Antero Resources (AR) 10-K 14 Feb 24 2023 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) shares in Thousands, $ in Billions	12 Months Ended
	Dec. 31, 2023	Feb. 09, 2024	Jun. 30, 2023
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
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	Yes
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
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
ICFR Auditor Attestation Flag	true
Entity Common Stock, Shares Outstanding		303,568
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001433270
Amendment Flag	false
Entity Public Float			$ 5.4
Auditor Name	KPMG LLP
Auditor Firm ID	185
Auditor Location	Denver

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Accounts receivable	$ 42,619	$ 35,488
Accrued revenue	400,805	707,685
Derivative instruments	5,175	1,900
Prepaid expenses	12,901	10,580
Other current assets	14,192	31,872
Total current assets	475,692	787,525
Oil and gas properties, at cost (successful efforts method):
Unproved properties	974,642	997,715
Proved properties	13,908,804	13,234,777
Gathering systems and facilities	5,802	5,802
Other property and equipment	98,668	83,909
Property and equipment, gross	14,987,916	14,322,203
Less accumulated depletion, depreciation and amortization	(5,063,274)	(4,683,399)
Property and equipment, net	9,924,642	9,638,804
Operating leases right-of-use assets	2,965,880	3,444,331
Derivative instruments	5,570	9,844
Investment in unconsolidated affiliate	222,255	220,429
Other assets	25,375	17,106
Total assets	13,619,414	14,118,039
Current liabilities:
Accrued liabilities	381,340	461,788
Revenue distributions payable	361,782	468,210
Derivative instruments	15,236	97,765
Short-term lease liabilities	540,060	556,636
Deferred revenue, VPP	27,101	30,552
Other current liabilities	1,295	1,707
Total current liabilities	1,452,091	1,774,909
Long-term liabilities:
Long-term debt	1,537,596	1,183,476
Deferred income tax liability, net	834,268	759,861
Derivative instruments	32,764	345,280
Long-term lease liabilities	2,428,450	2,889,854
Deferred revenue, VPP	60,712	87,813
Other liabilities	59,431	59,692
Total liabilities	6,405,312	7,100,885
Commitments and contingencies
Equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued
Common stock, $0.01 par value; authorized - 1,000,000 shares; 297,393 shares issued and 297,359 shares outstanding as of December 31, 2022, and 303,544 shares issued and outstanding as of December 31, 2023	3,035	2,974
Additional paid-in capital	5,846,541	5,838,848
Retained earnings	1,131,828	913,896
Treasury stock, at cost; 34 shares and zero shares as of December 31, 2022 and 2023, respectively		(1,160)
Total stockholders' equity	6,981,404	6,754,558
Noncontrolling interests	232,698	262,596
Total equity	7,214,102	7,017,154
Total liabilities and equity	13,619,414	14,118,039
Affiliated Entity
Current liabilities:
Accounts payable	86,284	80,708
Nonrelated Party
Current liabilities:
Accounts payable	$ 38,993	$ 77,543

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares shares in Thousands	Dec. 31, 2023	Dec. 31, 2022
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	303,544	297,393
Common stock, shares outstanding	303,544	297,359
Treasury stock, shares	0	34

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenue and other:
Total revenue	$ 4,681,972	$ 7,138,436	$ 4,619,432
Operating expenses:
Lease operating	118,441	99,595	96,793
Production and ad valorem taxes	158,855	287,406	197,910
General and administrative (including equity-based compensation expense of $20,437, $35,443 and $59,519 in 2021, 2022 and 2023, respectively)	224,516	172,909	145,006
Depletion, depreciation and amortization	689,966	680,600	742,009
Impairment of property and equipment	51,302	149,731	90,523
Accretion of asset retirement obligations	3,244	4,627	3,820
Contract termination and loss contingency	52,606	25,099	4,305
Loss (gain) on sale of assets	(447)	471	(2,232)
Other operating expense	336
Total operating expenses	4,228,842	4,564,531	4,595,572
Operating income	453,130	2,573,905	23,860
Other income (expense):
Interest expense, net	(117,870)	(125,372)	(181,868)
Equity in earnings of unconsolidated affiliate	82,952	72,327	77,085
Loss on early extinguishment of debt		(46,027)	(93,191)
Loss on convertible note inducements and equitizations	(374)	(169)	(50,777)
Transaction expense			(3,295)
Total other expense	(35,292)	(99,241)	(252,046)
Income (loss) before income taxes	417,838	2,474,664	(228,186)
Income tax benefit (expense)	(75,994)	(448,692)	74,077
Net income (loss) and comprehensive income (loss) including noncontrolling interests	341,844	2,025,972	(154,109)
Less: net income and comprehensive income attributable to noncontrolling interests	98,925	127,201	32,790
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 242,919	$ 1,898,771	$ (186,899)
Net income (loss) per common share-basic (in dollars per share)	$ 0.81	$ 6.18	$ (0.61)
Net income (loss) per common share-diluted (in dollars per share)	$ 0.78	$ 5.78	$ (0.61)
Weighted average number of common shares outstanding:
Basic (in shares)	299,793	307,202	308,146
Diluted (in shares)	311,597	329,223	308,146
Natural gas sales
Revenue and other:
Total revenue	$ 2,192,349	$ 5,520,419	$ 3,442,028
Natural gas liquids sales
Revenue and other:
Total revenue	1,836,950	2,498,657	2,147,499
Oil sales
Revenue and other:
Total revenue	247,146	275,673	201,232
Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	2,642,358	2,605,380	2,499,174
Commodity derivative fair value gains (losses)
Revenue and other:
Total revenue	166,324	(1,615,836)	(1,936,509)
Marketing.
Revenue and other:
Total revenue	206,122	416,758	718,921
Operating expenses:
Cost of goods and services sold	284,965	531,304	811,698
Amortization of deferred revenue, VPP
Revenue and other:
Total revenue	30,552	37,603	45,236
Other revenue and income
Revenue and other:
Total revenue	2,529	5,162	1,025
Exploration
Operating expenses:
Cost of goods and services sold	$ 2,700	$ 7,409	$ 6,566

Consolidated Statements of Op_2

Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Consolidated Statements of Operations and Comprehensive Income (Loss)
Equity-based compensation expense	$ 59,519	$ 35,443	$ 20,437

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit).	Treasury Stock	Noncontrolling Interests	Total
Balances at Dec. 31, 2020	$ 2,686	$ 6,195,497	$ (430,478)		$ 322,566	$ 6,090,271
Balances (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
Equity-based compensation		20,437				20,437
Distributions to non-controlling interest					(97,424)	(97,424)
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
Increase (Decrease) in Stockholders' Equity
Equity component of 2026 Convertible Notes, net		(24,411)	3,229			(21,182)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 30	(66,162)				(66,132)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	2,971
Conversion of 2026 Convertible Notes	$ 57	24,185				24,242
Conversion of 2026 Convertible Notes (in shares)	5,672
Repurchases and retirements of common stock	$ (252)	(501,605)	(370,727)	$ (1,160)		(873,744)
Repurchases and retirements of common stock (in shares)	(25,180)			(34)
Equity-based compensation		35,443				35,443
Distributions to non-controlling interest					(173,537)	(173,537)
Net income (loss) and comprehensive income (loss)			1,898,771		127,201	2,025,972
Balance at Dec. 31, 2022	$ 2,974	5,838,848	913,896	$ (1,160)	262,596	7,017,154
Balance (in shares) at Dec. 31, 2022	297,393			(34)
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes	$ 17	(30,384)				(30,367)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes (in shares)	1,735
Conversion of 2026 Convertible Notes	$ 70	30,061				30,131
Conversion of 2026 Convertible Notes (in shares)	7,032
Repurchases and retirements of common stock	$ (26)	(51,503)	(24,987)	$ 1,160		(75,356)
Repurchases and retirements of common stock (in shares)	(2,616)			34
Equity-based compensation		59,519				59,519
Distributions to non-controlling interest					(128,823)	(128,823)
Net income (loss) and comprehensive income (loss)			242,919		98,925	341,844
Balance at Dec. 31, 2023	$ 3,035	$ 5,846,541	$ 1,131,828		$ 232,698	$ 7,214,102
Balance (in shares) at Dec. 31, 2023	303,544

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$ 341,844	$ 2,025,972	$ (154,109)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization and accretion	693,210	685,227	745,829
Impairments	51,302	149,731	90,523
Commodity derivative fair value losses (gains)	(166,324)	1,615,836	1,936,509
Losses on settled commodity derivatives	(25,383)	(1,911,065)	(1,183,400)
Payments for derivative monetizations	(202,339)		(4,569)
Deferred income tax expense (benefit)	74,407	447,845	(74,293)
Equity-based compensation expense	59,519	35,443	20,437
Equity in earnings of unconsolidated affiliate	(82,952)	(72,327)	(77,085)
Dividends of earnings from unconsolidated affiliate	125,138	125,138	136,609
Amortization of deferred revenue	(30,552)	(37,603)	(45,236)
Amortization of debt issuance costs, debt discount and other	2,264	4,336	12,492
Settlement of asset retirement obligations	(718)	(1,050)
Contract termination and loss contingency	12,100
Loss (gain) on sale of assets	(447)	471	(2,232)
Loss on early extinguishment of debt		46,027	93,191
Loss on convertible note inducements and equitizations	374	169	50,777
Changes in current assets and liabilities:
Accounts receivable	7,550	43,510	(55,567)
Accrued revenue	306,880	(116,243)	(166,128)
Prepaid expenses and other current assets	14,890	(27,530)	316
Accounts payable including related parties	(16,837)	32,374	(1,184)
Accrued liabilities	(62,419)	(5,620)	77,584
Revenue distributions payable	(106,429)	23,337	246,757
Other current liabilities	(357)	(12,636)	12,895
Net cash provided by operating activities	994,721	3,051,342	1,660,116
Cash flows provided by (used in) investing activities:
Additions to unproved properties	(151,135)	(149,009)	(79,138)
Drilling and completion costs	(964,346)	(780,649)	(601,175)
Additions to other property and equipment	(16,382)	(14,313)	(35,623)
Proceeds from asset sales	447	2,747	3,192
Change in other assets	(9,351)	(2,388)	2,632
Change in other liabilities			(672)
Net cash used in investing activities	(1,140,767)	(943,612)	(710,784)
Cash flows provided by (used in) financing activities:
Repurchases of common stock	(75,355)	(873,744)
Issuance of senior notes			1,800,000
Repayment of senior notes		(1,027,559)	(1,554,657)
Borrowings on Credit Facility	4,501,400	6,308,900	5,006,000
Repayments on Credit Facility	(4,119,000)	(6,274,100)	(6,023,000)
Payment of debt issuance costs	(605)	(814)	(31,474)
Sale of noncontrolling interest			51,000
Distributions to noncontrolling interests	(128,823)	(173,537)	(97,424)
Employee tax withholding for settlement of equity compensation awards	(30,367)	(66,132)	(13,270)
Convertible note inducements and equitizations	(374)	(169)	(85,648)
Other	(830)	(575)	(859)
Net cash provided by (used in) financing activities	146,046	(2,107,730)	(949,332)
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	113,910	155,006	141,930
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$ (60,762)	$ 38,035	$ 37,049

Organization

Organization	12 Months Ended
	Dec. 31, 2023
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, 2023
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 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, 2022 and 2023, and its results of operations and cash flows for the years ended December 31, 2021, 2022 and 2023. 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 and its VIE, Martica, for which the Company is the primary beneficiary. All For the years ended December 31, 2021, 2022 and 2023, 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 3—Transactions); and ● Antero provides accounting, administrative and other services to Martica under a Management Services Agreement. The Company accounts for its interest in Antero Midstream Corporation (“Antero Midstream”) using the equity method of accounting. As of December 31, 2022 and 2023, the Company had , respectively, interest in Antero Midstream. 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 affiliate on the Company’s consolidated statements of operations and comprehensive income (loss) 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 affiliate in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the 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 LP (“Antero Midstream Partners”) as of March 12, 2019, on such date, the Company deconsolidated Antero Midstream Partners. See Note 5—Equity Method Investments to the consolidated financial statements for further discussion on equity method investments. 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, 2022, the book overdrafts included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2023, the book overdrafts 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 expensed as incurred. Exploratory drilling costs are initially capitalized, but expensed 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 determines, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or expensed. 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 Company did not incur any impairment expenses associated with its proved properties during the years ended December 31, 2021, 2022 and 2023. As of December 31, 2023, 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. In December 2022, the Company commenced a strategic evaluation of the sand mine at which time, such mine was idled. Accordingly, the Company performed an impairment analysis as of December 31, 2022, and recorded impairment expense of million. There were (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, 2021, 2022 and 2023, 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. 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, 2022, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. As of December 31, 2023, 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 may enter into derivative transactions from time to time, which contracts may include commodity fixed price swaps, basis swaps, collars 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. Cash flows from derivative instruments are classified in operating activities on the Company’s consolidated statements of cash flows. 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 and comprehensive income (loss). 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, 2022 and 2023, 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 and comprehensive income (loss). 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 Company’s volumetric production payment transaction (“VPP”), 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 and comprehensive income (loss). (p) 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 Six One Commodities LLC accounted for of total sales for the years ended December 31, 2021 and 2022, respectively. No customer accounted for more than 10% of the Company’s sales for the year ended December 31, 2023. 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, 2023, the Company did not have any commodity derivative assets with bank counterparties under our Credit Facility. 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, 2023 for the counterparty. The Company believes that the counterparty currently is an acceptable credit risk. The Company, at times, may have cash in banks in excess of federally insured amounts. (q) Income Taxes The Company recognizes deferred income tax assets and liabilities for temporary differences resulting from 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 income 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 income tax assets will not be realized. On July 8, 2022, Pennsylvania enacted new tax laws that are effective January 1, 2023 on a prospective basis that reduce the state’s corporate income tax rate. As a result of this tax law change together with changes in the Company’s apportionment to Pennsylvania, the Company’s net deferred income tax liability was reduced by 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. (r) 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 fixed 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. (s) 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. See Note 17—Reportable Segments to the consolidated financial statements for more information. 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. (t) Net Income (Loss) Per Common Share Net income (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. Net income (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity awards using the treasury stock method and (ii) shares of common stock issuable upon conversion of the 2026 Convertible Notes using the if-converted method. 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. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding is 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 income (loss) attributable to common stockholders for basic and diluted net income (loss) per common share (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders ​ $ (186,899) ​ ​ 1,898,771 ​ ​ 242,919 ​ Add: Interest expense for 2026 Convertible Notes ​ ​ — ​ ​ 3,369 ​ ​ 1,955 ​ Less: Tax-effect of interest expense for 2026 Convertible Notes ​ ​ — ​ ​ (724) ​ ​ (425) ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions ​ $ (186,899) ​ ​ 1,901,416 ​ ​ 244,449 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) per common share—basic ​ $ (0.61) ​ ​ 6.18 ​ ​ 0.81 ​ Net income (loss) per common share—diluted ​ $ (0.61) ​ ​ 5.78 ​ ​ 0.78 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average common shares outstanding—basic ​ ​ 308,146 ​ ​ 307,202 ​ ​ 299,793 ​ Weighted average common shares outstanding—diluted ​ ​ 308,146 ​ ​ 329,223 ​ ​ 311,597 ​ ​ 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, ​ ​ 2021 2022 2023 ​ Basic weighted average number of common shares outstanding ​ 308,146 ​ 307,202 ​ 299,793 ​ Add: Dilutive effect of RSUs ​ — ​ 3,341 ​ 1,379 ​ Add: Dilutive effect of PSUs ​ — ​ 2,005 ​ 989 ​ Add: Dilutive effect of 2026 Convertible Notes ​ — ​ 16,675 ​ 9,436 ​ Diluted weighted average number of common shares outstanding ​ 308,146 ​ 329,223 ​ 311,597 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 6,407 ​ 111 ​ 1,200 ​ PSUs ​ 2,832 ​ 101 ​ 199 ​ Stock options ​ 379 ​ 346 ​ 310 ​ 2026 Convertible Notes ​ 18,778 ​ — ​ — ​ (1) The potential dilutive effects of these awards were excluded from the computation of net income (loss) per common share—diluted because the inclusion of these awards would have been anti-dilutive. ​ (u) Treasury Stock and Share Retirement Treasury stock purchases are recorded at cost. 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 retained earnings (accumulated 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. (v) 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 9 (w) Recently Adopted or Issued Accounting Standards Convertible Debt 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 31, 2021. The Company adopted the standard effective January 1, 2022 under the modified retrospective transition method, which impacts only the debt instruments outstanding on the adoption date. Upon adoption of this new standard, the Company reclassified $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increased long-term debt by $27 million, reduced deferred income tax liability by $6 million and reduce

Transactions

Transactions	12 Months Ended
	Dec. 31, 2023
Transactions
Transactions	(3) 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 were achieved in 2020 and 2021. The Company met these production thresholds and received the $102 million of additional contributions from Sixth Street during 2020 and 2021. All cash contributed by Sixth Street at the initial closing and received as part of these additional contributions was distributed to the Company. 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. As of April 1, 2023, Sixth Street no longer had the right to participate in any new wells, and Martica reconveyed the Development Override to the Company, except for the portion relating to wells turned to sales prior to April 1, 2023. 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 Incremental 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. As of March 31, 2023, 24% of the Incremental Override (or a 0.48% overriding royalty interest) 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 24% of all distributions in respect of the Incremental Override, and the Company will receive 76% of all 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. (b) Drilling Partnership On February 17, 2021, Antero Resources announced the formation of a drilling partnership with 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 through 2024, Antero Resources and QL agreed to the estimated IRR of the Company’s capital budget for each annual tranche, and QL agreed to participate in all annual tranches. Antero Resources develops and manages the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche, 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 development capital of 20%, 15% and 15% for wells spud in 2021, 2022 and 2023, respectively, and will fund 20% of development capital for wells spud in 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 than December 1 following the end of each tranche year. The Company received a carry of million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023. 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 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, 2023
Revenue
Revenue	(4 ) 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 17—Reportable Segments to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2021 ​ 2022 2023 Reportable Segment Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 3,442,028 ​ ​ 5,520,419 ​ ​ 2,192,349 ​ Exploration and production Natural gas liquids sales (ethane) ​ ​ 206,889 ​ ​ 384,079 ​ ​ 250,116 ​ Exploration and production Natural gas liquids sales (C3+ NGLs) ​ ​ 1,940,610 ​ ​ 2,114,578 ​ ​ 1,586,834 ​ Exploration and production Oil sales ​ ​ 201,232 ​ ​ 275,673 ​ ​ 247,146 ​ Exploration and production Marketing ​ ​ 718,921 ​ ​ 416,758 ​ ​ 206,122 ​ Marketing Other revenue ​ ​ — ​ ​ — ​ ​ 633 ​ Exploration and production Total revenue from contracts with customers ​ ​ 6,509,680 ​ ​ 8,711,507 ​ ​ 4,483,200 ​ ​ Income (loss) from derivatives, deferred revenue and other sources, net ​ ​ (1,890,248) ​ ​ (1,573,071) ​ ​ 198,772 ​ ​ Total revenue ​ $ 4,619,432 ​ ​ 7,138,436 ​ ​ 4,681,972 ​ ​ ​ (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 (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, 2022 and 2023, the Company’s receivables from contracts with customers were

