%	150.00%
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent								200.00%
PSU Awards Based on Absolute TSR | One Year Period
Stock-based compensation
Service period					1 year	1 year
PSU Awards Based on Absolute TSR | Three Year Period
Stock-based compensation
Service period					3 years	3 years
PSU Awards Based On Relative TSR
Stock-based compensation
Number of performance periods | item						3
Number of cumulative performance periods | item						1
Service period						3 years			3 years	3 years
Amortization period of PSU expense						3 years
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent	150.00%								0.00%	0.00%
PSU Awards Based On Relative TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent						0.00%
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent									0.00%	0.00%
PSU Awards Based On Relative TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent						150.00%
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent									200.00%	200.00%
PSU Awards Based On Relative TSR | One Year Period
Stock-based compensation
Service period						1 year
PSU Awards Based On Relative TSR | Three Year Period
Stock-based compensation
Service period						3 years
PSU Awards Based On Leverage Ratio
Stock-based compensation
Number of performance periods | item		3
Service period		1 year
PSU Awards Based On Leverage Ratio | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent		0.00%
PSU Awards Based On Leverage Ratio | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent		200.00%
Price target performance share unit awards
Stock-based compensation
Number of successive days closing stock price must achieve specific thresholds for PSUs to vest per schedule										10 days
Service period										3 years
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent										33.33%
Price target performance share unit awards | Vesting before first anniversary
Stock-based compensation
Number of PSUs that may vest, as a percent										0.00%
Price target performance share unit awards | Vesting before the second anniversary | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent										33.33%
Price target performance share unit awards | Vesting before the third anniversary | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent										66.67%
TSR performance share unit awards | Maximum
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent					200.00%
ROCE performance share unit awards
Stock-based compensation
Service period								3 years
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent								0.00%
ROCE performance share unit awards | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent								0.00%
ROCE performance share unit awards | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent								200.00%

Equity-Based Compensation and_7

Equity-Based Compensation and Csah Awards - Converted AM RSU Awards (Details) - Converted AM RSU Awards $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)$ / sharesshares
Number of units
Total awarded and unvested at the beginning of the period (in shares) | shares	296,390
Vested (in shares) | shares	(209,964)
Forfeited (in shares) | shares	(4,719)
Total awarded and unvested at the end of the period (in shares) | shares	81,707
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 15.06
Vested (in dollars per share) | $ / shares	15.73
Forfeited (in dollars per share) | $ / shares	13.25
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 13.46
Unamortized equity-based compensation expense | $	$ 0.4
Weighted average period for recognizing unrecognized stock-based compensation expense	3 months 18 days

Fair Value (Details)

Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Jun. 01, 2021	Jan. 26, 2021	Jan. 04, 2021	Dec. 31, 2020	Aug. 21, 2020	Dec. 21, 2016	Mar. 17, 2015	May 06, 2014
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%		5.00%
8.375% Senior Notes Due 2026
Financial Instruments
Interest rate (as a percent)	8.375%			8.375%
7.625% Senior Notes Due 2029
Financial Instruments
Interest rate (as a percent)	7.625%		7.625%
5.375% senior notes due 2030
Financial Instruments
Interest rate (as a percent)	5.375%	5.375%
4.25% convertible senior notes due 2026
Financial Instruments
Interest rate (as a percent)	4.25%				4.25%	4.25%
Debt Instrument, Convertible, Carrying Amount of Equity Component	$ 32,799				$ 115,601
Fair value | Level 2 market data
Financial Instruments
Value	2,592,014				2,212,629
Fair value | Level 2 market data | 5.125 senior notes due 2022
Financial Instruments
Value					658,468
Fair value | Level 2 market data | 5.625% senior notes due 2023
Financial Instruments
Value					562,698
Fair value | Level 2 market data | 5.00% senior notes due 2025
Financial Instruments
Value	594,866				560,500
Fair value | Level 2 market data | 8.375% Senior Notes Due 2026
Financial Instruments
Value	370,013
Fair value | Level 2 market data | 7.625% Senior Notes Due 2029
Financial Instruments
Value	654,080
Fair value | Level 2 market data | 5.375% senior notes due 2030
Financial Instruments
Value	641,400
Fair value | Level 2 market data | 4.25% convertible senior notes due 2026
Financial Instruments
Value	331,655				430,963
Carrying value
Financial Instruments
Value	2,125,444				1,984,593
Carrying value | 5.125 senior notes due 2022
Financial Instruments
Value					658,400
Carrying value | 5.625% senior notes due 2023
Financial Instruments
Value					571,370
Carrying value | 5.00% senior notes due 2025
Financial Instruments
Value	581,117				585,440
Carrying value | 8.375% Senior Notes Due 2026
Financial Instruments
Value	321,738
Carrying value | 7.625% Senior Notes Due 2029
Financial Instruments
Value	577,149
Carrying value | 5.375% senior notes due 2030
Financial Instruments
Value	593,234
Carrying value | 4.25% convertible senior notes due 2026
Financial Instruments
Value	$ 52,206				$ 169,383