Equity Method Investment

Equity Method Investment	12 Months Ended
	Dec. 31, 2023
Equity Method Investment
Equity Method Investment	​ (5) Equity Method Investment ​ (a) Summary of Equity Method Investment ​ ​ The following table sets forth a reconciliation of Antero’s investment in unconsolidated affiliate (in thousands): ​ ​ ​ ​ ​ ​ Balance as of December 31, 2021 (1) ​ $ 232,399 ​ Equity in earnings of unconsolidated affiliate ​ ​ 72,327 ​ Dividends from unconsolidated affiliate ​ ​ (125,138) ​ Elimination of intercompany profit ​ ​ 40,841 ​ Balance as of December 31, 2022 (1) ​ ​ 220,429 ​ Equity in earnings of unconsolidated affiliate ​ ​ 82,952 ​ Dividends from unconsolidated affiliate ​ ​ (125,138) ​ Elimination of intercompany profit ​ ​ 44,012 ​ Balance as of December 31, 2023 (1) ​ $ 222,255 ​ (1) The fair value of the Company’s investment in Antero Midstream as of December 31, 2022 and 2023 was $1.5 billion and $1.7 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, ​ ​ 2022 2023 ​ Current assets ​ $ 88,993 ​ ​ 91,128 ​ Noncurrent assets ​ ​ 5,702,327 ​ ​ 5,646,490 ​ Total assets ​ $ 5,791,320 ​ ​ 5,737,618 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 102,077 ​ ​ 96,417 ​ Noncurrent liabilities ​ ​ 3,496,925 ​ ​ 3,489,470 ​ Stockholders' equity ​ ​ 2,192,318 ​ ​ 2,151,731 ​ Total liabilities and stockholders' equity ​ $ 5,791,320 ​ ​ 5,737,618 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2022 ​ 2023 Revenues ​ $ 898,202 ​ ​ 919,985 ​ ​ 1,041,771 Operating expenses ​ ​ 342,875 ​ ​ 380,519 ​ ​ 429,909 Income from operations ​ ​ 555,327 ​ ​ 539,466 ​ ​ 611,862 Net income ​ $ 331,617 ​ ​ 326,242 ​ ​ 371,786 ​

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2023
Accrued Liabilities
Accrued Liabilities	(6) Accrued Liabilities Accrued liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Capital expenditures ​ $ 57,361 ​ 38,848 ​ Gathering, compression, processing and transportation expenses ​ ​ 162,783 ​ ​ 160,758 ​ Marketing expenses ​ ​ 61,118 ​ ​ 36,428 ​ Interest expense, net ​ 31,892 ​ 33,066 ​ Production and ad valorem taxes ​ ​ 32,536 ​ ​ 51,516 ​ General and administrative expense ​ ​ 32,477 ​ ​ 35,641 ​ Derivative settlements payable ​ ​ 53,732 ​ ​ 1,037 ​ Other ​ 29,889 ​ 24,046 ​ Total accrued liabilities ​ $ 461,788 ​ 381,340 ​ ​

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2023
Long-Term Debt.
Long-Term Debt	(7) Long-Term Debt Long-term debt consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Credit Facility (a) ​ $ 34,800 ​ ​ 417,200 ​ 8.375% senior notes due 2026 (e) ​ ​ 96,870 ​ ​ 96,870 ​ 7.625% senior notes due 2029 (f) ​ ​ 407,115 ​ ​ 407,115 ​ 5.375% senior notes due 2030 (g) ​ ​ 600,000 ​ ​ 600,000 ​ 4.25% convertible senior notes due 2026 (h) ​ ​ 56,932 ​ ​ 26,386 ​ Total principal ​ ​ 1,195,717 ​ ​ 1,547,571 ​ Unamortized debt issuance costs ​ ​ (12,241) ​ ​ (9,975) ​ Long-term debt ​ $ 1,183,476 ​ ​ 1,537,596 ​ ​ (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 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, 2022 and 2023, the Credit Facility had a borrowing base of billion, respectively. The borrowing base was re-affirmed in the semi-annual redetermination in October 2023 and the next redetermination of the borrowing base is scheduled to occur in April 2024. . As of December 31, 2023, the Credit Facility had an available borrowing capacity of 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 Credit Facility in effect prior to October 26, 2021 provided for borrowing under either an Alternate Base Rate or as a Eurodollar Loan (as each term is defined in the agreement) , and the Credit Facility in effect on and after October 26, 2021 provides for borrowing at either an Adjusted Term SOFR, an Adjusted Daily Simple SOFR or an Alternate Base Rate (each as defined in the Credit Facility). The Credit Facility provides for interest only payments until maturity at which time all outstanding borrowings are due. Interest was payable at a variable rate based on LIBOR or the Alternative Base Rate (as defined in the agreement), determined by election at the time of borrowing, plus an applicable margin rate under the Credit Facility in effect prior to October 26, 2021. Interest is payable at a variable rate based on SOFR or the Alternate Base Rate, determined by election at the time of borrowing, plus an applicable margin rate under the Credit Facility on or after October 26, 2021. 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 with respect to the Credit Facility, determined with reference to borrowing base utilization subject to certain exceptions based on the leverage ratio then in effect. The 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 Credit Facility). As of December 31, 2022, Antero Resources had an outstanding balance under the Credit Facility of $35 million, with a weighted average interest rate of 6.42%, and outstanding letters of credit of $504 million. As of December 31, 2023, Antero Resources had an outstanding balance under the Credit Facility of (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 of par. The Company repurchased or otherwise fully redeemed all of the 2022 Notes between 2019 and the first quarter of 2021, and the 2022 Notes were fully retired as of February 10, 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 . . Interest on the 2023 Notes was payable on June 1 and December 1 of each year. See “—Debt Repurchase Program” below for more information (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 . The Company repurchased or otherwise redeemed all of the 2025 Notes between 2020 and the first quarter of 2022, and the 2025 Notes were fully retired as of March 1, 2022. Interest on the 2025 Notes was payable on March 1 and September 1 of each year. (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 million principal amount of the 2026 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. 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 or otherwise repurchased million principal amount of the 2029 Notes remained outstanding. See “—Debt Repurchase Program” below for more information. 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 (h) 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. million. The Company extinguished million principal amount of the 2026 Convertible Notes in 2021. In addition, during 2022 and 2023, million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms or induced into conversion by the Company. See “—Equitizations, Conversions and Inducements,” for more information. 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 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, 2023, the if-converted value of the 2026 Convertible Notes was million. The 2026 Convertible Notes will mature on September 1, 2026, unless earlier repurchased, redeemed or converted. Before May 1, 2026, noteholders 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 Sales 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, 2023. 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 was 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 15.3% 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 income taxes and issuance costs, in additional paid-in capital within the consolidated balance sheet and statement of stockholders’ equity. 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 were 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. Effective January 1, 2022, the Company adopted ASU 2020-06 whereby the Company reclassified the equity component of the 2026 Convertible Notes outstanding on such date, net of deferred income taxes and equity issuance costs, from additional paid-in capital to long-term debt. See Note 2—Summary of Significant Accounting Policies to the consolidated financial statements. The 2026 Convertible Notes consist of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2022 ​ 2023 ​ Principal ​ $ 56,932 ​ ​ 26,386 ​ Less: unamortized debt issuance costs ​ ​ (1,159) ​ ​ (404) ​ Net carrying value ​ $ 55,773 ​ ​ 25,982 ​ ​ Interest expense recognized on the 2026 Convertible Notes related to the stated interest rate, amortization of the debt discount and debt issuance costs totaled $11 million, $3 million and $2 million for the years ended December 31, 2021, 2022 and 2023, respectively. Equitizations, Conversions and Inducements Equitizations 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 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 had a conversion rate of 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 million loss on convertible note equitization in the consolidated statements of operations and comprehensive income (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 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 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 had a conversion rate of 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 million loss on convertible note equitization in the consolidated statements of operations and comprehensive income (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 Conversions and Inducements During the year ended December 31, 2022, $20 million aggregate principal amount of the 2026 Convertible Notes were converted pursuant to their terms, and an additional $5 million aggregate principal amount of the 2026 Convertible Notes were induced into conversion by the Company. The Company elected to settle these conversions by issuing approximately million. During the year ended December 31, 2023, million aggregate principal amount of the 2026 Convertible Notes were induced into conversion by the Company. The Company elected to settle these conversions by issuing (i) Debt Repurchase Program During the year ended December 31, 2021, the Company redeemed or repurchased through open market transactions (i) the remaining $661 million aggregate principal amount of its 2022 Notes at par, plus accrued and unpaid interest, (ii) the remaining $574 million aggregate principal amount of the 2023 Notes at par, plus accrued and unpaid interest, (iii) $5 million aggregate principal amount of its 2025 Notes at a weighted average redemption price of 102% of the principal amount thereof, plus accrued and unpaid interest, (iv) $175 million aggregate principal amount of its 2026 Notes at a redemption price of 108.375% of the principal amount thereof, plus accrued and unpaid interest and (v) $116 million aggregate principal amount of its 2029 Notes at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest. For such redemptions and repurchases, the Company recognized a During the year ended December 31, 2022, the Company redeemed or repurchased through its previously disclosed tender offer and open market transactions (i) the remaining $585 million aggregate principal amount of its 2025 Notes at a redemption price of 101.25% of the principal amount thereof, plus accrued and unpaid interest, (ii) $228 million aggregate principal amount of its 2026 Notes at a weighted average redemption price of 109% of the principal amount thereof, plus accrued and unpaid interest and (iii) $177 million aggregate principal amount of its 2029 Notes at a weighted average redemption price of 106% of the principal amount thereof, plus accrued and unpaid interest. For such redemptions and repurchases, the Company recognized a million loss on early extinguishment of debt. There were no debt redemptions or repurchases during the year ended December 31, 2023.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligations
Asset Retirement Obligations	(8) Asset Retirement Obligations ​ The following table presents a reconciliation of the Company’s asset retirement obligations (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2022 ​ 2023 ​ Beginning balance $ 53,952 ​ 59,485 ​ Obligations incurred ​ 3,456 ​ ​ 1,106 ​ Accretion expense ​ ​ 4,906 ​ ​ 3,244 ​ Settlement of obligations ​ ​ (1,050) ​ ​ (718) ​ Obligations on sold properties ​ ​ (42) ​ ​ — ​ Revisions to prior estimates ​ ​ (1,737) ​ ​ (3,903) ​ Ending balance ​ $ 59,485 ​ ​ 59,214 ​ ​ Revisions to prior estimates during the years ended December 31, 2022 and 2023 are primarily due to increases in estimated well lives. Asset retirement obligations are included in Other liabilities on the Company’s consolidated balance sheets.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2023
Equity-Based Compensation
Equity-Based Compensation	(9) Equity-Based Compensation 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 7,059,518 shares were available for future grant under the 2020 Plan as of December 31, 2023. 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). Antero Resources deconsolidated Antero Midstream Partners on March 12, 2019, and on such date, each outstanding phantom unit award under the AMP Plan, was assumed by Antero Midstream and converted into 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 represented a right to receive share of Antero Midstream common stock. As of December 31, 2023, all Converted AM RSU Awards were fully vested. The Company’s equity-based compensation expense, by type of award, is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 2022 2023 ​ RSU awards ​ $ 13,232 ​ ​ 18,915 ​ ​ 32,744 ​ PSU awards ​ ​ 4,662 ​ ​ 14,920 ​ ​ 25,322 ​ Converted AM RSU Awards (1) ​ ​ 1,160 ​ ​ 209 ​ ​ 1 ​ Equity awards issued to directors ​ ​ 1,383 ​ ​ 1,399 ​ ​ 1,452 ​ Total expense ​ $ 20,437 ​ ​ 35,443 ​ ​ 59,519 ​ (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 March 13, 2019 (date of deconsolidation) to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. As of December 31, 2023, all Converted AM RSU Awards were fully vested, and there is no remaining unamortized expense attributable to these awards ​ The total fair value of the Company’s vested equity awards for the years ended December 31, 2021, 2022 and 2023 were $34 million, $158 million and $75 million, respectively. (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. The weighted average grant date fair value per share for RSUs granted during the years ended December 31, 2021, 2022 and 2023 were ​ A summary of RSU award activity is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 4,676,219 ​ $ 15.29 ​ Granted ​ 1,474,930 ​ ​ 25.90 ​ Vested ​ (2,464,072) ​ ​ 10.92 ​ Forfeited ​ (166,027) ​ ​ 23.83 ​ Total awarded and unvested—December 31, 2023 ​ 3,521,050 ​ $ 22.40 ​ ​ As of December 31, 2023, there was $57 million of unamortized equity-based compensation expense related to unvested RSUs. That expense is expected to be recognized over a weighted average period of (b) Performance Share Unit Awards Performance Share Unit Awards Based on Total Shareholder Return 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 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 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 . 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 2018 TSR PSUs were not met, and In 2019, the Company granted PSUs to certain of its employees and executive officers that vested 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 (“2019 Absolute TSR PSUs”). The number of shares of common stock which could ultimately be earned ranged from of the PSUs granted. Expense related to these PSUs was recognized on a straight-line basis over . Forfeitures were accounted for as they occurred by reversing the expense previously recognized for awards that were forfeited during the period. During 2022, the market-based performance condition for the 2019 Absolute TSR PSUs was met at In 2020, the Company granted PSU awards to certain of its executive officers that vested 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 (“2020 Absolute TSR PSUs”). The number of shares of common stock that could ultimately be earned following the end of the cumulative three-year performance period ranged from zero to 150% of the target number of PSUs granted. Expense related to these PSUs was recognized on a graded-vested basis over approximately 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 each of the performance periods ended April 15, 2021, 2022 and 2023 were met. During 2023, the 2020 Absolute TSR PSUs vested at 112% of target for all four performance periods and were converted into approximately 0.2 million shares of common stock. Additionally, in 2020, the Company granted PSUs to certain of its executive officers that vested 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 (“2020 Relative TSR PSUs”). The number of shares of common stock that could ultimately be earned following the end of the cumulative three-year performance period ranged from zero to 150% of the target number of PSUs granted. Expense related to these PSUs was recognized on a graded-vested basis over approximately three years . Forfeitures were accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The performance condition for each of the performance periods ended April 15, 2021, 2022 and 2023 were met. During 2023, the 2020 Relative TSR PSUs vested at 126% of target for all four performance periods and were converted into approximately 0.2 million shares of common stock. 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 (“2021 Absolute TSR PSUs”). 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 2021 Absolute TSR PSUs ranges from zero to 200% of the target number of 2021 Absolute 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. The performance condition for the performance period ended April 15, 2022 was met, and 200% vesting was achieved for this award tranche. The performance condition for the performance period ended April 15, 2023 was not met, and as a result, no vesting for this award tranche was achieved. In 2022, the Company granted PSU awards to certain of its senior management and 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, 2023, April 15, 2024 and April 15, 2025, and one cumulative three-year performance period ending on April 15, 2025, in each case, subject to certain continued employment criteria (“2022 Absolute TSR PSUs”). 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 2022 Absolute TSR PSUs ranges from zero to 200% of the target number of 2022 Absolute 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. The performance condition for the performance period ended April 15, 2023 was not met, and as a result, no vesting for this award tranche was achieved. Additionally, in 2022, the Company granted PSU awards to certain of its senior management and 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 December 31, 2023, December 31, 2024 and December 31, 2025, and one cumulative three-year performance period ending on December 31, 2025, in each case, subject to certain continued employment criteria (“Special 2022 Absolute TSR PSUs”). 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 Special 2022 Absolute TSR PSUs ranges from zero to 200% of the target number of Special 2022 Absolute 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. The performance condition for the performance period ended December 31, 2023 was not met, and as a result, no vesting for this award tranche was achieved. In 2023, the Company granted PSU awards to certain of its senior management and 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 March 7, 2024, March 7, 2025 and March 7, 2026, and one cumulative three-year performance period ending on March 7, 2026, in each case, subject to certain continued employment criteria (“2023 Absolute TSR PSUs”). 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 2023 Absolute TSR PSUs ranges from zero to 200% of the target number of 2023 Absolute 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 2021, the Company granted PSUs to certain of its executive officers that vested based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) 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 (“2021 Leverage Ratio PSUs”). The number of shares of common stock that could ultimately be earned following the end of the third performance period with respect to the 2021 Leverage Ratio PSUs ranged from zero to 200% of the target number of 2021 Leverage Ratio PSUs originally granted. Expense related to the 2021 Leverage Ratio PSUs was recognized on a graded-vested basis over the term of each performance period that reflects 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. The performance conditions for the performance periods ended December 31, 2021, 2022 and 2023 were met at 200% of target. During the first quarter of 2024, the 2021 Leverage Ratio PSUs vested and converted into approximately 0.4 million shares of common stock. In 2022, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) determined as of the last day of each of three one-year performance periods ending on December 31, 2022, December 31, 2023 and December 31, 2024, in each case, subject to certain continued employment criteria (“2022 Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned following the end of the third performance period with respect to the 2022 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2022 Leverage Ratio PSUs originally granted. Expense related to the 2022 Leverage Ratio PSUs is recognized on a graded-vested basis over the term of each performance period that reflects 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. The performance conditions for the performance periods ended December 31, 2022 and 2023 were met, and 200% vesting was achieved for these award tranches. As of December 31, 2023, the likelihood of achieving the performance conditions related to the 2022 Leverage Ratio PSUs was probable. Additionally, in 2022, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) determined as of the last day of each of three one-year performance periods ending on December 31, 2023, December 31, 2024 and December 31, 2025, in each case, subject to certain continued employment criteria (“Special 2022 Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned following the end of the third performance period with respect to the Special 2022 Leverage Ratio PSUs ranges from zero to 200% of the target number of Special 2022 Leverage Ratio PSUs originally granted. Expense related to the Special 2022 Leverage Ratio PSUs is recognized on a graded-vested basis over the term of each performance period that reflects 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. The performance condition for the performance period ended December 31, 2023 was met, and 200% vesting was achieved for this award tranche. As of December 31, 2023, the likelihood of achieving the performance conditions related to the Special 2022 Leverage Ratio PSUs was probable. In 2023, the Company granted PSUs to certain of its senior management and executive officers that vest based on the Company’s total debt less cash and cash equivalents divided by the Company’s Adjusted EBITDAX (as defined in the award agreement) determined as of the last day of each of three one-year performance periods ending on December 31, 2023, December 31, 2024 and December 31, 2025, in each case, subject to certain continued employment criteria (“2023 Leverage Ratio PSUs”). The number of shares of common stock that may ultimately be earned following the end of the third performance period with respect to the 2023 Leverage Ratio PSUs ranges from zero to 200% of the target number of 2023 Leverage Ratio PSUs originally granted. Expense related to the 2023 Leverage Ratio PSUs is recognized on a graded-vested basis over the term of each performance period that reflects 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. The performance condition for the performance period ended December 31, 2023 was met, and 200% vesting was achieved for this award tranche. As of December 31, 2023, the likelihood of achieving the performance conditions related to the 2023 Leverage Ratio PSUs was probable. Summary Information for Performance Share Unit Awards A summary of PSU activity is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 1,329,725 ​ $ 23.18 ​ Granted ​ 417,466 ​ ​ 28.51 ​ Vested (1) ​ (335,000) ​ ​ 2.97 ​ Total awarded and unvested—December 31, 2023 ​ 1,412,191 ​ $ 29.54 ​ (1) During the year ended December 31, 2023, the PSUs granted in 2020 that were based on absolute TSR and relative TSR met the performance criteria to achieve vesting at 112% and 126% of target, respectively, and converted into approximately 0.4 million shares of the Company’s common stock. ​ 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 was assumed. The grant-date fair value for the 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 weighted average grant date fair value per share for PSUs granted during the years ended December 31, 2021, 2022 and 2023 were 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, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ ​ Dividend yield ​ ​ — % ​ — % ​ — % ​ Volatility ​ ​ 85 % ​ 87 - 88 % ​ 82 % ​ Risk-free interest rate ​ ​ 0.32 % ​ 2.65 - 4.49 % ​ 4.61 % ​ Weighted average fair value of awards granted ​ $ 11.99 ​ ​ 49.32 ​ ​ 33.96 ​ ​ ​ As of December 31, 2023, there was $19 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of (c) Converted AM RSU 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. On March 12, 2019, the Board of Directors of Antero Midstream adopted the AM Plan, and as a result, 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 ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 2,827 ​ $ 12.38 ​ Vested ​ (2,827) ​ ​ 12.38 ​ Total awarded and unvested—December 31, 2023 ​ — ​ $ — ​ ​ As of December 31, 2023, all Converted AM RSU Awards were fully vested resulting in no (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 ​ ​ ​ Number ​ Exercise ​ Contractual ​ Value ​ ​ of Options Price Life (in thousands) (1) ​ Outstanding—December 31, 2022 ​ 323,960 ​ $ 50.86 ​ 2.0 ​ $ — ​ Expired ​ (65,264) ​ ​ 54.10 ​ — ​ ​ — ​ Outstanding—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ ​ — ​ Vested—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ $ — ​ Exercisable—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ $ — ​ (1) Intrinsic values are based on the exercise price of the options and the closing price of Antero Resources’ common stock on the referenced dates. A Black-Scholes option- pricing model is used to determine the grant-date fair value of stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies’ stock prices as Antero Resources’ common stock had traded for a relatively short period of time at the dates the options were granted. The risk-free interest rate was determined using the implied yield available for zero- coupon U.S. government issues with a remaining term approximating the expected life of the options. A dividend yield of

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2023
Fair Value.
Fair Value	(10) Fair Value The carrying values of accounts receivable and accounts payable as of December 31, 2022 and 2023 approximated market values because of their short- term nature. The carrying values of the amounts outstanding under the Credit Facility as of December 31, 2022 and 2023 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, 2022 ​ December 31, 2023 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 2026 Notes ​ $ 100,987 ​ ​ 96,123 ​ ​ 99,534 ​ ​ 96,351 ​ 2029 Notes ​ ​ 410,860 ​ ​ 402,872 ​ ​ 417,781 ​ ​ 403,441 ​ 2030 Notes ​ ​ 556,260 ​ ​ 593,908 ​ ​ 573,720 ​ ​ 594,622 ​ 2026 Convertible Notes ​ ​ 406,039 ​ ​ 55,773 ​ ​ 138,337 ​ ​ 25,982 ​ Total ​ $ 1,474,146 ​ ​ 1,148,676 ​ ​ 1,229,372 ​ ​ 1,120,396 ​ (1) Fair values are based on Level 2 market data inputs. (2) Carrying values are presented net of unamortized debt issuance costs. See Note 9—Equity-Based Compensation to the consolidated financial statements for information regarding the fair value of equity based awards. See Note 11—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, 2023
Derivative Instruments.
Derivative Instruments	(11) Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, and it may use 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, 2021, 2022 and 2023. As of December 31, 2023, the Company has no fixed price commodity swap contracts. 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. Under these basis swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company receives the difference from the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company pays the difference to the counterparty. The Company’s derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s statements of operations and comprehensive income (loss). The Company has a call option and an embedded put option tied to NYMEX pricing for the production volumes associated with the Company’s retained interest in the VPP properties. The put option was embedded within another contract, and since the embedded put option was not clearly and closely related to its host contract, the Company bifurcated this derivative instrument and reflects it at fair value in the consolidated financial statements. As of December 31, 2023, the Company’s call option and embedded put option arrangements were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Embedded ​ ​ ​ ​ ​ ​ ​ ​ Call Option ​ Put Option ​ Commodity / Settlement Period Index Contracted Volume Strike Price Strike Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2024 ​ Henry Hub ​ 53,000 MMBtu/day ​ ​ 2.477 /MMBtu ​ ​ 2.527 /MMBtu ​ January-December 2025 ​ Henry Hub ​ 44,000 MMBtu/day ​ ​ 2.564 /MMBtu ​ ​ 2.614 /MMBtu ​ January-December 2026 ​ Henry Hub ​ 32,000 MMBtu/day ​ ​ 2.629 /MMBtu ​ ​ 2.679 /MMBtu ​ ​ As of December 31, 2023, 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 2024 ​ NYMEX to TCO ​ 50,000 MMBtu/day ​ ​ 0.530 /MMBtu ​ ​ In addition, the Company had a swaption agreement, which entitled 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/d at a price of $2.77 per MMBtu for the year ending December 31, 2024. In 2023, the Company executed an early settlement of this swaption agreement and made a cash payment of $202 million. As of December 31, 2023, 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 2024 ​ Henry Hub ​ 23,885 MMBtu/day ​ ​ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 18,021 MMBtu/day ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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) 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): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ Balance Sheet Location 2022 ​ 2023 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Embedded derivatives—current ​ Derivative instruments ​ $ 1,900 ​ ​ 5,175 ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ 9,844 ​ ​ 5,570 ​ Total asset derivatives (1) ​ ​ ​ ​ 11,744 ​ ​ 10,745 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (2) ​ Derivative instruments ​ ​ 97,765 ​ ​ 15,236 ​ Commodity derivatives—noncurrent (2) ​ Derivative instruments ​ ​ 345,280 ​ ​ 32,764 ​ Total liability derivatives (1) ​ ​ ​ ​ 443,045 ​ ​ 48,000 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives liability (1) ​ ​ ​ $ (431,301) ​ ​ (37,255) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs. (2) As of December 31, 2022, $47 million of commodity derivative liabilities, including $28 million of current commodity derivatives and $19 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of December 31, 2023, approximately $5 million of commodity derivative liabilities, including $3 million of current commodity derivatives and $2 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, 2022 ​ December 31, 2023 ​ ​ ​ ​ ​ ​ ​ 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 ​ $ 276 ​ ​ (276) ​ ​ — ​ ​ 406 ​ ​ (406) ​ ​ — ​ Embedded derivative assets ​ ​ 11,744 ​ ​ — ​ ​ 11,744 ​ ​ 10,745 ​ ​ — ​ ​ 10,745 ​ Commodity derivative liabilities ​ ​ (443,321) ​ ​ 276 ​ ​ (443,045) ​ ​ (48,406) ​ ​ 406 ​ ​ (48,000) ​ ​ 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 and comprehensive income (loss) (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location ​ 2021 ​ 2022 2023 ​ Commodity derivative fair value gains (losses) (1) ​ Revenue ​ $ (1,886,551) ​ ​ (1,524,250) ​ ​ 165,448 ​ Embedded derivative fair value gains (losses) (1) ​ Revenue ​ ​ (49,958) ​ ​ (91,586) ​ ​ 876 ​ (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, 2021 and 2023 include losses of $5 million and $202 million related to the settlement of certain natural gas derivatives prior to the contractual settlement dates. Payments for these early settlements are classified as operating cash flows on the Company’s consolidated statement of cash flows for the years ended December 31, 2021 and 2023. There were

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases
Leases	(12) 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 is a transfer of title or purchase option reasonably certain of exercise. Certain of the Company’s lease agreements include minimum payments based on a percentage of produced volumes over contractual levels and others include rental payments adjusted periodically for inflation. The Company 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 consolidated 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 2022 2023 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,849,116 ​ ​ 1,611,903 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 85,405 ​ ​ 32,187 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,463,756 ​ ​ 1,283,668 ​ Office space ​ Operating lease right-of-use assets ​ ​ 41,822 ​ ​ 37,706 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 756 ​ ​ — ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 3,476 ​ ​ 416 ​ Total operating lease right-of-use assets ​ ​ ​ $ 3,444,331 ​ ​ 2,965,880 ​ Operating lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease liabilities ​ Short-term lease liabilities ​ $ 556,137 ​ ​ 538,954 ​ Long-term operating lease liabilities ​ Long-term lease liabilities ​ ​ 2,888,194 ​ ​ 2,425,785 ​ Total operating lease liabilities ​ ​ ​ $ 3,444,331 ​ ​ 2,964,739 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 2,159 ​ ​ 3,771 ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 2,159 ​ ​ 3,771 ​ Finance lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease liabilities ​ Short-term lease liabilities ​ $ 499 ​ ​ 1,106 ​ Long-term finance lease liabilities ​ Long-term lease liabilities ​ ​ 1,660 ​ ​ 2,665 ​ Total finance lease liabilities ​ ​ ​ $ 2,159 ​ ​ 3,771 ​ (1) Gas gathering lines and compressor stations includes $1.4 billion and $ 1.3 billion related to Antero Midstream as of December 31, 2022 and 2023, respectively. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $1 million as of December 31, 2022 and 2023. ​ 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 financial statements as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ Cost Classification Location 2021 2022 2023 ​ Operating lease cost ​ Statement of operations ​ Gathering, compression, processing and transportation ​ $ 1,518,305 ​ ​ 1,481,022 ​ ​ 1,623,268 ​ Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 10,901 ​ ​ 11,472 ​ ​ 12,121 ​ Operating lease cost ​ Statement of operations ​ Contract termination ​ ​ 4,213 ​ ​ 12,000 ​ ​ 4,227 ​ Operating lease cost ​ Statement of operations ​ Lease operating ​ ​ 142 ​ ​ 177 ​ ​ 84 ​ Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 103,741 ​ ​ 123,756 ​ ​ 160,638 ​ Total operating lease cost ​ ​ ​ ​ ​ $ 1,637,302 ​ ​ 1,628,427 ​ ​ 1,800,338 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation and amortization ​ $ 522 ​ ​ 351 ​ ​ 1,530 ​ Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 352 ​ ​ 193 ​ ​ 597 ​ Total finance lease cost ​ ​ ​ ​ ​ $ 874 ​ ​ 544 ​ ​ 2,127 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 86,039 ​ ​ 141,470 ​ ​ 137,781 ​ (1) Capitalized costs related to drilling and completion activities. ​ (c) Supplemental Cash Flow Information Related to Leases The following table presents the Company’s supplemental cash flow information related to leases (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases $ 1,352,941 ​ ​ 1,380,968 ​ ​ 1,366,677 ​ Operating cash flows from finance leases ​ 352 ​ ​ 193 ​ ​ 597 ​ Investing cash flows from operating leases ​ 88,910 ​ ​ 103,244 ​ ​ 126,483 ​ Financing cash flows from finance leases ​ 859 ​ ​ 575 ​ ​ 830 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease obligations $ 437,045 ​ ​ 366,194 ​ ​ 76,797 ​ Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net (1) $ 702,512 ​ ​ 154,101 ​ ​ (15,858) ​ ​ (1) 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. During the year ended December 31, 2022, the weighted average discount rate for remeasured operating leases decreased from 5.6% as of December 31, 2021 to 5.2% as of December 31, 2022. During the year ended December 31, 2023, the weighted average discount rate for remeasured operating leases increased from 5.1% as of December 31, 2022 to 6.5% as of December 31, 2023. (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, 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2024 ​ $ 699,335 ​ ​ 1,628 ​ ​ 700,963 ​ 2025 ​ ​ 608,160 ​ ​ 1,585 ​ ​ 609,745 ​ 2026 ​ ​ 555,915 ​ ​ 1,230 ​ ​ 557,145 ​ 2027 ​ ​ 457,782 ​ ​ 197 ​ ​ 457,979 ​ 2028 ​ ​ 379,922 ​ ​ 23 ​ ​ 379,945 ​ Thereafter ​ ​ 872,055 ​ ​ 9 ​ ​ 872,064 ​ Total lease payments ​ ​ 3,573,169 ​ ​ 4,672 ​ ​ 3,577,841 ​ Less: imputed interest ​ ​ (608,430) ​ ​ (901) ​ ​ (609,331) ​ Total ​ $ 2,964,739 ​ ​ 3,771 ​ ​ 2,968,510 ​ ​ (e) Lease Term and Discount Rate ​ The following table sets forth the Company’s weighted average remaining lease term and discount rate: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ December 31, 2023 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ Operating Leases ​ Finance Leases ​ ​ Weighted average remaining lease term ​ 7.2 years ​ 3.5 years ​ 6.5 years ​ 3.0 years ​ ​ Weighted average discount rate ​ 5.3 % 7.4 % 5.9 % 8.3 % ​ ​ (f) Related Party Lease Disclosure ​ The Company has gathering and compression service agreements with Antero Midstream that include: (i) the second amended and restated gathering and compression agreement dated December 8, 2019 (the “2019 gathering and compression agreement”), (ii) a gathering and compression agreement from Antero Midstream’s acquisition of certain Marcellus gathering and compression assets (the “Marcellus gathering and compression agreement”) and (iii) a compression agreement from Antero Midstream’s acquisition of certain Utica compressors (the “Utica compression agreement” and, together with the 2019 gathering and compression agreement and the Marcellus gathering and compression agreement, the “gathering and compression agreements”). Pursuant to the gathering and compression agreements with Antero Midstream, the Company has dedicated substantially all of its current and future acreage in West Virginia, Ohio and Pennsylvania to Antero Midstream for gathering and compression services. The 2019 gathering and compression agreement has an initial term through 2038, the Marcellus gathering and compression agreement expires in 2031 and the Utica compression agreement has dedicated areas that expire in 2024 and 2030. Upon expiration of each of the Marcellus gathering and compression agreement and the Utica compression agreement, Antero Midstream will continue to provide gathering and compression services under the 2019 gathering and compression agreement. ​ Under the gathering and compression agreements, Antero Midstream receives a low pressure gathering fee per Mcf, a high pressure gathering fee per Mcf and a compression fee per Mcf, as applicable, subject to annual adjustments based on CPI. If and to the extent the Company requests that Antero Midstream construct new low pressure lines, high pressure lines and compressor stations, the 2019 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 addition, the Marcellus gathering and compression agreement provides for a minimum volume commitment that requires the Company to utilize or pay for ​ The 2019 gathering and compression agreement includes a growth incentive fee program whereby low pressure gathering fees were reduced during the years ended December 31, 2021, 2022 and 2023 to the extent the Company achieved certain quarterly volumetric targets. The Company’s throughput gathered under the Marcellus gathering and compression assets acquired by Antero Midstream was not considered in low pressure gathering volume targets. Upon completion of the initial contract term, the 2019 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 th day prior to the anniversary of such effective date. The Company earned fee rebates for the years ended December 31, 2021, 2022 and 2023 of million, respectively. The growth incentive fee program expired on December 31, 2023. ​ For the years ended December 31, 2021, 2022 and 2023, gathering and compression fees paid by Antero related to these agreements were $705 million, $660 million and $738 million, respectively. As of December 31, 2022 and 2023,