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details)	Dec. 31, 2021MMBTU / dbbl / d$ / MMBTU$ / bbl
Swaption Agreement
Derivative Instruments
Notional amount | MMBTU / d	427,500
Fixed price ($/MMBtu) | $ / MMBTU	2.77
Put option | Year ending December 31, 2026
Derivative Instruments
Notional amount | MMBTU / d	88,748,000
Weighted average strike price | $ / MMBTU	2.55
Natural gas. | NYMEX to TCO | January-December 2022
Derivative Instruments
Notional amount | MMBTU / d	60,000
Weighted average hedged differential | $ / MMBTU	0.515
Natural gas. | NYMEX to TCO | January-December 2023
Derivative Instruments
Notional amount | MMBTU / d	50,000
Weighted average hedged differential | $ / MMBTU	0.525
Natural gas. | NYMEX to TCO | January-December 2024
Derivative Instruments
Notional amount | MMBTU / d	50,000
Weighted average hedged differential | $ / MMBTU	0.530
Swaps | Natural gas. | Henry Hub | January-December 2022
Derivative Instruments
Notional amount | MMBTU / d	1,155,486
Weighted average index price | $ / MMBTU	2.50
Swaps | Natural gas. | Henry Hub | January-December 2022 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	38,356
Weighted average index price | $ / MMBTU	2.39
Swaps | Natural gas. | Henry Hub | January-December 2023
Derivative Instruments
Notional amount | MMBTU / d	43,000
Weighted average index price | $ / MMBTU	2.37
Swaps | Natural gas. | Henry Hub | January-December 2023 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	35,616
Weighted average index price | $ / MMBTU	2.35
Swaps | Natural gas. | Henry Hub | January-December 2024 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	23,885
Weighted average index price | $ / MMBTU	2.33
Swaps | Natural gas. | Henry Hub | January-March 2025 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	18,021
Weighted average index price | $ / MMBTU	2.53
Swaps | Natural gas. | Mont Belvieu Natural Gasoline-OPIS Non-TET | January-December 2022 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	282
Weighted average index price | $ / bbl	34.37
Swaps | Natural gas. | Mont Belvieu Natural Gasoline-OPIS Non-TET | January-December 2023 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	247
Weighted average index price | $ / bbl	40.74
Swaps | Ethane | Mont Belvieu Purity Ethane-OPIS | January-March 2022 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	521
Weighted average index price | $ / bbl	6.68
Swaps | Propane | Mont Belvieu Propane OPIS Non TET | January-December 2023 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	934
Weighted average index price | $ / bbl	19.20
Swaps | Oil | West Texas Intermediate | January-December 2022 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	112
Weighted average index price | $ / bbl	43.51
Swaps | Oil | West Texas Intermediate | January-December 2023 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	99
Weighted average index price | $ / MMBTU	44.88
Swaps | Oil | West Texas Intermediate | January-December 2024 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	43
Weighted average index price | $ / MMBTU	44.02
Swaps | Oil | West Texas Intermediate | January-March 2025 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	39
Weighted average index price | $ / MMBTU	45.06