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Taxes
Income Taxes	(13) Income Taxes ​ The Company’s income tax expense (benefit) consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 Current income tax expense ​ $ 216 ​ ​ 847 ​ ​ 1,587 ​ Deferred income tax expense (benefit) ​ (74,293) ​ 447,845 ​ 74,407 ​ Total income tax expense (benefit) ​ $ (74,077) ​ ​ 448,692 ​ ​ 75,994 ​ ​ 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, ​ ​ 2021 2022 2023 Federal income tax expense (benefit) ​ $ (47,919) ​ ​ 519,679 ​ ​ 87,746 ​ State income tax expense (benefit), net of federal effect ​ (6,576) ​ 12,461 ​ 3,512 ​ Change in state tax rate, net of federal effect ​ ​ (30,910) ​ ​ (52,747) ​ ​ 11,417 ​ Equity-based compensation ​ 1,117 ​ (9,717) ​ (772) ​ Dividends received deduction ​ ​ (3,832) ​ ​ (1,749) ​ ​ (3,186) ​ Noncontrolling interests ​ ​ (7,862) ​ ​ (27,347) ​ ​ (21,525) ​ Change in valuation allowance ​ 4,606 ​ 7,070 ​ (2,567) ​ Nondeductible loss on 2026 Convertible Notes equitizations and inducement ​ ​ 12,174 ​ ​ 36 ​ ​ 81 ​ Other ​ 5,125 ​ 1,006 ​ 1,288 ​ Total income tax expense (benefit) ​ $ (74,077) ​ ​ 448,692 ​ ​ 75,994 ​ ​ 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 deferred income tax assets and liabilities is as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Deferred income tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 282,829 ​ ​ 281,217 ​ Interest expense carryforwards ​ ​ — ​ ​ 25,258 ​ Equity-based compensation ​ ​ 3,362 ​ ​ 7,056 ​ Investment in Antero Midstream ​ ​ 254,164 ​ ​ 234,423 ​ Unrealized losses on derivative instruments ​ ​ 83,269 ​ ​ 51,025 ​ Lease liabilities ​ ​ 740,254 ​ ​ 644,622 ​ Asset retirement obligations and other ​ ​ 15,859 ​ ​ 17,093 ​ Total deferred income tax assets ​ ​ 1,379,737 ​ ​ 1,260,694 ​ Valuation allowance ​ ​ (57,375) ​ ​ (54,805) ​ Deferred income tax assets, net ​ ​ 1,322,362 ​ ​ 1,205,889 ​ Deferred income tax liabilities: ​ ​ ​ ​ ​ ​ ​ Oil and gas properties ​ ​ 1,295,847 ​ ​ 1,338,442 ​ Lease right-of-use assets ​ ​ 740,254 ​ ​ 644,870 ​ Investment in Martica ​ ​ 45,507 ​ ​ 55,759 ​ 2026 Convertible Notes and other ​ ​ 615 ​ ​ 1,086 ​ Total deferred income tax liabilities ​ ​ 2,082,223 ​ ​ 2,040,157 ​ Deferred tax liability, net ​ $ (759,861) ​ ​ (834,268) ​ ​ In assessing the realizability of deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred income 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 income 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 income 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 million as of December 31, 2022 and 2023, respectively. The valuation allowance for each of the years ended December 31, 2022 and 2023, relates primarily to Colorado, Oklahoma and West Virginia state NOL carryforwards and are the result of expected future reduced income tax apportionment in those states. The amount of the deferred income 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 has ​ As of December 31, 2023, the Company has U.S. federal and state NOL carryforwards of $1.0 billion and $1.9 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 2036 and 2037. For tax years 2018 and thereafter, U.S. federal and West Virginia NOL carryforwards generated in these jurisdictions have no expiration date. The Colorado NOL carryforwards generated in tax years prior to 2018 or in 2021 expire between 2025 and 2041. The Colorado NOL Carryforwards generated in tax years 2018 through 2020 have no expiration date. Tax years 2020 through 2023 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 2019 through 2023.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2023
Commitments
Commitments	(14) Commitments ​ The following table sets forth a schedule of future minimum payments for the Company’s contractual obligations, which include leases that have a lease term in excess of one year as of December 31, 2023 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gathering, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Firm ​ Compression ​ Operating and ​ Imputed Interest ​ ​ ​ ​ ​ ​ ​ Transportation ​ and Water Service ​ Financing Leases ​ for Leases ​ Other ​ ​ ​ ​ (a) (b) (c) (c) (d) Total 2024 ​ $ 1,171,743 ​ ​ 67,201 ​ ​ 540,101 ​ ​ 160,862 ​ ​ 8,412 ​ ​ 1,948,319 ​ 2025 ​ ​ 1,158,209 ​ ​ 55,853 ​ ​ 479,666 ​ ​ 130,080 ​ ​ 4,875 ​ ​ 1,828,683 ​ 2026 ​ ​ 1,155,797 ​ ​ 22,676 ​ ​ 455,118 ​ ​ 102,027 ​ ​ 2,250 ​ ​ 1,737,868 ​ 2027 ​ ​ 1,151,152 ​ ​ 21,387 ​ ​ 381,598 ​ ​ 76,380 ​ ​ — ​ ​ 1,630,517 ​ 2028 ​ ​ 1,095,015 ​ ​ 20,054 ​ ​ 324,786 ​ ​ 55,159 ​ ​ — ​ ​ 1,495,014 ​ Thereafter ​ ​ 4,382,740 ​ ​ 77,753 ​ ​ 787,241 ​ ​ 84,823 ​ ​ — ​ ​ 5,332,557 ​ Total ​ $ 10,114,656 ​ ​ 264,924 ​ ​ 2,968,510 ​ ​ 609,331 ​ ​ 15,537 ​ ​ 13,972,958 ​ ​ (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, Compression and Water Service Commitments The Company has entered into various long-term gas processing, gathering, compression and water 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) Operating and Finance 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 12—Leases to the consolidated financial statements for more information on the Company’s operating and finance leases. (d) Other The Company has entered into various land acquisition and sand supply 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. (e) Contract Terminations The Company incurs costs associated with the delay or cancellation of certain contracts with third parties. These costs are recorded in contract termination and included in the statements of operations and comprehensive income (loss). During 2022, the Company cancelled the construction of the Smithburg 2 gas processing plant and made a cash payment of million. During 2023, the Company executed an early termination of its firm transportation commitment of million. There are no remaining payment obligations related to any delayed or cancelled contracts as of December 31, 2023.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2023
Contingencies
Contingencies	(15) Contingencies Environmental In June 2018, the Company received a Notice of Violation (“NOV”) from the 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. 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 lawsuits were consolidated and tried in June 2019. On June 20, 2019, the Company was awarded a jury verdict of approximately 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 Other The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows. In addition, pending litigation against the Company and other similarly situated peer operators could have an impact on the methods for determining the amount of permitted post-production costs and types of costs that have been, and may be, deducted from royalty payments, among other things. While the amounts claimed could be material, we are unable to predict with certainty the ultimate outcome of such claims and proceedings. Rulings were recently received in two cases to which the Company is a party, and where the plaintiffs alleged, and the court found, that certain post-production costs may not be deducted: a non-class action lawsuit in West Virginia and a class action lawsuit in Ohio. In each case, the alleged damages were not material. The Company will continue to challenge the legal conclusions reached in each of these cases with respect to deductibility of post-production costs, and continues to analyze how these decisions may impact other cases to which the Company is a party. At this time, the Company cannot predict how these issues may ultimately be resolved, and therefore is also unable to estimate any potential damages, if any, that may result. The Company accrues for litigation, claims and proceedings when liability is both probable and the amount can be reasonably estimated, and does not currently have any material amounts accrued with respect to its pending litigation matters.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2023
Related Parties
Related Parties	(16) Related Parties ​ Substantially all of Antero Midstream’s revenues were and are derived from transactions with Antero Resources. See Note 17—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, 2023
Reportable Segments
Reportable Segments	(17) Reportable Segments (a) Summary of Reportable Segments The Company’s operations, which are located in the United States, are organized into three reportable 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. Substantially all of the Company’s 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. These segments are monitored separately by management for performance and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Management evaluates the performance of the Company’s business segments based on operating income (loss). 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. Exploration and Production The exploration and production segment is engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. 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. Marketing Where feasible, the Company purchases and sells third-party natural gas and NGLs and markets its excess firm transportation capacity, or engages third parties to conduct these activities on the Company’s behalf, in order to optimize the revenues from these transportation agreements. The Company has entered into long-term firm transportation agreements for a significant portion of its current and expected future production in order to secure guaranteed capacity to favorable markets. Equity Method Investment in Antero Midstream The Company receives midstream services through its equity method investment in Antero Midstream. Antero Midstream owns, operates and develops midstream energy infrastructure primarily to service the Company’s production and completion activity in the Appalachian Basin. Antero Midstream’s assets consist of gathering pipelines, compressor stations, interests in processing and fractionation plants and water handling assets. Antero Midstream provides midstream services to Antero Resources under long-term contracts. (b) Reportable Segments Financial Information The operating results and assets of the Company’s reportable segments were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2021 ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,899,486 ​ ​ 718,921 ​ ​ 516 ​ ​ (516) ​ ​ 4,618,407 Intersegment ​ 1,025 ​ ​ — ​ ​ 897,686 ​ ​ (897,686) ​ ​ 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, transportation and water handling ​ ​ 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 property and equipment ​ ​ 90,523 ​ ​ — ​ ​ 5,042 ​ ​ (5,042) ​ ​ 90,523 Other ​ ​ 210,369 ​ ​ 811,698 ​ ​ 8,085 ​ ​ (8,085) ​ ​ 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 Capital expenditures for segment assets ​ $ 715,936 ​ ​ — ​ ​ 232,825 ​ ​ (232,825) ​ ​ 715,936 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 6,720,212 ​ ​ 416,758 ​ ​ 2,622 ​ ​ (2,622) ​ ​ 7,136,970 ​ Intersegment ​ 1,466 ​ ​ — ​ ​ 917,363 ​ ​ (917,363) ​ ​ 1,466 ​ Total revenue ​ ​ 6,721,678 ​ ​ 416,758 ​ ​ 919,985 ​ ​ (919,985) ​ ​ 7,138,436 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 99,595 ​ ​ — ​ ​ — ​ ​ — ​ ​ 99,595 ​ Gathering, compression, processing, transportation and water handling ​ ​ 2,605,380 ​ ​ — ​ ​ 180,254 ​ ​ (180,254) ​ ​ 2,605,380 ​ General and administrative ​ ​ 172,909 ​ ​ — ​ ​ 62,125 ​ ​ (62,125) ​ ​ 172,909 ​ Depletion, depreciation and amortization ​ ​ 680,600 ​ ​ — ​ ​ 131,762 ​ ​ (131,762) ​ ​ 680,600 ​ Impairment of property and equipment ​ ​ 149,731 ​ ​ — ​ ​ 3,702 ​ ​ (3,702) ​ ​ 149,731 ​ Other ​ ​ 325,012 ​ ​ 531,304 ​ ​ 2,676 ​ ​ (2,676) ​ ​ 856,316 ​ Total operating expenses ​ ​ 4,033,227 ​ ​ 531,304 ​ ​ 380,519 ​ ​ (380,519) ​ ​ 4,564,531 ​ Operating income (loss) ​ $ 2,688,451 ​ ​ (114,546) ​ ​ 539,466 ​ ​ (539,466) ​ ​ 2,573,905 ​ Equity in earnings of unconsolidated affiliates ​ $ 72,327 ​ ​ — ​ ​ 94,218 ​ ​ (94,218) ​ ​ 72,327 ​ Capital expenditures for segment assets ​ $ 943,971 ​ ​ — ​ ​ 298,924 ​ ​ (298,924) ​ ​ 943,971 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,473,969 ​ ​ 206,122 ​ ​ 1,414 ​ ​ (1,414) ​ ​ 4,680,091 ​ Intersegment ​ 1,881 ​ ​ — ​ ​ 1,040,357 ​ ​ (1,040,357) ​ ​ 1,881 ​ Total revenue ​ ​ 4,475,850 ​ ​ 206,122 ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ 4,681,972 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 118,441 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,441 ​ Gathering, compression, processing, transportation and water handling ​ ​ 2,642,358 ​ ​ — ​ ​ 213,165 ​ ​ (213,165) ​ ​ 2,642,358 ​ General and administrative ​ ​ 224,516 ​ ​ — ​ ​ 71,068 ​ ​ (71,068) ​ ​ 224,516 ​ Depletion, depreciation and amortization ​ ​ 689,966 ​ ​ — ​ ​ 136,059 ​ ​ (136,059) ​ ​ 689,966 ​ Impairment of property and equipment ​ ​ 51,302 ​ ​ — ​ ​ 146 ​ ​ (146) ​ ​ 51,302 ​ Other ​ ​ 193,531 ​ ​ 308,728 ​ ​ 9,471 ​ ​ (9,471) ​ ​ 502,259 ​ Total operating expenses ​ ​ 3,920,114 ​ ​ 308,728 ​ ​ 429,909 ​ ​ (429,909) ​ ​ 4,228,842 ​ Operating income (loss) ​ $ 555,736 ​ ​ (102,606) ​ ​ 611,862 ​ ​ (611,862) ​ ​ 453,130 ​ Equity in earnings of unconsolidated affiliates ​ $ 82,952 ​ ​ — ​ ​ 105,456 ​ ​ (105,456) ​ ​ 82,952 ​ Capital expenditures for segment assets ​ $ 1,131,863 ​ ​ — ​ ​ 183,733 ​ ​ (183,733) ​ ​ 1,131,863 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total ​ Investments in unconsolidated affiliates ​ $ 220,429 ​ ​ — ​ ​ 652,767 ​ ​ (652,767) ​ ​ 220,429 ​ Total assets ​ ​ 14,081,077 ​ ​ 36,962 ​ ​ 5,791,320 ​ ​ (5,791,320) ​ ​ 14,118,039 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Investments in unconsolidated affiliates ​ $ 222,255 ​ ​ — ​ ​ 626,650 ​ ​ (626,650) ​ ​ 222,255 ​ Total assets ​ ​ 13,602,297 ​ ​ 17,117 ​ ​ 5,737,618 ​ ​ (5,737,618) ​ ​ 13,619,414 ​ ​

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2023
Subsidiary Guarantors
Subsidiary Guarantors	(18) 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 Sheets ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2022 ​ 2023 ​ Current assets ​ $ 739,104 ​ ​ 453,581 ​ Noncurrent assets ​ ​ 12,663,911 ​ ​ 12,562,439 ​ Total assets ​ $ 13,403,015 ​ ​ 13,016,020 ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable, related parties ​ $ 80,708 ​ ​ 86,284 ​ Other current liabilities ​ ​ 1,668,426 ​ ​ 1,360,102 ​ Total current liabilities ​ ​ 1,749,134 ​ ​ 1,446,386 ​ Noncurrent liabilities ​ ​ 5,306,539 ​ ​ 4,951,464 ​ Total liabilities ​ $ 7,055,673 ​ ​ 6,397,850 ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ ​ ​ December 31, 2023 ​ Revenues ​ ​ ​ ​ $ 4,539,184 ​ Operating expenses ​ ​ ​ ​ ​ 4,184,979 ​ Income from operations ​ ​ ​ ​ ​ 354,205 ​ Net income and comprehensive income including noncontrolling interests ​ ​ ​ ​ ​ 242,919 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ ​ ​ ​ $ 242,919 ​ ​

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2023
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	(19) Supplemental Information on Oil and Gas Producing Activities (Unaudited) The tables below 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, ​ ​ 2022 ​ 2023 ​ Proved properties ​ $ 13,234,777 ​ ​ 13,908,804 ​ Unproved properties ​ 997,715 ​ 974,642 ​ Total oil and gas properties ​ 14,232,492 ​ 14,883,446 ​ Accumulated depletion ​ (4,624,674) ​ (4,996,691) ​ Net capitalized costs ​ $ 9,607,818 ​ ​ 9,886,755 ​ ​ (b) Costs Incurred in Certain Oil and Gas Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved property ​ $ 79,138 ​ ​ 149,009 ​ ​ 151,135 ​ Development costs ​ 581,352 ​ ​ 775,106 ​ ​ 956,267 ​ Exploration costs ​ 19,822 ​ ​ 5,543 ​ ​ 8,079 ​ Total costs incurred ​ $ 680,312 ​ ​ 929,658 ​ ​ 1,115,481 ​ ​ ​ (c) Results of Operations for Oil and Gas Producing Activities ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2022 ​ 2023 ​ Revenues ​ $ 5,790,759 ​ ​ 8,294,749 ​ ​ 4,276,445 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 2,793,877 ​ ​ 2,992,381 ​ ​ 2,919,654 ​ Exploration expenses ​ 1,164 ​ ​ 3,651 ​ ​ 2,691 ​ Depletion ​ 735,687 ​ ​ 737,504 ​ ​ 682,109 ​ Impairment of unproved properties ​ 90,523 ​ ​ 98,324 ​ ​ 51,302 ​ Results of operations before income tax expense ​ 2,169,508 ​ ​ 4,462,889 ​ ​ 620,689 ​ Income tax expense ​ (520,168) ​ ​ (959,477) ​ ​ (135,063) ​ Results of operations ​ $ 1,649,340 ​ ​ 3,503,412 ​ ​ 485,626 ​ ​ (d) Oil and Gas Reserves Net proved oil and gas reserves for the years ended December 31, 2021, 2022 and 2023 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 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 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, 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 ​ Revisions ​ 427 ​ 32 ​ (4) ​ 596 ​ Extensions, discoveries and other additions ​ 437 ​ 25 ​ 2 ​ 604 ​ Production ​ (798) ​ (59) ​ (3) ​ (1,170) ​ December 31, 2022 (1) ​ 10,270 ​ 1,217 ​ 31 ​ 17,759 ​ Revisions ​ 863 ​ 54 ​ — ​ 1,187 ​ Extensions, discoveries and other additions ​ 296 ​ 18 ​ 2 ​ 413 ​ Production ​ (815) ​ (67) ​ (4) ​ (1,238) ​ December 31, 2023 (1) ​ 10,614 ​ 1,222 ​ 29 ​ 18,121 ​ (1) Proved reserves for the noncontrolling interests in Martica as of December 31, 2021 were 167 Bcfe, which consisted of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2022 were 92 Bcfe, which consisted of 71 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 (1) ​ 7,395 ​ 876 ​ 17 ​ 12,753 ​ December 31, 2022 (1) ​ 7,699 ​ 930 ​ 16 ​ 13,373 ​ December 31, 2023 (1) ​ 7,912 ​ 963 ​ 15 ​ 13,783 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 (2) ​ 2,809 ​ 343 ​ 19 ​ 4,976 ​ December 31, 2022 (2) ​ 2,571 ​ 287 ​ 15 ​ 4,386 ​ December 31, 2023 (2) ​ 2,702 ​ 259 ​ 14 ​ 4,338 ​ (1) Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2021 were 133 Bcfe, which consisted of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2022 were 91 Bcfe, which consisted of 70 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate. (2) Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2021 were 34 Bcfe, which consisted of 23 Bcf of natural gas, 2 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2022 were 1 Bcfe, which consisted entirely of natural gas. There were no proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2023. Significant changes in proved reserves for the years ended December 31, 2021, 2022 and 2023 include the following: 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: o 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. o Net upward performance revisions of 565 Bcfe. o Upward revisions of 149 Bcfe due to increases in prices for natural gas, NGLs and oil. o Upward revisions of 121 Bcfe are due to an increase in the Company’s assumed future ethane recovery. ● Sales of reserves of 670 Bcfe related to the drilling partnership. 2022 Proved Reserve Changes ● Extensions, discoveries, and other additions of 604 Bcfe resulted from delineation and development drilling in the Appalachian Basin. ● Net upward revisions of 596 Bcfe include: o Net upward revisions of previous estimates of 414 Bcfe primarily due to changes in ownership interests. o Net upward revision of 92 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 692 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 600 Bcfe for locations that were not developed within five years of initial booking as proved reserves. o Upward revisions of 88 Bcfe are due to an increase in the Company’s assumed future ethane recovery. o Upward revisions of 2 Bcfe due to increases in prices for natural gas, NGLs and oil. 2023 Proved Reserve Changes ● Extensions, discoveries, and other additions of 413 Bcfe resulted from delineation and development drilling in the Appalachian Basin. ● Net upward revisions of 1,187 Bcfe include: o Net upward revisions of previous estimates of 814 Bcfe includes 846 Bcfe for increases in the Company’s ownership interests, partially offset by downward revisions of 32 Bcfe related to changes in the Company’s reserve forecast and operation cost estimates. o Net upward revision of 454 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 698 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 244 Bcfe for locations that were not developed within five years of initial booking as proved reserves. o Downward revisions of 81 Bcfe due to decreases in prices for natural gas, NGLs and oil. (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 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 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, ​ ​ ​ 2021 ​ 2022 ​ 2023 Future cash inflows ​ $ 74,622 ​ ​ 109,052 ​ ​ 58,061 ​ Future production costs ​ (34,665) ​ ​ (39,378) ​ ​ (41,887) ​ Future development costs ​ (1,704) ​ ​ (2,073) ​ ​ (2,027) ​ Future net cash flows before income tax ​ 38,253 ​ ​ 67,601 ​ ​ 14,147 ​ Future income tax expense ​ (7,813) ​ ​ (13,692) ​ ​ (2,178) ​ Future net cash flows ​ 30,440 ​ ​ 53,909 ​ ​ 11,969 ​ 10% annual discount for estimated timing of cash flows ​ (17,007) ​ ​ (30,345) ​ ​ (6,874) ​ Standardized measure of discounted future net cash flows (1) ​ $ 13,433 ​ ​ 23,564 ​ ​ 5,095 ​ (1) The standardized measure of discounted future net cash flows for the noncontrolling interests in Martica were $501 million, $458 million and $ 170 million for the years ended December 31, 2021, 2022 and 2023, respectively. The Company used the following 12-month weighted average prices to estimate its total equivalent reserves (per Mcfe): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ 12-month weighted average price ​ $ 4.21 ​ ​ 6.14 ​ ​ 3.20 ​ ​ (f) Changes in Standardized Measure of Discounted Future Net Cash Flow ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ Sales of oil and gas, net of productions costs ​ $ (2,917) ​ ​ (5,302) ​ ​ (1,357) ​ Net changes in prices and production costs (1) ​ 14,099 ​ ​ 13,793 ​ ​ (25,672) ​ Development costs incurred during the period ​ 454 ​ ​ 448 ​ ​ 637 ​ Net changes in future development costs ​ (117) ​ ​ (289) ​ ​ (96) ​ Extensions, discoveries and other additions ​ 504 ​ ​ 1,068 ​ ​ 69 ​ Divestitures ​ ​ (125) ​ ​ — ​ ​ — ​ Revisions of previous quantity estimates ​ 2,543 ​ ​ 1,475 ​ ​ 190 ​ Accretion of discount ​ 121 ​ ​ 1,655 ​ ​ 2,947 ​ Net change in income taxes ​ (3,115) ​ ​ (2,787) ​ ​ 5,069 ​ Changes in timing and other ​ 776 ​ ​ 70 ​ ​ (256) ​ Net increase (decrease) ​ 12,223 ​ ​ 10,131 ​ ​ (18,469) ​ Beginning of year ​ 1,210 ​ ​ 13,433 ​ ​ 23,564 ​ End of year (2) ​ $ 13,433 ​ ​ 23,564 ​ ​ 5,095 ​ (1) The net changes in prices and production costs are calculated prior to the consideration of future income tax expense. The Standardized Measure included future income tax expense of $7.8 billion, $13.7 billion and $2.2 billion for the years ended December 31, 2021, 2022 and 2023, respectively. (2) The standardized measure for the noncontrolling interests in Martica were $501 million, $458 million and $170 million for the years ended December 31, 2021, 2022 and 2023, respectively.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Basis of Presentation	(a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with 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, 2022 and 2023, and its results of operations and cash flows for the years ended December 31, 2021, 2022 and 2023. 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 and its VIE, Martica, for which the Company is the primary beneficiary. All For the years ended December 31, 2021, 2022 and 2023, 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 3—Transactions); and ● Antero provides accounting, administrative and other services to Martica under a Management Services Agreement. The Company accounts for its interest in Antero Midstream Corporation (“Antero Midstream”) using the equity method of accounting. As of December 31, 2022 and 2023, the Company had , respectively, interest in Antero Midstream. 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 affiliate on the Company’s consolidated statements of operations and comprehensive income (loss) 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 affiliate in the statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the 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 LP (“Antero Midstream Partners”) as of March 12, 2019, on such date, the Company deconsolidated Antero Midstream Partners. See Note 5—Equity Method Investments to the consolidated financial statements for further discussion on equity method investments. 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, 2022, the book overdrafts included within accounts payable and revenue distributions payable were million, respectively. As of December 31, 2023, the book overdrafts 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 expensed as incurred. Exploratory drilling costs are initially capitalized, but expensed 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 determines, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or expensed. 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 Company did not incur any impairment expenses associated with its proved properties during the years ended December 31, 2021, 2022 and 2023. As of December 31, 2023, 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. In December 2022, the Company commenced a strategic evaluation of the sand mine at which time, such mine was idled. Accordingly, the Company performed an impairment analysis as of December 31, 2022, and recorded impairment expense of million. There were
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, 2021, 2022 and 2023, 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. 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, 2022, the Company had million of unamortized debt issuance costs included as a reduction to long-term debt. As of December 31, 2023, 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 may enter into derivative transactions from time to time, which contracts may include commodity fixed price swaps, basis swaps, collars 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. Cash flows from derivative instruments are classified in operating activities on the Company’s consolidated statements of cash flows. 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 and comprehensive income (loss). 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, 2022 and 2023, 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.
Deferred Revenue	(o) Deferred Revenue Under the terms of the Company’s volumetric production payment transaction (“VPP”), 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 and comprehensive income (loss).
Concentrations of Credit Risk	(p) 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 Six One Commodities LLC accounted for of total sales for the years ended December 31, 2021 and 2022, respectively. No customer accounted for more than 10% of the Company’s sales for the year ended December 31, 2023. 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, 2023, the Company did not have any commodity derivative assets with bank counterparties under our Credit Facility. 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, 2023 for the counterparty. The Company believes that the counterparty currently is an acceptable credit risk. The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	(q) Income Taxes The Company recognizes deferred income tax assets and liabilities for temporary differences resulting from 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 income 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 income tax assets will not be realized. On July 8, 2022, Pennsylvania enacted new tax laws that are effective January 1, 2023 on a prospective basis that reduce the state’s corporate income tax rate. As a result of this tax law change together with changes in the Company’s apportionment to Pennsylvania, the Company’s net deferred income tax liability was reduced by 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	(r) 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 fixed 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	(s) 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. See Note 17—Reportable Segments to the consolidated financial statements for more information. 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.
Net Income (Loss) Per Common Share	(t) Net Income (Loss) Per Common Share Net income (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. Net income (loss) per common share—diluted for each period is computed after giving consideration to the potential dilution from (i) outstanding equity awards using the treasury stock method and (ii) shares of common stock issuable upon conversion of the 2026 Convertible Notes using the if-converted method. 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. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding is 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 income (loss) attributable to common stockholders for basic and diluted net income (loss) per common share (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders ​ $ (186,899) ​ ​ 1,898,771 ​ ​ 242,919 ​ Add: Interest expense for 2026 Convertible Notes ​ ​ — ​ ​ 3,369 ​ ​ 1,955 ​ Less: Tax-effect of interest expense for 2026 Convertible Notes ​ ​ — ​ ​ (724) ​ ​ (425) ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions ​ $ (186,899) ​ ​ 1,901,416 ​ ​ 244,449 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) per common share—basic ​ $ (0.61) ​ ​ 6.18 ​ ​ 0.81 ​ Net income (loss) per common share—diluted ​ $ (0.61) ​ ​ 5.78 ​ ​ 0.78 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average common shares outstanding—basic ​ ​ 308,146 ​ ​ 307,202 ​ ​ 299,793 ​ Weighted average common shares outstanding—diluted ​ ​ 308,146 ​ ​ 329,223 ​ ​ 311,597 ​ ​ 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, ​ ​ 2021 2022 2023 ​ Basic weighted average number of common shares outstanding ​ 308,146 ​ 307,202 ​ 299,793 ​ Add: Dilutive effect of RSUs ​ — ​ 3,341 ​ 1,379 ​ Add: Dilutive effect of PSUs ​ — ​ 2,005 ​ 989 ​ Add: Dilutive effect of 2026 Convertible Notes ​ — ​ 16,675 ​ 9,436 ​ Diluted weighted average number of common shares outstanding ​ 308,146 ​ 329,223 ​ 311,597 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 6,407 ​ 111 ​ 1,200 ​ PSUs ​ 2,832 ​ 101 ​ 199 ​ Stock options ​ 379 ​ 346 ​ 310 ​ 2026 Convertible Notes ​ 18,778 ​ — ​ — ​ (1) The potential dilutive effects of these awards were excluded from the computation of net income (loss) per common share—diluted because the inclusion of these awards would have been anti-dilutive. ​
Treasury Stock and Share Retirement	(u) Treasury Stock and Share Retirement Treasury stock purchases are recorded at cost. 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 retained earnings (accumulated 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	(v) 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 9
Recently Adopted or Issued Accounting Standards	(w) Recently Adopted or Issued Accounting Standards Convertible Debt 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 31, 2021. The Company adopted the standard effective January 1, 2022 under the modified retrospective transition method, which impacts only the debt instruments outstanding on the adoption date. Upon adoption of this new standard, the Company reclassified $24 million, net of deferred income taxes and equity issuance costs, from additional paid-in capital and increased long-term debt by $27 million, reduced deferred income tax liability by $6 million and reduced accumulated deficit by $3 million as of January 1, 2022. Additionally, annual interest expense for the 2026 Convertible Notes beginning January 1, 2022 is based on an effective interest rate of 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. In December 2023, the FASB issued ASU No. 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 is intended to improve income tax disclosures primarily through enhanced disclosure of income tax rate reconciliation items, and disaggregation of income (loss) from continuing operations, income tax expense (benefit) and income taxes paid, net disclosures by federal, state and foreign jurisdictions, among others. This ASU is effective for annual reporting periods beginning after December 15, 2024, and early adoption is permitted. ASU 2023-07 should be applied on a prospective basis, although retrospective application is permitted. The Company is evaluating the impact that ASC 2023-09 will have on the consolidated financial statements and its plans for adoption, including the adoption date and transition method. Reportable Segments In November 2023, the FASB issued ASU No. 2023-07, Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 is intended to improve reportable segment disclosures primarily through enhanced disclosure of reportable segment expenses. This ASU is effective for annual reporting periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. ASU 2023-07 is required to be applied retrospectively to all prior periods presented in the financial statements. The Company is evaluating the impact that ASU 2023-07 will have on the consolidated financial statements and its plans for adoption, including the adoption date
Natural Gas, NGLs and Oil Revenues
Deferred 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 and comprehensive income (loss). 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
Deferred 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, 2023
Summary of Significant Accounting Policies
Reconciliation of income (loss) attributable to common stockholders for basic and diluted earnings (loss) per share	The following is a reconciliation of the Company’s income (loss) attributable to common stockholders for basic and diluted net income (loss) per common share (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders ​ $ (186,899) ​ ​ 1,898,771 ​ ​ 242,919 ​ Add: Interest expense for 2026 Convertible Notes ​ ​ — ​ ​ 3,369 ​ ​ 1,955 ​ Less: Tax-effect of interest expense for 2026 Convertible Notes ​ ​ — ​ ​ (724) ​ ​ (425) ​ Net income (loss) attributable to Antero Resources Corporation—common shareholders and assumed conversions ​ $ (186,899) ​ ​ 1,901,416 ​ ​ 244,449 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net income (loss) per common share—basic ​ $ (0.61) ​ ​ 6.18 ​ ​ 0.81 ​ Net income (loss) per common share—diluted ​ $ (0.61) ​ ​ 5.78 ​ ​ 0.78 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average common shares outstanding—basic ​ ​ 308,146 ​ ​ 307,202 ​ ​ 299,793 ​ Weighted average common shares outstanding—diluted ​ ​ 308,146 ​ ​ 329,223 ​ ​ 311,597 ​
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, ​ ​ 2021 2022 2023 ​ Basic weighted average number of common shares outstanding ​ 308,146 ​ 307,202 ​ 299,793 ​ Add: Dilutive effect of RSUs ​ — ​ 3,341 ​ 1,379 ​ Add: Dilutive effect of PSUs ​ — ​ 2,005 ​ 989 ​ Add: Dilutive effect of 2026 Convertible Notes ​ — ​ 16,675 ​ 9,436 ​ Diluted weighted average number of common shares outstanding ​ 308,146 ​ 329,223 ​ 311,597 ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share (1) ​ ​ ​ ​ ​ ​ ​ RSUs ​ 6,407 ​ 111 ​ 1,200 ​ PSUs ​ 2,832 ​ 101 ​ 199 ​ Stock options ​ 379 ​ 346 ​ 310 ​ 2026 Convertible Notes ​ 18,778 ​ — ​ — ​ (1) The potential dilutive effects of these awards were excluded from the computation of net income (loss) per common share—diluted because the inclusion of these awards would have been anti-dilutive. ​

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2023
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 17—Reportable Segments to the consolidated financial statements for more information on reportable segments. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ ​ 2021 ​ 2022 2023 Reportable Segment Revenues from contracts with customers: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Natural gas sales ​ $ 3,442,028 ​ ​ 5,520,419 ​ ​ 2,192,349 ​ Exploration and production Natural gas liquids sales (ethane) ​ ​ 206,889 ​ ​ 384,079 ​ ​ 250,116 ​ Exploration and production Natural gas liquids sales (C3+ NGLs) ​ ​ 1,940,610 ​ ​ 2,114,578 ​ ​ 1,586,834 ​ Exploration and production Oil sales ​ ​ 201,232 ​ ​ 275,673 ​ ​ 247,146 ​ Exploration and production Marketing ​ ​ 718,921 ​ ​ 416,758 ​ ​ 206,122 ​ Marketing Other revenue ​ ​ — ​ ​ — ​ ​ 633 ​ Exploration and production Total revenue from contracts with customers ​ ​ 6,509,680 ​ ​ 8,711,507 ​ ​ 4,483,200 ​ ​ Income (loss) from derivatives, deferred revenue and other sources, net ​ ​ (1,890,248) ​ ​ (1,573,071) ​ ​ 198,772 ​ ​ Total revenue ​ $ 4,619,432 ​ ​ 7,138,436 ​ ​ 4,681,972 ​ ​

Equity Method Investment (Table

Equity Method Investment (Tables)	12 Months Ended
	Dec. 31, 2023
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): ​ ​ ​ ​ ​ ​ Balance as of December 31, 2021 (1) ​ $ 232,399 ​ Equity in earnings of unconsolidated affiliate ​ ​ 72,327 ​ Dividends from unconsolidated affiliate ​ ​ (125,138) ​ Elimination of intercompany profit ​ ​ 40,841 ​ Balance as of December 31, 2022 (1) ​ ​ 220,429 ​ Equity in earnings of unconsolidated affiliate ​ ​ 82,952 ​ Dividends from unconsolidated affiliate ​ ​ (125,138) ​ Elimination of intercompany profit ​ ​ 44,012 ​ Balance as of December 31, 2023 (1) ​ $ 222,255 ​ (1) The fair value of the Company’s investment in Antero Midstream as of December 31, 2022 and 2023 was $1.5 billion and $1.7 billion, respectively, based on the quoted market share price of Antero Midstream. The tables set forth below present summarized financial information of Antero Midstream (in thousands): ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Current assets ​ $ 88,993 ​ ​ 91,128 ​ Noncurrent assets ​ ​ 5,702,327 ​ ​ 5,646,490 ​ Total assets ​ $ 5,791,320 ​ ​ 5,737,618 ​ ​ ​ ​ ​ ​ ​ ​ ​ Current liabilities ​ $ 102,077 ​ ​ 96,417 ​ Noncurrent liabilities ​ ​ 3,496,925 ​ ​ 3,489,470 ​ Stockholders' equity ​ ​ 2,192,318 ​ ​ 2,151,731 ​ Total liabilities and stockholders' equity ​ $ 5,791,320 ​ ​ 5,737,618 ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ 2021 2022 ​ 2023 Revenues ​ $ 898,202 ​ ​ 919,985 ​ ​ 1,041,771 Operating expenses ​ ​ 342,875 ​ ​ 380,519 ​ ​ 429,909 Income from operations ​ ​ 555,327 ​ ​ 539,466 ​ ​ 611,862 Net income ​ $ 331,617 ​ ​ 326,242 ​ ​ 371,786 ​

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Capital expenditures ​ $ 57,361 ​ 38,848 ​ Gathering, compression, processing and transportation expenses ​ ​ 162,783 ​ ​ 160,758 ​ Marketing expenses ​ ​ 61,118 ​ ​ 36,428 ​ Interest expense, net ​ 31,892 ​ 33,066 ​ Production and ad valorem taxes ​ ​ 32,536 ​ ​ 51,516 ​ General and administrative expense ​ ​ 32,477 ​ ​ 35,641 ​ Derivative settlements payable ​ ​ 53,732 ​ ​ 1,037 ​ Other ​ 29,889 ​ 24,046 ​ Total accrued liabilities ​ $ 461,788 ​ 381,340 ​ ​

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Long-Term Debt
Schedule of long-term debt	Long-term debt consisted of the following items (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Credit Facility (a) ​ $ 34,800 ​ ​ 417,200 ​ 8.375% senior notes due 2026 (e) ​ ​ 96,870 ​ ​ 96,870 ​ 7.625% senior notes due 2029 (f) ​ ​ 407,115 ​ ​ 407,115 ​ 5.375% senior notes due 2030 (g) ​ ​ 600,000 ​ ​ 600,000 ​ 4.25% convertible senior notes due 2026 (h) ​ ​ 56,932 ​ ​ 26,386 ​ Total principal ​ ​ 1,195,717 ​ ​ 1,547,571 ​ Unamortized debt issuance costs ​ ​ (12,241) ​ ​ (9,975) ​ Long-term debt ​ $ 1,183,476 ​ ​ 1,537,596 ​
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, ​ ​ ​ 2022 ​ 2023 ​ Principal ​ $ 56,932 ​ ​ 26,386 ​ Less: unamortized debt issuance costs ​ ​ (1,159) ​ ​ (404) ​ Net carrying value ​ $ 55,773 ​ ​ 25,982 ​

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
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): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2022 ​ 2023 ​ Beginning balance $ 53,952 ​ 59,485 ​ Obligations incurred ​ 3,456 ​ ​ 1,106 ​ Accretion expense ​ ​ 4,906 ​ ​ 3,244 ​ Settlement of obligations ​ ​ (1,050) ​ ​ (718) ​ Obligations on sold properties ​ ​ (42) ​ ​ — ​ Revisions to prior estimates ​ ​ (1,737) ​ ​ (3,903) ​ Ending balance ​ $ 59,485 ​ ​ 59,214 ​

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Equity-Based Compensation
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, ​ ​ ​ 2021 2022 2023 ​ RSU awards ​ $ 13,232 ​ ​ 18,915 ​ ​ 32,744 ​ PSU awards ​ ​ 4,662 ​ ​ 14,920 ​ ​ 25,322 ​ Converted AM RSU Awards (1) ​ ​ 1,160 ​ ​ 209 ​ ​ 1 ​ Equity awards issued to directors ​ ​ 1,383 ​ ​ 1,399 ​ ​ 1,452 ​ Total expense ​ $ 20,437 ​ ​ 35,443 ​ ​ 59,519 ​ (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 March 13, 2019 (date of deconsolidation) to Antero Midstream Partners based on its proportionate share of Antero Resources’ labor costs. As of December 31, 2023, all Converted AM RSU Awards were fully vested, and there is no remaining unamortized expense attributable to these awards
Summary of RSU award activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 4,676,219 ​ $ 15.29 ​ Granted ​ 1,474,930 ​ ​ 25.90 ​ Vested ​ (2,464,072) ​ ​ 10.92 ​ Forfeited ​ (166,027) ​ ​ 23.83 ​ Total awarded and unvested—December 31, 2023 ​ 3,521,050 ​ $ 22.40 ​
Summary of PSU award activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 1,329,725 ​ $ 23.18 ​ Granted ​ 417,466 ​ ​ 28.51 ​ Vested (1) ​ (335,000) ​ ​ 2.97 ​ Total awarded and unvested—December 31, 2023 ​ 1,412,191 ​ $ 29.54 ​ (1) During the year ended December 31, 2023, the PSUs granted in 2020 that were based on absolute TSR and relative TSR met the performance criteria to achieve vesting at 112% and 126% of target, respectively, and converted into approximately 0.4 million shares of the Company’s common stock.
Schedule of weighted average fair value assumptions used for PSUs granted	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ ​ Dividend yield ​ ​ — % ​ — % ​ — % ​ Volatility ​ ​ 85 % ​ 87 - 88 % ​ 82 % ​ Risk-free interest rate ​ ​ 0.32 % ​ 2.65 - 4.49 % ​ 4.61 % ​ Weighted average fair value of awards granted ​ $ 11.99 ​ ​ 49.32 ​ ​ 33.96 ​ ​
Schedule of Converted AM RSU Awards	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ Average ​ ​ ​ Number ​ Grant Date ​ ​ of Units Fair Value Total awarded and unvested—December 31, 2022 ​ 2,827 ​ $ 12.38 ​ Vested ​ (2,827) ​ ​ 12.38 ​ Total awarded and unvested—December 31, 2023 ​ — ​ $ — ​
Summary of stock option activity	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ Weighted ​ Average ​ ​ ​ ​ ​ ​ ​ Average ​ Remaining ​ Intrinsic ​ ​ ​ Number ​ Exercise ​ Contractual ​ Value ​ ​ of Options Price Life (in thousands) (1) ​ Outstanding—December 31, 2022 ​ 323,960 ​ $ 50.86 ​ 2.0 ​ $ — ​ Expired ​ (65,264) ​ ​ 54.10 ​ — ​ ​ — ​ Outstanding—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ ​ — ​ Vested—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ $ — ​ Exercisable—December 31, 2023 ​ 258,696 ​ $ 50.04 ​ 1.3 ​ $ — ​ (1) Intrinsic values are based on the exercise price of the options and the closing price of Antero Resources’ common stock on the referenced dates.