Derivative Instruments (Details

Derivative Instruments (Details)	Dec. 31, 2021MMBTU / d$ / MMBTU
Put option | Year ending December 31, 2026
Derivative Instruments
Notional amount | MMBTU / d	88,748,000
Weighted average strike price | $ / MMBTU	2.55
Natural gas. | NYMEX to TCO | January-December 2022
Derivative Instruments
Notional amount | MMBTU / d	60,000
Weighted average hedged differential | $ / MMBTU	0.515
Natural gas. | NYMEX to TCO | January-December 2023
Derivative Instruments
Notional amount | MMBTU / d	50,000
Weighted average hedged differential | $ / MMBTU	0.525
Natural gas. | NYMEX to TCO | January-December 2024
Derivative Instruments
Notional amount | MMBTU / d	50,000
Weighted average hedged differential | $ / MMBTU	0.530

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 757	$ 105,130
Noncurrent portion of fair value of derivative assets	14,369	47,293
Current portion of fair value of derivative liabilities	559,851	31,242
Noncurrent portion of fair value of derivative liabilities	181,806	99,172
Net fair value of commodity derivative assets position
Fair value of derivative instruments
Total asset derivatives		111,833
Total liability derivatives	741,657	130,414
Embedded derivatives
Fair value of derivative instruments
Total asset derivatives	15,126	40,590
Derivatives not designated as hedges for accounting purposes
Fair value of derivative instruments
Total asset derivatives	15,126	152,423
Total liability derivatives	741,657	130,414
Net derivatives assets (liabilities)	(726,531)	22,009
Derivatives not designated as hedges for accounting purposes | Net fair value of commodity derivative assets position
Fair value of derivative instruments
Current portion of fair value of derivative assets		97,144
Noncurrent portion of fair value of derivative assets		14,689
Current portion of fair value of derivative liabilities	559,851	31,242
Noncurrent portion of fair value of derivative liabilities	181,806	99,172
Derivatives not designated as hedges for accounting purposes | Net fair value of commodity derivative assets position | VIE, Martica
Fair value of derivative instruments
Current portion of fair value of derivative liabilities	31,000	7,000
Noncurrent portion of fair value of derivative liabilities	24,000	7,000
Total liability derivatives	55,000	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	757	7,986
Noncurrent portion of fair value of derivative assets	$ 14,369	$ 32,604

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Net fair value of commodity derivative assets position
Commodity derivative assets
Gross amounts on balance sheet	$ 2,177	$ 181,375
Gross amounts offset on balance sheet	(2,177)	(69,542)
Total asset derivatives		111,833
Commodity derivative liabilities
Gross amounts on balance sheet	(743,834)	(199,956)
Gross amounts offset on balance sheet	2,177	69,542
Total liability derivatives	(741,657)	(130,414)
Embedded derivatives
Commodity derivative assets
Gross amounts on balance sheet	15,126	40,590
Total asset derivatives	$ 15,126	$ 40,590

Derivative Instruments - Fair_2

Derivative Instruments - Fair value gains (losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	$ (1,936,509)	$ 79,918	$ 463,972
Commodity derivative fair value gains (losses) on derivatives monetized prior to settlement dates	(5,000)	9,000	0
Net fair value of commodity derivative assets position | Revenue.
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	(1,886,551)	40,565	$ 463,972
Embedded derivatives | Revenue.
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	$ (49,958)	$ 39,353

Leases (Details)

Leases (Details)	12 Months Ended
	Dec. 31, 2021
Leases
Options to renew - Operating lease	true
Minimum
Leases
Renewal terms - Operating lease	1 year
Maximum
Leases
Renewal terms - Operating lease	20 years

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information Related to Leases (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Lease Assets
Operating leases right-of-use assets	$ 3,419,912	$ 2,613,603
Short-term operating lease obligation	$ 455,950	$ 265,178
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Current	Operating And Finance Lease Liability Current
Long-term operating lease obligation	$ 2,963,962	$ 2,348,425
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Noncurrent	Operating And Finance Lease Liability Noncurrent
Total operating lease obligation	$ 3,419,912	$ 2,613,603
Finance leases, right of use assets	550	1,206
Short-term finance lease obligation	$ 397	$ 845
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Current	Operating And Finance Lease Liability Current
Long-term finance lease obligation	$ 153	$ 361
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Operating And Finance Lease Liability Noncurrent	Operating And Finance Lease Liability Noncurrent
Total finance lease obligation	$ 550	$ 1,206
Finance leases, accumulated amortization	2,000	3,000
Vehicles
Lease Assets
Operating leases right-of-use assets	$ 2,009	$ 2,704
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets
Finance leases, right of use assets	$ 550	$ 1,206
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 leases right-of-use assets	$ 482	$ 746
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets
Processing plants
Lease Assets
Operating leases right-of-use assets	$ 1,739,550	$ 1,302,290
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets
Drilling rigs and completion services
Lease Assets
Operating leases right-of-use assets	$ 9,860	$ 29,894
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets
Gas gathering lines and compressor stations
Lease Assets
Operating leases right-of-use assets	$ 1,634,928	$ 1,241,090
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets
Gas gathering lines and compressor stations | Antero Midstream Corporation
Lease Assets
Operating leases right-of-use assets	$ 1,500,000	$ 1,100,000
Office space
Lease Assets
Operating leases right-of-use assets	$ 33,083	$ 36,879
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Operating leases right-of-use assets	Operating leases right-of-use assets

Leases - Supplemental Informati

Leases - Supplemental Information Related to Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2019
Leases
Total operating lease cost	$ 1,637,302	$ 1,622,425	$ 1,058,882
Total finance lease cost	522	1,080	1,806
Short-term lease payments	86,039	122,577	162,654
Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases	1,352,941	1,576,984	809,667
Cash paid for amounts included in the measurement of lease liabilities: Investing cash flows from operating leases	88,910	106,867	178,898
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: Financing cash flows from finance leases	859	1,291	2,507
Right-of-use assets obtained in exchange for new operating lease obligations	437,045	202,125	3,720,945
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net	$ 702,512	$ (173,563)	$ (681,686)
Weighted average discount rate for remeasured operating leases (as a percent)		14.40%	10.00%	6.00%
Weighted average discount rate for new operating leases (as a percent)	5.00%	14.40%	12.40%
Proved properties
Leases
Total operating lease cost	$ 103,741	$ 104,146	$ 194,522
Gathering, compression, water handling and treatment, processing, and transportation
Leases
Total operating lease cost	1,518,305	1,498,221	842,440
General and administrative.
Leases
Total operating lease cost	10,901	11,530	11,228
Contract termination and rig stacking
Leases
Total operating lease cost	4,213	8,528	10,692
Lease operating.
Leases
Total operating lease cost	142
Depletion, Depreciation, And Amortization
Leases
Amortization of right-of-use assets	$ 522	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, 2021	Dec. 31, 2020
Future minimum payments for operating lease liabilities
2022	$ 634,632
2023	622,266
2024	612,344
2025	540,291
2026	489,589
Thereafter	1,386,882
Total lease payments	4,286,004
Less: imputed interest	(866,092)
Total operating lease obligation	3,419,912	$ 2,613,603
Future minimum payments for financing lease liabilities
2022	424
2023	76
2024	67
2025	22
Total lease payments	589
Less: imputed interest	(39)
Total finance lease obligation	550	$ 1,206
Future minimum payments for total lease liabilities
2022	635,056
2023	622,342
2024	612,411
2025	540,313
2026	489,589
Thereafter	1,386,882
Total lease payments	4,286,593
Less: imputed interest	(866,131)
Total	$ 3,420,462

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2021	Dec. 31, 2020
Leases
Weighted-average remaining lease term: Operating lease	7 years 7 months 6 days	8 years
Weighted-average discount rate: Operating lease	5.50%	13.70%
Weighted-average remaining lease term: Finance lease	1 year 10 months 24 days	1 year 6 months
Weighted-average discount rate: Finance lease	5.60%	6.20%

Leases - Related Party Lease Di

Leases - Related Party Lease Disclosure (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases
Accounts payable, related parties	$ 76,240	$ 76,240	$ 69,860
Antero Midstream Corporation
Leases
Minimum volume commitments that require Antero to utilize or pay certain percentage of the capacity of new construction for high pressure lines (as a percent)		75.00%
Minimum volume commitments that require Antero to utilize or pay certain percentage of the capacity of new construction of compressor stations (as a percent)		70.00%
Term of lease	10 years	10 years
Notice period		180 days
Rebate received	$ 12,000		48,000
Gathering and compression fees paid		$ 705,000	679,000	$ 643,000
Accounts payable, related parties	$ 54,000	$ 54,000	$ 55,000
Percentage of rate of return	13.00%	13.00%
Term for rate of return on constructions		7 years