Fair value (Tables)

Fair value (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value.
Schedule of fair value and carrying value of the Senior Notes and 2026 Convertible Notes	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ December 31, 2023 ​ ​ Fair Carrying Fair Carrying ​ ​ ​ Value (1) ​ Value (2) ​ Value (1) ​ Value (2) ​ 2026 Notes ​ $ 100,987 ​ ​ 96,123 ​ ​ 99,534 ​ ​ 96,351 ​ 2029 Notes ​ ​ 410,860 ​ ​ 402,872 ​ ​ 417,781 ​ ​ 403,441 ​ 2030 Notes ​ ​ 556,260 ​ ​ 593,908 ​ ​ 573,720 ​ ​ 594,622 ​ 2026 Convertible Notes ​ ​ 406,039 ​ ​ 55,773 ​ ​ 138,337 ​ ​ 25,982 ​ Total ​ $ 1,474,146 ​ ​ 1,148,676 ​ ​ 1,229,372 ​ ​ 1,120,396 ​ (1) Fair values are based on Level 2 market data inputs. (2) Carrying values are presented net of unamortized debt issuance costs.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Schedule of call option and embedded put option arrangements	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Embedded ​ ​ ​ ​ ​ ​ ​ ​ Call Option ​ Put Option ​ Commodity / Settlement Period Index Contracted Volume Strike Price Strike Price Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2024 ​ Henry Hub ​ 53,000 MMBtu/day ​ ​ 2.477 /MMBtu ​ ​ 2.527 /MMBtu ​ January-December 2025 ​ Henry Hub ​ 44,000 MMBtu/day ​ ​ 2.564 /MMBtu ​ ​ 2.614 /MMBtu ​ January-December 2026 ​ Henry Hub ​ 32,000 MMBtu/day ​ ​ 2.629 /MMBtu ​ ​ 2.679 /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 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	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ Balance Sheet Location 2022 ​ 2023 ​ Asset derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Embedded derivatives—current ​ Derivative instruments ​ $ 1,900 ​ ​ 5,175 ​ Embedded derivatives—noncurrent ​ Derivative instruments ​ ​ 9,844 ​ ​ 5,570 ​ Total asset derivatives (1) ​ ​ ​ ​ 11,744 ​ ​ 10,745 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability derivatives not designated as hedges for accounting purposes: ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity derivatives—current (2) ​ Derivative instruments ​ ​ 97,765 ​ ​ 15,236 ​ Commodity derivatives—noncurrent (2) ​ Derivative instruments ​ ​ 345,280 ​ ​ 32,764 ​ Total liability derivatives (1) ​ ​ ​ ​ 443,045 ​ ​ 48,000 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Net derivatives liability (1) ​ ​ ​ $ (431,301) ​ ​ (37,255) ​ (1) The fair value of derivative instruments was determined using Level 2 inputs. (2) As of December 31, 2022, $47 million of commodity derivative liabilities, including $28 million of current commodity derivatives and $19 million of noncurrent commodity derivatives, are attributable to the Company’s consolidated VIE, Martica. As of December 31, 2023, approximately $5 million of commodity derivative liabilities, including $3 million of current commodity derivatives and $2 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, 2022 ​ December 31, 2023 ​ ​ ​ ​ ​ ​ ​ 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 ​ $ 276 ​ ​ (276) ​ ​ — ​ ​ 406 ​ ​ (406) ​ ​ — ​ Embedded derivative assets ​ ​ 11,744 ​ ​ — ​ ​ 11,744 ​ ​ 10,745 ​ ​ — ​ ​ 10,745 ​ Commodity derivative liabilities ​ ​ (443,321) ​ ​ 276 ​ ​ (443,045) ​ ​ (48,406) ​ ​ 406 ​ ​ (48,000) ​
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 and comprehensive income (loss) (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operations ​ Year Ended December 31, ​ ​ Location ​ 2021 ​ 2022 2023 ​ Commodity derivative fair value gains (losses) (1) ​ Revenue ​ $ (1,886,551) ​ ​ (1,524,250) ​ ​ 165,448 ​ Embedded derivative fair value gains (losses) (1) ​ Revenue ​ ​ (49,958) ​ ​ (91,586) ​ ​ 876 ​ (1) The fair value of derivative instruments was determined using Level 2 inputs .
VIE, Martica
Schedule of outstanding commodity derivatives for Antero Resources Corporation	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted ​ ​ ​ ​ ​ ​ ​ ​ Average ​ Commodity / Settlement Period Index Contracted Volume Price ​ Natural Gas ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ January-December 2024 ​ Henry Hub ​ 23,885 MMBtu/day ​ ​ 2.33 /MMBtu ​ January-March 2025 ​ Henry Hub ​ 18,021 MMBtu/day ​ ​ 2.53 /MMBtu ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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, 2023
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 2022 2023 ​ Operating Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing plants ​ Operating lease right-of-use assets ​ $ 1,849,116 ​ ​ 1,611,903 ​ Drilling rigs and completion services ​ Operating lease right-of-use assets ​ ​ 85,405 ​ ​ 32,187 ​ Gas gathering lines and compressor stations (1) ​ Operating lease right-of-use assets ​ ​ 1,463,756 ​ ​ 1,283,668 ​ Office space ​ Operating lease right-of-use assets ​ ​ 41,822 ​ ​ 37,706 ​ Vehicles ​ Operating lease right-of-use assets ​ ​ 756 ​ ​ — ​ Other office and field equipment ​ Operating lease right-of-use assets ​ ​ 3,476 ​ ​ 416 ​ Total operating lease right-of-use assets ​ ​ ​ $ 3,444,331 ​ ​ 2,965,880 ​ Operating lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term operating lease liabilities ​ Short-term lease liabilities ​ $ 556,137 ​ ​ 538,954 ​ Long-term operating lease liabilities ​ Long-term lease liabilities ​ ​ 2,888,194 ​ ​ 2,425,785 ​ Total operating lease liabilities ​ ​ ​ $ 3,444,331 ​ ​ 2,964,739 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance Leases ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease right-of-use assets: ​ ​ ​ ​ ​ ​ ​ ​ ​ Vehicles ​ Other property and equipment ​ $ 2,159 ​ ​ 3,771 ​ Total finance lease right-of-use assets (2) ​ ​ ​ $ 2,159 ​ ​ 3,771 ​ Finance lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term finance lease liabilities ​ Short-term lease liabilities ​ $ 499 ​ ​ 1,106 ​ Long-term finance lease liabilities ​ Long-term lease liabilities ​ ​ 1,660 ​ ​ 2,665 ​ Total finance lease liabilities ​ ​ ​ $ 2,159 ​ ​ 3,771 ​ (1) Gas gathering lines and compressor stations includes $1.4 billion and $ 1.3 billion related to Antero Midstream as of December 31, 2022 and 2023, respectively. See “—Related party lease disclosure” for additional discussion. (2) Financing lease assets are recorded net of accumulated amortization of $1 million as of December 31, 2022 and 2023.
Summary of costs associated with operating leases and finance leases	Costs associated with operating and finance leases were included in the consolidated financial statements as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ Cost Classification Location 2021 2022 2023 ​ Operating lease cost ​ Statement of operations ​ Gathering, compression, processing and transportation ​ $ 1,518,305 ​ ​ 1,481,022 ​ ​ 1,623,268 ​ Operating lease cost ​ Statement of operations ​ General and administrative ​ ​ 10,901 ​ ​ 11,472 ​ ​ 12,121 ​ Operating lease cost ​ Statement of operations ​ Contract termination ​ ​ 4,213 ​ ​ 12,000 ​ ​ 4,227 ​ Operating lease cost ​ Statement of operations ​ Lease operating ​ ​ 142 ​ ​ 177 ​ ​ 84 ​ Operating lease cost ​ Balance sheet ​ Proved properties (1) ​ ​ 103,741 ​ ​ 123,756 ​ ​ 160,638 ​ Total operating lease cost ​ ​ ​ ​ ​ $ 1,637,302 ​ ​ 1,628,427 ​ ​ 1,800,338 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Finance lease cost: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Amortization of right-of-use assets ​ Statement of operations ​ Depletion, depreciation and amortization ​ $ 522 ​ ​ 351 ​ ​ 1,530 ​ Interest on lease liabilities ​ Statement of operations ​ Interest expense ​ ​ 352 ​ ​ 193 ​ ​ 597 ​ Total finance lease cost ​ ​ ​ ​ ​ $ 874 ​ ​ 544 ​ ​ 2,127 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Short-term lease payments ​ ​ ​ ​ ​ $ 86,039 ​ ​ 141,470 ​ ​ 137,781 ​ (1) Capitalized costs related to drilling and completion activities.
Summary of supplemental cash flow information related to leases	The following table presents the Company’s supplemental cash flow information related to leases (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 ​ Cash paid for amounts included in the measurement of lease liabilities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating cash flows from operating leases $ 1,352,941 ​ ​ 1,380,968 ​ ​ 1,366,677 ​ Operating cash flows from finance leases ​ 352 ​ ​ 193 ​ ​ 597 ​ Investing cash flows from operating leases ​ 88,910 ​ ​ 103,244 ​ ​ 126,483 ​ Financing cash flows from finance leases ​ 859 ​ ​ 575 ​ ​ 830 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Noncash activities: ​ ​ ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease obligations $ 437,045 ​ ​ 366,194 ​ ​ 76,797 ​ Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net (1) $ 702,512 ​ ​ 154,101 ​ ​ (15,858) ​ ​ (1) 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. During the year ended December 31, 2022, the weighted average discount rate for remeasured operating leases decreased from 5.6% as of December 31, 2021 to 5.2% as of December 31, 2022. During the year ended December 31, 2023, the weighted average discount rate for remeasured operating leases increased from 5.1% as of December 31, 2022 to 6.5% as of December 31, 2023.
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, 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2024 ​ $ 699,335 ​ ​ 1,628 ​ ​ 700,963 ​ 2025 ​ ​ 608,160 ​ ​ 1,585 ​ ​ 609,745 ​ 2026 ​ ​ 555,915 ​ ​ 1,230 ​ ​ 557,145 ​ 2027 ​ ​ 457,782 ​ ​ 197 ​ ​ 457,979 ​ 2028 ​ ​ 379,922 ​ ​ 23 ​ ​ 379,945 ​ Thereafter ​ ​ 872,055 ​ ​ 9 ​ ​ 872,064 ​ Total lease payments ​ ​ 3,573,169 ​ ​ 4,672 ​ ​ 3,577,841 ​ Less: imputed interest ​ ​ (608,430) ​ ​ (901) ​ ​ (609,331) ​ Total ​ $ 2,964,739 ​ ​ 3,771 ​ ​ 2,968,510 ​ ​
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, 2022 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating Leases ​ Financing Leases ​ Total ​ 2024 ​ $ 699,335 ​ ​ 1,628 ​ ​ 700,963 ​ 2025 ​ ​ 608,160 ​ ​ 1,585 ​ ​ 609,745 ​ 2026 ​ ​ 555,915 ​ ​ 1,230 ​ ​ 557,145 ​ 2027 ​ ​ 457,782 ​ ​ 197 ​ ​ 457,979 ​ 2028 ​ ​ 379,922 ​ ​ 23 ​ ​ 379,945 ​ Thereafter ​ ​ 872,055 ​ ​ 9 ​ ​ 872,064 ​ Total lease payments ​ ​ 3,573,169 ​ ​ 4,672 ​ ​ 3,577,841 ​ Less: imputed interest ​ ​ (608,430) ​ ​ (901) ​ ​ (609,331) ​ Total ​ $ 2,964,739 ​ ​ 3,771 ​ ​ 2,968,510 ​ ​
Summary of weighted-average remaining lease term and discount rate	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 ​ December 31, 2023 ​ ​ ​ ​ Operating Leases ​ Finance Leases ​ Operating Leases ​ Finance Leases ​ ​ Weighted average remaining lease term ​ 7.2 years ​ 3.5 years ​ 6.5 years ​ 3.0 years ​ ​ Weighted average discount rate ​ 5.3 % 7.4 % 5.9 % 8.3 % ​

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Taxes
Schedule of income tax expense (benefit)	The Company’s income tax expense (benefit) consisted of the following (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 2022 2023 Current income tax expense ​ $ 216 ​ ​ 847 ​ ​ 1,587 ​ Deferred income tax expense (benefit) ​ (74,293) ​ 447,845 ​ 74,407 ​ Total income tax expense (benefit) ​ $ (74,077) ​ ​ 448,692 ​ ​ 75,994 ​
Schedule of reconciliation of income tax expense (benefit)	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, ​ ​ 2021 2022 2023 Federal income tax expense (benefit) ​ $ (47,919) ​ ​ 519,679 ​ ​ 87,746 ​ State income tax expense (benefit), net of federal effect ​ (6,576) ​ 12,461 ​ 3,512 ​ Change in state tax rate, net of federal effect ​ ​ (30,910) ​ ​ (52,747) ​ ​ 11,417 ​ Equity-based compensation ​ 1,117 ​ (9,717) ​ (772) ​ Dividends received deduction ​ ​ (3,832) ​ ​ (1,749) ​ ​ (3,186) ​ Noncontrolling interests ​ ​ (7,862) ​ ​ (27,347) ​ ​ (21,525) ​ Change in valuation allowance ​ 4,606 ​ 7,070 ​ (2,567) ​ Nondeductible loss on 2026 Convertible Notes equitizations and inducement ​ ​ 12,174 ​ ​ 36 ​ ​ 81 ​ Other ​ 5,125 ​ 1,006 ​ 1,288 ​ Total income tax expense (benefit) ​ $ (74,077) ​ ​ 448,692 ​ ​ 75,994 ​
Schedule of net deferred tax assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2022 2023 ​ Deferred income tax assets: ​ ​ ​ ​ ​ ​ ​ NOL carryforwards ​ $ 282,829 ​ ​ 281,217 ​ Interest expense carryforwards ​ ​ — ​ ​ 25,258 ​ Equity-based compensation ​ ​ 3,362 ​ ​ 7,056 ​ Investment in Antero Midstream ​ ​ 254,164 ​ ​ 234,423 ​ Unrealized losses on derivative instruments ​ ​ 83,269 ​ ​ 51,025 ​ Lease liabilities ​ ​ 740,254 ​ ​ 644,622 ​ Asset retirement obligations and other ​ ​ 15,859 ​ ​ 17,093 ​ Total deferred income tax assets ​ ​ 1,379,737 ​ ​ 1,260,694 ​ Valuation allowance ​ ​ (57,375) ​ ​ (54,805) ​ Deferred income tax assets, net ​ ​ 1,322,362 ​ ​ 1,205,889 ​ Deferred income tax liabilities: ​ ​ ​ ​ ​ ​ ​ Oil and gas properties ​ ​ 1,295,847 ​ ​ 1,338,442 ​ Lease right-of-use assets ​ ​ 740,254 ​ ​ 644,870 ​ Investment in Martica ​ ​ 45,507 ​ ​ 55,759 ​ 2026 Convertible Notes and other ​ ​ 615 ​ ​ 1,086 ​ Total deferred income tax liabilities ​ ​ 2,082,223 ​ ​ 2,040,157 ​ Deferred tax liability, net ​ $ (759,861) ​ ​ (834,268) ​

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments
Schedule of future minimum payments 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 the Company’s contractual obligations, which include leases that have a lease term in excess of one year as of December 31, 2023 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Processing, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gathering, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Firm ​ Compression ​ Operating and ​ Imputed Interest ​ ​ ​ ​ ​ ​ ​ Transportation ​ and Water Service ​ Financing Leases ​ for Leases ​ Other ​ ​ ​ ​ (a) (b) (c) (c) (d) Total 2024 ​ $ 1,171,743 ​ ​ 67,201 ​ ​ 540,101 ​ ​ 160,862 ​ ​ 8,412 ​ ​ 1,948,319 ​ 2025 ​ ​ 1,158,209 ​ ​ 55,853 ​ ​ 479,666 ​ ​ 130,080 ​ ​ 4,875 ​ ​ 1,828,683 ​ 2026 ​ ​ 1,155,797 ​ ​ 22,676 ​ ​ 455,118 ​ ​ 102,027 ​ ​ 2,250 ​ ​ 1,737,868 ​ 2027 ​ ​ 1,151,152 ​ ​ 21,387 ​ ​ 381,598 ​ ​ 76,380 ​ ​ — ​ ​ 1,630,517 ​ 2028 ​ ​ 1,095,015 ​ ​ 20,054 ​ ​ 324,786 ​ ​ 55,159 ​ ​ — ​ ​ 1,495,014 ​ Thereafter ​ ​ 4,382,740 ​ ​ 77,753 ​ ​ 787,241 ​ ​ 84,823 ​ ​ — ​ ​ 5,332,557 ​ Total ​ $ 10,114,656 ​ ​ 264,924 ​ ​ 2,968,510 ​ ​ 609,331 ​ ​ 15,537 ​ ​ 13,972,958 ​

Reportable Segments (Tables)

Reportable Segments (Tables)	12 Months Ended
	Dec. 31, 2023
Reportable Segments
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, 2021 ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 3,899,486 ​ ​ 718,921 ​ ​ 516 ​ ​ (516) ​ ​ 4,618,407 Intersegment ​ 1,025 ​ ​ — ​ ​ 897,686 ​ ​ (897,686) ​ ​ 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, transportation and water handling ​ ​ 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 property and equipment ​ ​ 90,523 ​ ​ — ​ ​ 5,042 ​ ​ (5,042) ​ ​ 90,523 Other ​ ​ 210,369 ​ ​ 811,698 ​ ​ 8,085 ​ ​ (8,085) ​ ​ 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 Capital expenditures for segment assets ​ $ 715,936 ​ ​ — ​ ​ 232,825 ​ ​ (232,825) ​ ​ 715,936 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 6,720,212 ​ ​ 416,758 ​ ​ 2,622 ​ ​ (2,622) ​ ​ 7,136,970 ​ Intersegment ​ 1,466 ​ ​ — ​ ​ 917,363 ​ ​ (917,363) ​ ​ 1,466 ​ Total revenue ​ ​ 6,721,678 ​ ​ 416,758 ​ ​ 919,985 ​ ​ (919,985) ​ ​ 7,138,436 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 99,595 ​ ​ — ​ ​ — ​ ​ — ​ ​ 99,595 ​ Gathering, compression, processing, transportation and water handling ​ ​ 2,605,380 ​ ​ — ​ ​ 180,254 ​ ​ (180,254) ​ ​ 2,605,380 ​ General and administrative ​ ​ 172,909 ​ ​ — ​ ​ 62,125 ​ ​ (62,125) ​ ​ 172,909 ​ Depletion, depreciation and amortization ​ ​ 680,600 ​ ​ — ​ ​ 131,762 ​ ​ (131,762) ​ ​ 680,600 ​ Impairment of property and equipment ​ ​ 149,731 ​ ​ — ​ ​ 3,702 ​ ​ (3,702) ​ ​ 149,731 ​ Other ​ ​ 325,012 ​ ​ 531,304 ​ ​ 2,676 ​ ​ (2,676) ​ ​ 856,316 ​ Total operating expenses ​ ​ 4,033,227 ​ ​ 531,304 ​ ​ 380,519 ​ ​ (380,519) ​ ​ 4,564,531 ​ Operating income (loss) ​ $ 2,688,451 ​ ​ (114,546) ​ ​ 539,466 ​ ​ (539,466) ​ ​ 2,573,905 ​ Equity in earnings of unconsolidated affiliates ​ $ 72,327 ​ ​ — ​ ​ 94,218 ​ ​ (94,218) ​ ​ 72,327 ​ Capital expenditures for segment assets ​ $ 943,971 ​ ​ — ​ ​ 298,924 ​ ​ (298,924) ​ ​ 943,971 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Sales and revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Third-party ​ $ 4,473,969 ​ ​ 206,122 ​ ​ 1,414 ​ ​ (1,414) ​ ​ 4,680,091 ​ Intersegment ​ 1,881 ​ ​ — ​ ​ 1,040,357 ​ ​ (1,040,357) ​ ​ 1,881 ​ Total revenue ​ ​ 4,475,850 ​ ​ 206,122 ​ ​ 1,041,771 ​ ​ (1,041,771) ​ ​ 4,681,972 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Lease operating ​ ​ 118,441 ​ ​ — ​ ​ — ​ ​ — ​ ​ 118,441 ​ Gathering, compression, processing, transportation and water handling ​ ​ 2,642,358 ​ ​ — ​ ​ 213,165 ​ ​ (213,165) ​ ​ 2,642,358 ​ General and administrative ​ ​ 224,516 ​ ​ — ​ ​ 71,068 ​ ​ (71,068) ​ ​ 224,516 ​ Depletion, depreciation and amortization ​ ​ 689,966 ​ ​ — ​ ​ 136,059 ​ ​ (136,059) ​ ​ 689,966 ​ Impairment of property and equipment ​ ​ 51,302 ​ ​ — ​ ​ 146 ​ ​ (146) ​ ​ 51,302 ​ Other ​ ​ 193,531 ​ ​ 308,728 ​ ​ 9,471 ​ ​ (9,471) ​ ​ 502,259 ​ Total operating expenses ​ ​ 3,920,114 ​ ​ 308,728 ​ ​ 429,909 ​ ​ (429,909) ​ ​ 4,228,842 ​ Operating income (loss) ​ $ 555,736 ​ ​ (102,606) ​ ​ 611,862 ​ ​ (611,862) ​ ​ 453,130 ​ Equity in earnings of unconsolidated affiliates ​ $ 82,952 ​ ​ — ​ ​ 105,456 ​ ​ (105,456) ​ ​ 82,952 ​ Capital expenditures for segment assets ​ $ 1,131,863 ​ ​ — ​ ​ 183,733 ​ ​ (183,733) ​ ​ 1,131,863 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2022 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total ​ Investments in unconsolidated affiliates ​ $ 220,429 ​ ​ — ​ ​ 652,767 ​ ​ (652,767) ​ ​ 220,429 ​ Total assets ​ ​ 14,081,077 ​ ​ 36,962 ​ ​ 5,791,320 ​ ​ (5,791,320) ​ ​ 14,118,039 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, 2023 ​ ​ ​ ​ ​ ​ ​ Equity Method ​ ​ ​ ​ ​ ​ ​ Exploration ​ ​ ​ Investment in ​ Elimination of ​ ​ ​ ​ ​ and ​ ​ ​ Antero ​ Unconsolidated ​ Consolidated ​ ​ Production Marketing Midstream Affiliate Total Investments in unconsolidated affiliates ​ $ 222,255 ​ ​ — ​ ​ 626,650 ​ ​ (626,650) ​ ​ 222,255 ​ Total assets ​ ​ 13,602,297 ​ ​ 17,117 ​ ​ 5,737,618 ​ ​ (5,737,618) ​ ​ 13,619,414 ​ ​