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income tax expense from continuing operations
Current income tax expense (benefit)	$ 216	$ (209)	$ 5,048
Deferred income tax benefit	(74,293)	(397,273)	(79,158)
Total income tax benefit	$ (74,077)	$ (397,482)	$ (74,110)
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)	$ (47,919)	$ (348,158)	$ (77,122)
State income tax expense (benefit), net of federal benefit	(6,576)	(50,584)	(8,826)
Change in State tax rate, net of federal effect	(30,910)	2,291	24,041
Nondeductible equity-based compensation	1,117	4,490	6,920
Dividends received deduction	(3,832)	(4,013)	(4,201)
Noncontrolling interest	(7,862)	(1,801)	(10,998)
Deconsolidation adjustment			(6,626)
Change in valuation allowance	4,606	789	1,325
Nondeductible loss on 2026 Convertible Notes equitization	12,174
Other	5,125	(496)	1,377
Total income tax benefit	(74,077)	(397,482)	$ (74,110)
Deferred tax assets:
NOL carryforwards	569,523	565,433
Equity-based compensation	2,462	8,445
Investment in Antero Midstream	297,893	330,301
Unrealized losses on derivative instruments	158,779
Asset retirement obligations and other	15,051	17,206
Total deferred tax assets	1,043,708	921,385
Valuation allowance	(50,304)	(46,013)
Net deferred tax assets	993,404	875,372
Valuation allowance	50,304	46,013
Deferred tax liabilities:
Unrealized gains on derivative instruments		13,189
Oil and gas properties	1,254,182	1,188,599
Investment in Martica	51,166	59,586
2026 Convertible Notes and other	6,182	26,250
Total deferred tax liabilities	1,311,530	1,287,624
Net deferred tax liabilities	$ (318,126)	$ (412,252)

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) $ in Billions	Dec. 31, 2021USD ($)
Unrecognized tax benefits
Unrecognized tax benefits	$ 0
U.S Federal
Income Taxes
Net operating loss carryforward	2.3
State
Income Taxes
Net operating loss carryforward	$ 2

Commitments (Details)

Commitments (Details) $ in Thousands	Dec. 31, 2021USD ($)
Future minimum payments
2022	$ 1,730,962
2023	1,754,005
2024	1,717,115
2025	1,613,056
2026	1,523,184
Thereafter	7,518,616
Total	15,856,938
Firm transportation
Future minimum payments
2022	1,042,280
2023	1,072,523
2024	1,045,442
2025	1,024,783
2026	1,018,812
Thereafter	6,033,138
Total	11,236,978
Gas processing, gathering and compression
Future minimum payments
2022	52,265
2023	59,140
2024	59,262
2025	47,960
2026	14,783
Thereafter	98,596
Total	332,006
Land payment obligations
Future minimum payments
2022	1,361
Total	1,361
Operating and Financing Leases
Future minimum payments
2022	456,345
2023	466,960
2024	481,688
2025	433,507
2026	404,381
Thereafter	1,177,581
Total	3,420,462
Imputed Interest for Leases
Future minimum payments
2022	178,711
2023	155,382
2024	130,723
2025	106,806
2026	85,208
Thereafter	209,301
Total	$ 866,131

Contingencies (Details)

Contingencies (Details) $ in Millions	Jun. 20, 2019USD ($)	Feb. 28, 2021USD ($)	Dec. 31, 2019USD ($)	Jun. 30, 2019lawsuit	Mar. 31, 2017USD ($)
SJGC | Settled Litigation
Contingencies
Settlement amount received			$ 82
WGL | Settled Litigation
Contingencies
Damages awarded	$ 96
WGL | Pending Litigation
Contingencies
Number of lawsuits | lawsuit				2
WGL | Pending Litigation | Minimum
Contingencies
Damages sought					$ 40
WGL | Judicial Ruling
Contingencies
Settlement amount received		$ 107