Subsidiary Guarantors (Tables)

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2023
Subsidiary Guarantors
Schedule of summarized financial information of Antero and its guarantor subsidiaries	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 Sheets ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ ​ 2022 ​ 2023 ​ Current assets ​ $ 739,104 ​ ​ 453,581 ​ Noncurrent assets ​ ​ 12,663,911 ​ ​ 12,562,439 ​ Total assets ​ $ 13,403,015 ​ ​ 13,016,020 ​ ​ ​ ​ ​ ​ ​ ​ ​ Accounts payable, related parties ​ $ 80,708 ​ ​ 86,284 ​ Other current liabilities ​ ​ 1,668,426 ​ ​ 1,360,102 ​ Total current liabilities ​ ​ 1,749,134 ​ ​ 1,446,386 ​ Noncurrent liabilities ​ ​ 5,306,539 ​ ​ 4,951,464 ​ Total liabilities ​ $ 7,055,673 ​ ​ 6,397,850 ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended ​ ​ ​ ​ ​ ​ December 31, 2023 ​ Revenues ​ ​ ​ ​ $ 4,539,184 ​ Operating expenses ​ ​ ​ ​ ​ 4,184,979 ​ Income from operations ​ ​ ​ ​ ​ 354,205 ​ Net income and comprehensive income including noncontrolling interests ​ ​ ​ ​ ​ 242,919 ​ Net income and comprehensive income attributable to Antero Resources Corporation ​ ​ ​ ​ $ 242,919 ​ ​

Supplemental Information on O_2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Schedule of capitalized costs relating to oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2022 ​ 2023 ​ Proved properties ​ $ 13,234,777 ​ ​ 13,908,804 ​ Unproved properties ​ 997,715 ​ 974,642 ​ Total oil and gas properties ​ 14,232,492 ​ 14,883,446 ​ Accumulated depletion ​ (4,624,674) ​ (4,996,691) ​ Net capitalized costs ​ $ 9,607,818 ​ ​ 9,886,755 ​
Schedule of costs incurred in certain oil and gas activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ Acquisition costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Unproved property ​ $ 79,138 ​ ​ 149,009 ​ ​ 151,135 ​ Development costs ​ 581,352 ​ ​ 775,106 ​ ​ 956,267 ​ Exploration costs ​ 19,822 ​ ​ 5,543 ​ ​ 8,079 ​ Total costs incurred ​ $ 680,312 ​ ​ 929,658 ​ ​ 1,115,481 ​
Schedule of results of operations for oil and gas producing activities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ 2021 ​ 2022 ​ 2023 ​ Revenues ​ $ 5,790,759 ​ ​ 8,294,749 ​ ​ 4,276,445 ​ Operating expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Production expenses ​ 2,793,877 ​ ​ 2,992,381 ​ ​ 2,919,654 ​ Exploration expenses ​ 1,164 ​ ​ 3,651 ​ ​ 2,691 ​ Depletion ​ 735,687 ​ ​ 737,504 ​ ​ 682,109 ​ Impairment of unproved properties ​ 90,523 ​ ​ 98,324 ​ ​ 51,302 ​ Results of operations before income tax expense ​ 2,169,508 ​ ​ 4,462,889 ​ ​ 620,689 ​ Income tax expense ​ (520,168) ​ ​ (959,477) ​ ​ (135,063) ​ Results of operations ​ $ 1,649,340 ​ ​ 3,503,412 ​ ​ 485,626 ​
Schedule of proved developed and undeveloped reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ 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 ​ Revisions ​ 427 ​ 32 ​ (4) ​ 596 ​ Extensions, discoveries and other additions ​ 437 ​ 25 ​ 2 ​ 604 ​ Production ​ (798) ​ (59) ​ (3) ​ (1,170) ​ December 31, 2022 (1) ​ 10,270 ​ 1,217 ​ 31 ​ 17,759 ​ Revisions ​ 863 ​ 54 ​ — ​ 1,187 ​ Extensions, discoveries and other additions ​ 296 ​ 18 ​ 2 ​ 413 ​ Production ​ (815) ​ (67) ​ (4) ​ (1,238) ​ December 31, 2023 (1) ​ 10,614 ​ 1,222 ​ 29 ​ 18,121 ​ (1) Proved reserves for the noncontrolling interests in Martica as of December 31, 2021 were 167 Bcfe, which consisted of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2022 were 92 Bcfe, which consisted of 71 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Oil and ​ ​ ​ ​ ​ Natural Gas ​ NGLs ​ Condensate ​ Equivalents ​ ​ ​ (Bcf) ​ (MMBbl) ​ (MMBbl) ​ (Bcfe) ​ Proved developed reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 (1) ​ 7,395 ​ 876 ​ 17 ​ 12,753 ​ December 31, 2022 (1) ​ 7,699 ​ 930 ​ 16 ​ 13,373 ​ December 31, 2023 (1) ​ 7,912 ​ 963 ​ 15 ​ 13,783 ​ Proved undeveloped reserves: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2021 (2) ​ 2,809 ​ 343 ​ 19 ​ 4,976 ​ December 31, 2022 (2) ​ 2,571 ​ 287 ​ 15 ​ 4,386 ​ December 31, 2023 (2) ​ 2,702 ​ 259 ​ 14 ​ 4,338 ​ (1) Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2021 were 133 Bcfe, which consisted of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2022 were 91 Bcfe, which consisted of 70 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate. (2) Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2021 were 34 Bcfe, which consisted of 23 Bcf of natural gas, 2 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2022 were 1 Bcfe, which consisted entirely of natural gas. There were no proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2023.
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 Future cash inflows ​ $ 74,622 ​ ​ 109,052 ​ ​ 58,061 ​ Future production costs ​ (34,665) ​ ​ (39,378) ​ ​ (41,887) ​ Future development costs ​ (1,704) ​ ​ (2,073) ​ ​ (2,027) ​ Future net cash flows before income tax ​ 38,253 ​ ​ 67,601 ​ ​ 14,147 ​ Future income tax expense ​ (7,813) ​ ​ (13,692) ​ ​ (2,178) ​ Future net cash flows ​ 30,440 ​ ​ 53,909 ​ ​ 11,969 ​ 10% annual discount for estimated timing of cash flows ​ (17,007) ​ ​ (30,345) ​ ​ (6,874) ​ Standardized measure of discounted future net cash flows (1) ​ $ 13,433 ​ ​ 23,564 ​ ​ 5,095 ​ (1) The standardized measure of discounted future net cash flows for the noncontrolling interests in Martica were $501 million, $458 million and $ 170 million for the years ended December 31, 2021, 2022 and 2023, respectively.
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ 12-month weighted average price ​ $ 4.21 ​ ​ 6.14 ​ ​ 3.20 ​
Schedule of changes in standardized measure of discounted future net cash flow	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year Ended December 31, ​ ​ ​ 2021 ​ 2022 ​ 2023 ​ Sales of oil and gas, net of productions costs ​ $ (2,917) ​ ​ (5,302) ​ ​ (1,357) ​ Net changes in prices and production costs (1) ​ 14,099 ​ ​ 13,793 ​ ​ (25,672) ​ Development costs incurred during the period ​ 454 ​ ​ 448 ​ ​ 637 ​ Net changes in future development costs ​ (117) ​ ​ (289) ​ ​ (96) ​ Extensions, discoveries and other additions ​ 504 ​ ​ 1,068 ​ ​ 69 ​ Divestitures ​ ​ (125) ​ ​ — ​ ​ — ​ Revisions of previous quantity estimates ​ 2,543 ​ ​ 1,475 ​ ​ 190 ​ Accretion of discount ​ 121 ​ ​ 1,655 ​ ​ 2,947 ​ Net change in income taxes ​ (3,115) ​ ​ (2,787) ​ ​ 5,069 ​ Changes in timing and other ​ 776 ​ ​ 70 ​ ​ (256) ​ Net increase (decrease) ​ 12,223 ​ ​ 10,131 ​ ​ (18,469) ​ Beginning of year ​ 1,210 ​ ​ 13,433 ​ ​ 23,564 ​ End of year (2) ​ $ 13,433 ​ ​ 23,564 ​ ​ 5,095 ​ (1) The net changes in prices and production costs are calculated prior to the consideration of future income tax expense. The Standardized Measure included future income tax expense of $7.8 billion, $13.7 billion and $2.2 billion for the years ended December 31, 2021, 2022 and 2023, respectively. (2) The standardized measure for the noncontrolling interests in Martica were $501 million, $458 million and $170 million for the years ended December 31, 2021, 2022 and 2023, respectively.

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation (Details)	Dec. 31, 2023	Dec. 31, 2022
Antero Midstream Corporation
Equity Method Investments
Ownership percentage	29%	29.10%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounts Payable
Basis of Presentation
Book overdrafts	$ 11	$ 28
Revenue distributions payable
Basis of Presentation
Book overdrafts	$ 19	$ 43

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Other Property and equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property and Equipment
Depreciation expense	$ 689,966	$ 680,600	$ 742,009
Oil and Gas Properties
Impairment of unproved oil and gas properties	51,000	98,000	91,000
Depreciation, depletion, and amortization expense for oil and gas properties	682,000	738,000	736,000
Impairment of long-lived assets other than oil and gas properties	0	48,000	0
Deferred Financing Costs
Amortization and write off related to deferred debt issuance costs	4,000	4,000	7,000
Other long term assets
Deferred Financing Costs
Unamortized debt issuance costs	5,000	6,000
Long-term debt
Deferred Financing Costs
Unamortized debt issuance costs	10,000	12,000
Other property and equipment
Property and Equipment
Depreciation expense	$ 8,000	$ 4,000	$ 6,000
Other property and equipment | Minimum
Property and Equipment
Estimated useful life	2 years
Other property and equipment | Maximum
Property and Equipment
Estimated useful life	20 years

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Concentrations Credit Risk (Details) - Counterparty	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2023
Concentrations of Credit Risk
Number Of Counterparties			3
Six One Commodities LLC | Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	12%	10%

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Income Taxes (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Summary of Significant Accounting Policies
Reduction of deferred tax liability due to change in the enacted tax rate, net of the change in the Company's state apportionment	$ (41)

Summary of Significant Accoun_9

Summary of Significant Accounting Policies - Reconciliation of Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary of Significant Accounting Policies
Net income (loss) attributable to Antero Resources Corporation-common shareholders	$ 242,919	$ 1,898,771	$ (186,899)
Add: Interest expense for 2026 Convertible Notes	1,955	3,369
Less: Tax-effect of interest expense for 2026 Convertible Notes	(425)	(724)
Net income (loss) attributable to Antero Resources Corporation-common shareholders and assumed conversions	$ 244,449	$ 1,901,416	$ (186,899)
Net income (loss) per common share-basic (in dollars per share)	$ 0.81	$ 6.18	$ (0.61)
Net income (loss) per common share-diluted (in dollars per share)	$ 0.78	$ 5.78	$ (0.61)
Weighted average common shares outstanding-basic (in shares)	299,793	307,202	308,146
Weighted average common shares outstanding-diluted (in shares)	311,597	329,223	308,146

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Reconciliation of Weighted Average Shares Outstanding (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income (loss) per common share
Basic weighted average number of common shares outstanding	299,793	307,202	308,146
Diluted weighted average number of common shares outstanding	311,597	329,223	308,146
RSUs
Income (loss) per common share
Add: Dilutive effect	1,379	3,341
Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share	1,200	111	6,407
PSUs
Income (loss) per common share
Add: Dilutive effect	989	2,005
Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share	199	101	2,832
Employee Stock Option [Member]
Income (loss) per common share
Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share	310	346	379
4.25% convertible senior notes due 2026
Income (loss) per common share
Add: Dilutive effect	9,436	16,675
Weighted average number of outstanding securities excluded from calculation of diluted net income (loss) per common share			18,778

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Recently Adopted or Issued Accounting Standards (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Jan. 01, 2022	Dec. 31, 2021	Aug. 21, 2020
Recently Issued Accounting Standards
Additional paid-in capital	$ 5,846,541	$ 5,838,848
Long-term debt	1,537,596	1,183,476
Deferred income tax liability, net	834,268	759,861
Retained earnings	1,131,828	913,896
4.25% convertible senior notes due 2026
Recently Issued Accounting Standards
Long-term debt	$ 25,982	$ 55,773
Effective interest rate (as a percent)				15.30%	15.30%
Accounting Standards Update 2020-06 | Adjustment Effect
Recently Issued Accounting Standards
Additional paid-in capital			$ (24,000)
Long-term debt			27,000
Deferred income tax liability, net			(6,000)
Retained earnings			$ 3,000
Accounting Standards Update 2020-06 | Adjustment Effect | 4.25% convertible senior notes due 2026
Recently Issued Accounting Standards
Effective interest rate (as a percent)			4.90%

Transactions (Details)

Transactions (Details) ft in Thousands, $ in Thousands			12 Months Ended
	Feb. 17, 2021 tranche	Jun. 15, 2020 USD ($) ft	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Mar. 31, 2023
Transactions
Cash contribution					$ 51,000
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%
Portion Of overriding royalty interest remaining with Martica							0.48%
Portion of Incremental Override remaining with Martica							24%
Percentage of distributions received		85%
Percentage of distributions received on Incremental Override		76%
ORRI | Sixth Street
Transactions
Cash contribution		$ 300,000
Additional contribution upon achievement of production target		$ 102,000
Cash distributions received					$ 102,000	$ 102,000
Internal rate of return threshold		13%
Cash on cash return threshold		150%
Percentage of distributions received on Incremental Override		24%
Drilling Partnership | QL
Transactions
Number of tranches | tranche	4
Percent of total development capital spending funded by drilling partner			15%	15%	20%
Percent of total development capital spending in the next year to be funded by drilling partner			20%
Amount of carry received from drilling partner.			$ 29,000	$ 29,000
Gain (loss) on interests conveyed			$ 0	$ 0	$ 0

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue
Revenue	$ 4,483,200	$ 8,711,507	$ 6,509,680
Income (loss) from derivatives, deferred revenue and other sources, net	198,772	(1,573,071)	(1,890,248)
Total revenue	4,681,972	7,138,436	4,619,432
Natural gas sales
Disaggregation of Revenue
Total revenue	2,192,349	5,520,419	3,442,028
Oil sales
Disaggregation of Revenue
Total revenue	247,146	275,673	201,232
Marketing
Disaggregation of Revenue
Total revenue	206,122	416,758	718,921
Exploration and production | Natural gas sales
Disaggregation of Revenue
Revenue	2,192,349	5,520,419	3,442,028
Exploration and production | Natural gas liquids sales (ethane)
Disaggregation of Revenue
Revenue	250,116	384,079	206,889
Exploration and production | Natural gas liquids sales (C3+ NGLs)
Disaggregation of Revenue
Revenue	1,586,834	2,114,578	1,940,610
Exploration and production | Oil sales
Disaggregation of Revenue
Revenue	247,146	275,673	201,232
Exploration and production | Other
Disaggregation of Revenue
Revenue	633
Marketing | Marketing
Disaggregation of Revenue
Revenue	$ 206,122	$ 416,758	$ 718,921

Revenue - Transaction Price All

Revenue - Transaction Price Allocation and Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenue
Original expected duration	true
Receivables from contracts with customers	$ 400,805	$ 707,685

Equity Method Investment (Detai

Equity Method Investment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Investments in unconsolidated affiliates
Equity in earnings of unconsolidated affiliate	$ 82,952	$ 72,327	$ 77,085
Dividends from unconsolidated affiliate	(125,138)	(125,138)	(136,609)
Summarized Financial Information
Current assets	475,692	787,525
Total assets	13,619,414	14,118,039
Current liabilities	1,452,091	1,774,909
Stockholders' equity	7,214,102	7,017,154	6,066,092	$ 6,090,271
Total liabilities and equity	13,619,414	14,118,039
Revenues	4,681,972	7,138,436	4,619,432
Operating expenses	4,228,842	4,564,531	4,595,572
Income from operations	453,130	2,573,905	23,860
Net income	$ 341,844	$ 2,025,972	(154,109)
Antero Midstream Corporation
Equity Method Investments
Ownership percentage	29%	29.10%
Investments in unconsolidated affiliates
Balance at beginning of period	$ 220,429	$ 232,399
Equity in earnings of unconsolidated affiliate	82,952	72,327
Dividends from unconsolidated affiliate	(125,138)	(125,138)
Elimination of intercompany profit	44,012	40,841
Balance at end of period	222,255	220,429	232,399
Fair value of investment	1,700,000	1,500,000
Antero Midstream Corporation
Summarized Financial Information
Current assets	91,128	88,993
Noncurrent assets	5,646,490	5,702,327
Total assets	5,737,618	5,791,320
Current liabilities	96,417	102,077
Noncurrent liabilities	3,489,470	3,496,925
Stockholders' equity	2,151,731	2,192,318
Total liabilities and equity	5,737,618	5,791,320
Revenues	1,041,771	919,985	898,202
Operating expenses	429,909	380,519	342,875
Income from operations	611,862	539,466	555,327
Net income	$ 371,786	$ 326,242	$ 331,617

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accrued Liabilities
Capital expenditures	$ 38,848	$ 57,361
Gathering, compression, processing, and transportation expenses	160,758	162,783
Marketing expenses	36,428	61,118
Interest expense, net	33,066	31,892
Production and ad valorem taxes	51,516	32,536
General and administrative expense	35,641	32,477
Derivative settlements payable	1,037	53,732
Other	24,046	29,889
Total accrued liabilities	$ 381,340	$ 461,788

Long-Term Debt (Details)