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Sales and revenues:
Sales and revenues - Third-party	$ 4,618,407	$ 3,488,902	$ 4,400,102
Sales and revenues - Intersegment	1,025	2,797	8,588
Revenues	4,619,432	3,491,699	4,408,690
Operating expenses:
Lease operating	96,793	98,865	145,720
General and administrative	145,006	134,482	178,696
Depletion, depreciation, and amortization	742,009	861,870	914,867
Impairment of oil and gas properties	90,523	223,770	1,300,444
Impairment of midstream assets			14,782
Other	1,022,067	595,321	694,579
Total operating expenses	4,595,572	4,445,146	5,395,735
Operating income (loss)	23,860	(953,447)	(987,045)
Equity in earnings of unconsolidated affiliates	77,085	(62,660)	(143,216)
Investments in unconsolidated affiliates	232,399	255,082	1,055,177
Segment assets	13,896,528	13,150,845	15,197,569
Capital expenditures for segment assets	715,936	874,357	1,422,155
Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	2,499,174	2,530,838	2,146,647
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues - Third-party	3,899,486	3,178,330	4,107,845
Sales and revenues - Intersegment	1,025	2,797	5,812
Revenues	3,900,511	3,181,127	4,113,657
Operating expenses:
Lease operating	96,793	98,865	146,990
General and administrative	145,006	134,482	160,402
Depletion, depreciation, and amortization	742,009	861,870	893,161
Impairment of oil and gas properties	90,523	223,770	1,300,444
Other	210,369	125,917	143,762
Total operating expenses	3,783,874	3,975,742	4,901,858
Operating income (loss)	116,637	(794,615)	(788,201)
Equity in earnings of unconsolidated affiliates	77,085	(62,660)
Investments in unconsolidated affiliates	232,399	255,082
Segment assets	13,864,402	13,150,845	14,121,523
Capital expenditures for segment assets	715,936	874,357	1,369,003
Operating segments | Exploration and production | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	2,499,174	2,530,838	2,257,099
Operating segments | Marketing
Sales and revenues:
Sales and revenues - Third-party	718,921	310,572	292,207
Revenues	718,921	310,572	292,207
Operating expenses:
Other	811,698	469,404	549,814
Total operating expenses	811,698	469,404	549,814
Operating income (loss)	(92,777)	(158,832)	(257,607)
Segment assets	32,126		20,869
Operating segments | Antero Midstream Corporation
Sales and revenues:
Sales and revenues - Third-party			50
Sales and revenues - Intersegment	898,202	900,719	792,538
Revenues	898,202	900,719	792,588
Operating expenses:
Lease operating			162,376
General and administrative	63,838	52,213	118,113
Depletion, depreciation, and amortization	108,790	108,790	95,526
Impairment of midstream assets		673,640	776,832
Other	13,127	18,328	12,093
Total operating expenses	342,875	1,018,357	1,205,953
Operating income (loss)	555,327	(117,638)	(413,365)
Equity in earnings of unconsolidated affiliates	90,451	86,430	51,315
Investments in unconsolidated affiliates	696,009		709,639
Segment assets	5,544,001	5,610,912	6,282,878
Capital expenditures for segment assets	232,825	196,724	391,990
Operating segments | Antero Midstream Corporation | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	157,120	165,386	41,013
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues - Intersegment	(898,202)	(900,719)	(789,762)
Revenues	(898,202)	(900,719)	(789,762)
Operating expenses:
Lease operating			(163,646)
General and administrative	(63,838)	(52,213)	(99,819)
Depletion, depreciation, and amortization	(108,790)	(108,790)	(73,820)
Impairment of midstream assets		(673,640)	(762,050)
Other	(13,127)	(18,328)	(11,090)
Total operating expenses	(342,875)	(1,018,357)	(1,261,890)
Operating income (loss)	(555,327)	117,638	472,128
Equity in earnings of unconsolidated affiliates	(90,451)	(86,430)	(194,531)
Investments in unconsolidated affiliates	(696,009)		345,538
Segment assets	(5,544,001)	(5,610,912)	(5,227,701)
Capital expenditures for segment assets	(232,825)	(196,724)	(338,838)
Elimination of intersegment transaction | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	$ (157,120)	$ (165,386)	$ (151,465)

Subsidiary Guarantors - Balance

Subsidiary Guarantors - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Other current assets	$ 14,922	$ 15,238
Total current assets	686,119	574,139
Total assets	13,896,528	13,150,845	$ 15,197,569
Liabilities and Stockholders' Equity
Accounts payable, non-guarantor subsidiaries	76,240	69,860
Other current liabilities	11,140	2,302
Total current liabilities	2,068,117	983,054
Total liabilities	7,830,436	$ 7,060,574
Parent (Antero) And Guarantor Subsidiaries
Current assets:
Other current assets	633,014
Total current assets	633,014
Noncurrent assets	12,480,350
Total assets	13,113,364
Liabilities and Stockholders' Equity
Accounts payable, related parties	76,240
Other current liabilities	1,961,041
Total current liabilities	2,037,281
Noncurrent liabilities	5,737,999
Total liabilities	$ 7,775,280

Subsidiary Guarantors - Stateme

Subsidiary Guarantors - Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed consolidated statement of operations and comprehensive income (loss)
Revenues	$ 6,509,680	$ 3,394,477	$ 3,940,558
Operating expenses	4,595,572	4,445,146	5,395,735
Loss from operations	23,860	(953,447)	(987,045)
Net income and comprehensive income including noncontrolling interests	(154,109)	(1,260,411)	(293,136)
Net income and comprehensive income attributable to Antero Resources Corporation	(186,899)	$ (1,267,897)	$ (340,129)
Parent (Antero) And Guarantor Subsidiaries
Condensed consolidated statement of operations and comprehensive income (loss)
Revenues	4,545,912
Operating expenses	4,561,383
Loss from operations	(15,471)
Net income and comprehensive income including noncontrolling interests	(186,899)
Net income and comprehensive income attributable to Antero Resources Corporation	$ (186,899)

Supplemental Information on O_3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 12,646,303	$ 12,260,713
Unproved properties	1,042,118	1,175,178
Total oil and gas properties	13,688,421	13,435,891
Accumulated depletion	(4,229,300)	(3,818,279)
Net capitalized costs	9,459,121	9,617,612
Costs Incurred in Certain Oil and Gas Activities
Unproved property	79,138	45,129	$ 88,682
Development costs	581,352	823,271	1,104,336
Exploration costs	19,822	2,993	149,782
Total costs incurred	680,312	871,393	1,342,800
Results of Operations for Oil and Gas Producing Activities
Revenues	5,790,759	3,083,905	3,643,873
Operating expenses:
Production expenses	2,793,877	2,736,478	2,417,509
Exploration expenses	1,164	1,083	884
Depletion	735,687	854,331	884,350
Impairment of unproved properties	90,523	223,770	1,300,444
Results of operations before income tax (expense) benefit	2,169,508	(731,757)	(959,314)
Income tax (expense) benefit	520,168	(176,061)	224,511
Results of operations	$ 2,689,676	$ (907,818)	$ (734,803)

Supplemental Information on O_4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details)	12 Months Ended
	Dec. 31, 2021BcfeBcfMMBbls	Dec. 31, 2020BcfeMMBblsBcf	Dec. 31, 2019BcfeMMBblsBcf
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcfe	17,635	18,893	18,011
Revisions | Bcfe	1,486	(940)	(1,648)
Extensions, discoveries and other additions | Bcfe	472	1,105	3,705
Production | Bcfe	(1,194)	(1,310)	(1,175)
Sales | Bcfe	(670)	(113)
Balance at the end of the period | Bcfe	17,729	17,635	18,893
Oil and Gas Reserves
Proved developed reserves | Bcfe	12,753	11,873	11,740
Proved undeveloped reserves | Bcfe	4,976	5,762	7,153
VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcfe	254
Balance at the end of the period | Bcfe	167	254
Oil and Gas Reserves
Proved developed reserves | Bcfe	133	181
Proved undeveloped reserves | Bcfe	34	73
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	10,025	11,494	11,425
Revisions | Bcf	993	(1,280)	(1,735)
Extensions, discoveries and other additions | Bcf	349	799	2,626
Production | Bcf	(826)	(875)	(822)
Sales | Bcf	(337)	(113)
Balance at the end of the period | Bcf	10,204	10,025	11,494
Oil and Gas Reserves
Proved developed reserves | Bcf	7,395	6,901	7,229
Proved undeveloped reserves | Bcf	2,809	3,124	4,265
Natural gas | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	159
Balance at the end of the period | Bcf	101	159
Oil and Gas Reserves
Proved developed reserves | Bcf	78	110
Proved undeveloped reserves | Bcf	23	49
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	1,236	1,191	1,052
Revisions	77	65	25
Extensions, discoveries and other additions	18	48	169
Production	(58)	(68)	(55)
Sales	(54)
Balance at the end of the period	1,219	1,236	1,191
Oil and Gas Reserves
Proved developed reserves	876	810	731
Proved undeveloped reserves	343	426	460
NGLS | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period	15
Balance at the end of the period	11	15
Oil and Gas Reserves
Proved developed reserves	9	11
Proved undeveloped reserves	2	4
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	33	42	46
Revisions	6	(8)	(11)
Extensions, discoveries and other additions	2	3	11
Production	(4)	(4)	(4)
Sales	(1)
Balance at the end of the period	36	33	42
Oil and Gas Reserves
Proved developed reserves	17	19	21
Proved undeveloped reserves	19	14	21
Oil and condensate | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period	0.5
Balance at the end of the period	0.4	0.5
Oil and Gas Reserves
Proved developed reserves	0.2	0.3
Proved undeveloped reserves	0.2	0.2

Supplemental Information on O_5

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes In Reserves (Details) - Bcfe	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Extensions, discoveries and other additions	472	1,105	3,705
Revisions	1,486	(940)	(1,648)
Time period of the development plan	5 years	5 years	5 years
Increase (decrease) in proved reserves due to development plan revisions			(1,705)
Increase in proved reserves due to additions to development plan	1,475		595
Decrease in proved reserves due to reclassifications related to five-year rule	(824)	(922)	(2,300)
Increase In Proved Reserve Due To Improved Well Performance	565	491	63
Increase (decrease) in proved reserves resulting from price revisions	149	(1,126)	(157)
Increase Decrease In Proved Reserve Due To Ethane Recovery	121	485	315
Increase (decrease) in proved undeveloped properties reclassified from non-proved to proved undeveloped	651	132
Increase Decrease In Proved Reserve Due To Deconsolidation Of Equity Method Investment			(164)
Sales of reserves	670	113

Supplemental Information on O_6

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Discounted future cash flows (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Oil and gas reserves
Future cash inflows computation period	12 months	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	$ 74,622	$ 37,845	$ 54,228
Future production costs	(34,665)	(32,202)	(36,524)
Future development costs	(1,704)	(1,685)	(2,772)
Future net cash flows before income tax	38,253	3,958	14,932
Future income tax expense	(7,813)		(1,639)
Future net cash flows	30,440	3,958	13,293
10% annual discount for estimated timing of cash flows	(17,007)	(2,748)	(7,824)
Standardized measure of discounted future net cash flows	13,433	1,210	$ 5,469	$ 10,478
VIE, Martica
Annual net cash inflows
Standardized measure of discounted future net cash flows	$ 501	$ 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 Millions	12 Months Ended
	Dec. 31, 2021USD ($)$ / Mcfe	Dec. 31, 2020USD ($)$ / Mcfe	Dec. 31, 2019USD ($)$ / Mcfe
Reserve Quantities [Line Items]
12-month weighted average price (in dollars per Mcfe | $ / Mcfe	4.21	2.15	2.87
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs	$ (2,917)	$ (347)	$ (1,116)
Net changes in prices and production costs	14,099	(5,455)	(6,729)
Development costs incurred during the period	454	704	758
Net changes in future development costs	(117)	249	(92)
Extensions, discoveries and other additions	504	31	782
Divestitures	(125)	(174)
Revisions of previous quantity estimates	2,543	(379)	(1,011)
Accretion of discount	121	607	1,259
Net change in income taxes	(3,115)	598	1,513
Changes in timing and other	776	(93)	(373)
Net decrease	12,223	(4,259)	(5,009)
Beginning of year	1,210	5,469	10,478
End of year	13,433	1,210	5,469
Increased production costs			3,300
Increased future development costs			$ 185
VIE, Martica
Changes in Standardized Measure of Discounted Future Net Cash Flow
Beginning of year	359
End of year	$ 501	$ 359