Long-Term Debt (Details) $ / shares in Units, $ in Thousands								12 Months Ended			24 Months Ended
	Jun. 01, 2021 USD ($)	May 13, 2021 USD ($) $ / shares shares	Jan. 26, 2021 USD ($)	Jan. 12, 2021 USD ($) $ / shares shares	Jan. 04, 2021 USD ($)	Sep. 02, 2020 USD ($)	Aug. 21, 2020 USD ($) D shares	Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($) shares	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($)	Nov. 02, 2021 USD ($)	Oct. 18, 2021 USD ($)	Jul. 01, 2021 USD ($)	Dec. 21, 2016 USD ($)	Mar. 17, 2015 USD ($)	Sep. 18, 2014 USD ($)	May 06, 2014 USD ($)
Long-Term Debt
Total principal								$ 1,547,571	$ 1,195,717		$ 1,547,571
Unamortized debt issuance costs								(9,975)	(12,241)		(9,975)
Long-term debt								1,537,596	1,183,476		1,537,596
Payments of deferred financing costs								605	814	$ 31,474
Aggregate principal amount converted								30,131	24,242
Loss on convertible note equitizations								374	169	50,777
Gain (loss) on extinguishment of debt repurchased									(46,027)	(93,191)
Debt Repurchase Program
Long-Term Debt
Gain (loss) on extinguishment of debt repurchased									46,000	31,000
Credit Facility
Long-Term Debt
Credit facility								417,200	34,800		417,200
Current borrowing base								3,500,000	3,500,000		3,500,000
Lender commitments								$ 1,600,000	1,500,000		1,600,000
Debt maturity threshold days								180 days
Available borrowing capacity								$ 692,000			692,000
Outstanding letters of credit								$ 501,000	$ 504,000		$ 501,000
Weighted average interest rate (as a percent)								7.71%	6.42%		7.71%
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%
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%
5.125 senior notes due 2022
Long-Term Debt
Senior notes																		$ 600,000
Total principal																	$ 500,000
Interest rate (as a percent)																		5.125%
Issue price as percentage of par value																	100.50%	100%
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																$ 750,000
Interest rate (as a percent)																5.625%
Issue price as percentage of par value																100%
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															$ 600,000
Interest rate (as a percent)															5%
Issue price as percentage of par value															100%
5.00% senior notes due 2025 | Debt Repurchase Program
Long-Term Debt
Redemption price										102%
Amount of debt repurchased									$ 585,000	$ 5,000
Percentage of redeemed amount									101.25%
8.375% Senior Notes Due 2026
Long-Term Debt
Senior notes					$ 500,000			$ 96,870	$ 96,870		$ 96,870
Interest rate (as a percent)					8.375%			8.375%	8.375%		8.375%
Issue price as percentage of par value					100%
Redemption price of the debt instrument in the event of change of control (as a percent)					101%
8.375% Senior Notes Due 2026 | Debt Repurchase Program
Long-Term Debt
Redemption amount														$ 175,000
Redemption price										108.375%
Amount of debt repurchased									$ 228,000	$ 175,000
Carrying value of debt repurchased									$ 228,000
Weighted average percentage premium on repurchases of debt									109%
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%
8.375% Senior Notes Due 2026 | Prior to January 15, 2024
Long-Term Debt
Redemption price					100%
7.625% Senior Notes Due 2029
Long-Term Debt
Senior notes			$ 700,000					$ 407,115	$ 407,115		$ 407,115
Interest rate (as a percent)			7.625%					7.625%	7.625%		7.625%
Redemption amount												$ 116,000	$ 116,000
Redemption price of the debt instrument in the event of change of control (as a percent)			101%
Amount of debt repurchased									$ 177,000
7.625% Senior Notes Due 2029 | Debt Repurchase Program
Long-Term Debt
Amount of debt repurchased									$ 177,000	$ 116,000
Weighted average percentage premium on repurchases of debt									106%
Percentage of redeemed amount										107.625%
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%
7.625% Senior Notes Due 2029 | On or before February 1, 2024
Long-Term Debt
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)			107.625%
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings			35%
7.625% Senior Notes Due 2029 | Prior to February 1, 2024
Long-Term Debt
Redemption price			100%
5.375% senior notes due 2030
Long-Term Debt
Senior notes	$ 600,000							$ 600,000	$ 600,000		$ 600,000
Interest rate (as a percent)	5.375%							5.375%	5.375%		5.375%
Redemption price of the debt instrument in the event of change of control (as a percent)	101%
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%
5.375% senior notes due 2030 | On or Before March 1, 2025
Long-Term Debt
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)	105.375%
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings	35%
5.375% senior notes due 2030 | Prior to March 1, 2025
Long-Term Debt
Redemption price	100%
4.25% convertible senior notes due 2026
Long-Term Debt
Amount of debt extinguished										$ 206,000
Convertible senior notes								$ 26,386	$ 56,932		$ 26,386
Total principal						$ 37,500	$ 250,000
Unamortized discount, net							$ 116,000
Unamortized debt issuance costs								(404)	(1,159)		(404)
Long-term debt								$ 25,982	$ 55,773		$ 25,982
Interest rate (as a percent)							4.25%	4.25%	4.25%		4.25%
Amount of debt converted											$ 55,000
Shares issued on conversion | shares							230.2026
Issuance of convertible notes						278,500
Payments of deferred financing costs						$ 9,000
If-converted value								$ 138,000			138,000
If-converted value above principal amount								112,000			$ 112,000
Aggregate principal amount converted								9,000	$ 20,000
Aggregate principal amount induced into conversion								$ 21,000	$ 5,000
Shares issued to cover conversions (in shares) | shares								7,000,000	6,000,000
Cash inducement premium								$ 400	$ 200
Effective interest rate (as a percent)							15.30%			15.30%
Interest expense								$ 2,000	$ 3,000	$ 11,000
4.25% convertible senior notes due 2026 | January Share Offering
Long-Term Debt
Amount of debt converted				$ 150,000
Shares issued on conversion | shares				275.3525
Number of shares of common stock issued (in shares) | shares				31,400,000
Share price | $ / shares				$ 6.35
Line of credit proceeds used to repurchase convertible notes				$ 63,000
Loss on convertible note equitizations										39,000
Gain (loss) on extinguishment of debt repurchased										41,000
4.25% convertible senior notes due 2026 | May Share Offering
Long-Term Debt
Carrying value of debt repurchased		$ 56,000
Shares issued on conversion | shares		245.2802
Number of shares of common stock issued (in shares) | shares		11,600,000
Share price | $ / shares		$ 11.01
Line of credit proceeds used to repurchase convertible notes		$ 26,000
Loss on convertible note equitizations										12,000
Gain (loss) on extinguishment of debt repurchased										$ 21,000
4.25% convertible senior notes due 2026 | Convertible debt threshold minimum percentage
Long-Term Debt
Stock price trigger							98%
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%
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, 2023	Dec. 31, 2022
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 59,485	$ 53,952
Obligations incurred	1,106	3,456
Accretion expense	3,244	4,906
Settlement of obligations	(718)	(1,050)
Obligations on sold properties		(42)
Revisions to prior estimates	(3,903)	(1,737)
Asset retirement obligations - end of period	$ 59,214	$ 59,485

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Thousands			12 Months Ended
	Jun. 15, 2020	Mar. 12, 2019	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jun. 17, 2020
Stock-based compensation expense
Equity based compensation expense recognized			$ 59,519	$ 35,443	$ 20,437
Fair value of equity awards			$ 75,000	158,000	34,000
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			7,059,518
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			$ 32,744	18,915	13,232
PSUs
Stock-based compensation expense
Equity based compensation expense recognized			25,322	14,920	4,662
Converted AM RSU Awards
Stock-based compensation expense
Equity based compensation expense recognized			1	209	1,160
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized			$ 1,452	$ 1,399	$ 1,383
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 - Res

Equity-Based Compensation - Restricted Stock and RSU Awards (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Number of shares
Total awarded and unvested at the beginning of the period (in shares)	4,676,219
Granted (in shares)	1,474,930
Vested (in shares)	(2,464,072)
Forfeited (in shares)	(166,027)
Total awarded and unvested at the end of the period (in shares)	3,521,050	4,676,219
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share)	$ 15.29
Granted (in dollars per share)	25.90	$ 35.64	$ 9.63
Vested (in dollars per share)	10.92
Forfeited (in dollars per share)	23.83
Total awarded and unvested at the end of the period (in dollars per share)	$ 22.40	$ 15.29
Unamortized equity-based compensation expense	$ 57
Weighted average period for recognizing unrecognized stock-based compensation expense	1 year 9 months 18 days

Equity-Based Compensation - PSU

Equity-Based Compensation - PSU awards (Details) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2024 $ / shares shares	Dec. 31, 2023 USD ($) item $ / shares shares	Dec. 31, 2022 item $ / shares shares	Dec. 31, 2021 item $ / shares	Dec. 31, 2020 item	Dec. 31, 2019	Dec. 31, 2018
PSUs
Stock-based compensation
Number of shares of common stock awards converted into | shares		400,000
Number of units
Total awarded and unvested at the beginning of the period (in shares) | shares	1,412,191	1,329,725
Granted (in shares) | shares		417,466
Vested (in shares) | shares		(335,000)
Total awarded and unvested at the end of the period (in shares) | shares		1,412,191	1,329,725
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 29.54	$ 23.18
Granted (in dollars per share) | $ / shares		28.51	$ 37.96	$ 9.71
Vested (in dollars per share) | $ / shares		2.97
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares		$ 29.54	$ 23.18
Additional disclosures
Unamortized equity-based compensation expense | $		$ 19
Weighted average period for recognizing unrecognized stock-based compensation expense		1 year 6 months
Weighted-average assumptions used to calculate fair value of performance share units granted
Dividend yield (as a percent)		0%
Volatility (as a percent)				85%
Volatility, minimum (as a percent)		82%	87%
Volatility, maximum (as a percent)			88%
Risk-free interest rate (as a percent)		4.61%		0.32%
Risk-free interest rate, minimum (as a percent)		4.61%	2.65%
Risk-free interest rate, maximum (as a percent)			4.49%
Weighted average fair value of awards granted-Absolute TSR | $ / shares		$ 33.96	$ 49.32	$ 11.99
PSU Awards Based on Absolute TSR
Stock-based compensation
Vesting percentage achieved		112%
2018 PSU Awards based on Absolute TSR
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%
Price target as a percentage of beginning price							125%
Amortization period of PSU expense							3 years
2018 PSU Awards based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent							0%
2018 PSU Awards based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent							200%
2019 PSU Awards Based on Absolute TSR
Stock-based compensation
Service period						3 years
Vesting percentage achieved			200%
Shares issued to cover conversions (in shares) | shares			2,000,000
Price target as a percentage of beginning price						125%
2019 PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent						0%
2019 PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent						200%
2020 PSU Awards Based on Absolute TSR
Stock-based compensation
Vesting percentage achieved		112%
Shares issued to cover conversions (in shares) | shares		200,000
Number of performance periods					3
Number of cumulative performance periods					1
Amortization period of PSU expense					3 years
2020 PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent					0%
2020 PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent					150%
2020 PSU Awards Based on Absolute TSR | One Year Period
Stock-based compensation
Service period					1 year
2020 PSU Awards Based on Absolute TSR | Three Year Period
Stock-based compensation
Service period					3 years
2021 PSU Awards Based on Absolute TSR
Stock-based compensation
Number of performance periods				3
Number of cumulative performance periods				1
2021 PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent				0%
2021 PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent				200%
2021 PSU Awards Based on Absolute TSR | Vesting before first anniversary
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent				200%
2021 PSU Awards Based on Absolute TSR | Vesting before the second anniversary
Stock-based compensation
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent				0%
2021 PSU Awards Based on Absolute TSR | One Year Period
Stock-based compensation
Service period				1 year
2021 PSU Awards Based on Absolute TSR | Three Year Period
Stock-based compensation
Service period				3 years
2022 PSU Awards Based on Absolute TSR
Stock-based compensation
Number of performance periods			3
Number of cumulative performance periods			1
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent			0%
2022 PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent			0%
2022 PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent			200%
2022 PSU Awards Based on Absolute TSR | One Year Period
Stock-based compensation
Service period			1 year
2022 PSU Awards Based on Absolute TSR | Three Year Period
Stock-based compensation
Service period			3 years
2022 PSU Awards Based on Absolute TSR Special
Stock-based compensation
Number of performance periods			3
Number of cumulative performance periods			1
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent			0%
2022 PSU Awards Based on Absolute TSR Special | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent			0%
2022 PSU Awards Based on Absolute TSR Special | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent			200%
2022 PSU Awards Based on Absolute TSR Special | One Year Period
Stock-based compensation
Service period			1 year
2022 PSU Awards Based on Absolute TSR Special | Three Year Period
Stock-based compensation
Service period			3 years
2023 PSU Awards Based on Absolute TSR
Stock-based compensation
Number of performance periods		3
Number of cumulative performance periods		1
2023 PSU Awards Based on Absolute TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent		0%
2023 PSU Awards Based on Absolute TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent		200%
2023 PSU Awards Based on Absolute TSR | One Year Period
Stock-based compensation
Service period		1 year
2023 PSU Awards Based on Absolute TSR | Three Year Period
Stock-based compensation
Service period		3 years
PSU Awards Based On Relative TSR
Stock-based compensation
Vesting percentage achieved		126%
Shares issued to cover conversions (in shares) | shares		200,000
Number of performance periods					3
Number of cumulative performance periods					1
Amortization period of PSU expense					3 years
PSU Awards Based On Relative TSR | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent					0%
PSU Awards Based On Relative TSR | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent					150%
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
2021 PSU Awards Based on Leverage Ratio
Stock-based compensation
Service period				1 year
Vesting percentage achieved				200%
Number of performance periods				3
2021 PSU Awards Based on Leverage Ratio | Forecast
Stock-based compensation
Shares issued to cover conversions (in shares) | shares	400,000
2021 PSU Awards Based on Leverage Ratio | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent				0%
2021 PSU Awards Based on Leverage Ratio | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent				200%
2022 PSU Awards Based on Leverage Ratio
Stock-based compensation
Service period			1 year
Vesting percentage achieved			200%
Number of performance periods			3
2022 PSU Awards Based on Leverage Ratio | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent			0%
2022 PSU Awards Based on Leverage Ratio | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent			200%
2022 PSU Awards Based on Leverage Ratio Special
Stock-based compensation
Service period			1 year
Vesting percentage achieved			200%
Number of performance periods			3
2022 PSU Awards Based on Leverage Ratio Special | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent			0%
2022 PSU Awards Based on Leverage Ratio Special | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent			200%
2023 PSU Awards Based on Leverage Ratio
Stock-based compensation
Service period		1 year
Vesting percentage achieved		200%
Number of performance periods		3
2023 PSU Awards Based on Leverage Ratio | Minimum
Stock-based compensation
Number of PSUs that may vest, as a percent		0%
2023 PSU Awards Based on Leverage Ratio | Maximum
Stock-based compensation
Number of PSUs that may vest, as a percent		200%

Equity-Based Compensation - Con

Equity-Based Compensation - Converted AM RSU Awards (Details) - Converted AM RSU Awards $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Number of units
Total awarded and unvested at the beginning of the period (in shares) | shares	2,827
Vested (in shares) | shares	(2,827)
Total awarded and unvested at the end of the period (in shares) | shares
Weighted average grant date fair value
Total awarded and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 12.38
Vested (in dollars per share) | $ / shares	$ 12.38
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares
Additional disclosures
Unamortized equity-based compensation expense | $	$ 0

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Options (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Stock options
Outstanding at the beginning of the period (in shares)	323,960
Options expired (in shares)	(65,264)
Outstanding at the end of the period (in shares)	258,696	323,960
Vested (in shares)	258,696
Exercisable (in shares)	258,696
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.86
Options expired (in dollars per share)	54.10
Outstanding at the end of the period (in dollars per share)	50.04	$ 50.86
Vested (in dollars per share)	50.04
Exercisable (in dollars per share)	$ 50.04
Weighted average remaining contractual life
Outstanding	1 year 3 months 18 days	2 years
Vested	1 year 3 months 18 days
Exercisable	1 year 3 months 18 days
Employee Stock Option [Member]
Additional disclosures
Dividend yield (as a percent)	0%
Employee Stock Option [Member] | Maximum
Stock-based compensation
Contractual life	10 years

Fair Value (Details)

Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair value | Level 2 market data
Financial Instruments
Value	$ 1,229,372	$ 1,474,146
Fair value | Level 2 market data | 8.375% Senior Notes Due 2026
Financial Instruments
Value	99,534	100,987
Fair value | Level 2 market data | 7.625% Senior Notes Due 2029
Financial Instruments
Value	417,781	410,860
Fair value | Level 2 market data | 5.375% senior notes due 2030
Financial Instruments
Value	573,720	556,260
Fair value | Level 2 market data | 4.25% convertible senior notes due 2026
Financial Instruments
Value	138,337	406,039
Carrying value
Financial Instruments
Value	1,120,396	1,148,676
Carrying value | 8.375% Senior Notes Due 2026
Financial Instruments
Value	96,351	96,123
Carrying value | 7.625% Senior Notes Due 2029
Financial Instruments
Value	403,441	402,872
Carrying value | 5.375% senior notes due 2030
Financial Instruments
Value	594,622	593,908
Carrying value | 4.25% convertible senior notes due 2026
Financial Instruments
Value	$ 25,982	$ 55,773

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) MMBTU / d bbl / d $ / MMBTU $ / bbl
Swaption Agreement
Derivative Instruments
Notional amount | MMBTU / d	427,500
Fixed price ($/MMBtu)	2.77
Cash payment for early settlement | $	$ 202
Swaps | Natural gas. | Henry Hub | January-December 2024 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	23,885
Weighted average index price	2.33
Swaps | Natural gas. | Henry Hub | January-March 2025 | VIE, Martica
Derivative Instruments
Notional amount | MMBTU / d	18,021
Weighted average index price	2.53
Swaps | Natural gas. | NYMEX to TCO | January-December 2024
Derivative Instruments
Notional amount | MMBTU / d	50,000
Weighted average hedged differential	0.530
Swaps | Oil | West Texas Intermediate | January-December 2024 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	43
Weighted average index price | $ / bbl	44.02
Swaps | Oil | West Texas Intermediate | January-March 2025 | VIE, Martica
Derivative Instruments
Notional amount | bbl / d	39
Weighted average index price | $ / bbl	45.06
Call option and embedded put option | Natural gas. | Henry Hub | January-December 2024
Derivative Instruments
Notional amount | MMBTU / d	53,000
Call option and embedded put option | Natural gas. | Henry Hub | January-December 2025
Derivative Instruments
Notional amount | MMBTU / d	44,000
Call option and embedded put option | Natural gas. | Henry Hub | January-December 2026
Derivative Instruments
Notional amount | MMBTU / d	32,000
Call option and embedded put option | Natural gas. | Put option | Henry Hub | January-December 2024
Derivative Instruments
Strike price	2.527
Call option and embedded put option | Natural gas. | Put option | Henry Hub | January-December 2025
Derivative Instruments
Strike price	2.614
Call option and embedded put option | Natural gas. | Put option | Henry Hub | January-December 2026
Derivative Instruments
Strike price	2.679
Call option and embedded put option | Natural gas. | Call Option | Henry Hub | January-December 2024
Derivative Instruments
Strike price	2.477
Call option and embedded put option | Natural gas. | Call Option | Henry Hub | January-December 2025
Derivative Instruments
Strike price	2.564
Call option and embedded put option | Natural gas. | Call Option | Henry Hub | January-December 2026
Derivative Instruments
Strike price	2.629

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 5,175	$ 1,900
Noncurrent portion of fair value of derivative assets	5,570	9,844
Current portion of fair value of derivative liabilities	15,236	97,765
Noncurrent portion of fair value of derivative liabilities	32,764	345,280
Derivatives not designated as hedges for accounting purposes
Fair value of derivative instruments
Total asset derivatives	10,745	11,744
Total liability derivatives	48,000	443,045
Net derivatives liability	(37,255)	(431,301)
Derivatives not designated as hedges for accounting purposes | Commodity derivatives
Fair value of derivative instruments
Current portion of fair value of derivative liabilities	15,236	97,765
Noncurrent portion of fair value of derivative liabilities	32,764	345,280
Derivatives not designated as hedges for accounting purposes | Commodity derivatives | VIE, Martica
Fair value of derivative instruments
Current portion of fair value of derivative liabilities	3,000	28,000
Noncurrent portion of fair value of derivative liabilities	2,000	19,000
Total liability derivatives	5,000	47,000
Derivatives not designated as hedges for accounting purposes | Embedded derivatives
Fair value of derivative instruments
Current portion of fair value of derivative assets	5,175	1,900
Noncurrent portion of fair value of derivative assets	$ 5,570	$ 9,844

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Commodity derivatives
Commodity derivative assets
Gross amounts on balance sheet	$ 406	$ 276
Gross amounts offset on balance sheet	(406)	(276)
Commodity derivative liabilities
Gross amounts on balance sheet	(48,406)	(443,321)
Gross amounts offset on balance sheet	406	276
Total liability derivatives	(48,000)	(443,045)
Embedded derivatives
Commodity derivative assets
Gross amounts on balance sheet	10,745	11,744
Total asset derivatives	$ 10,745	$ 11,744

Derivative Instruments - Fair_2

Derivative Instruments - Fair value gains (losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	$ 166,324	$ (1,615,836)	$ (1,936,509)
Commodity derivatives
Summary of realized and unrealized gains (losses) on derivative instruments
Payments for derivative monetizations	202,000	0	5,000
Commodity derivatives | Revenue.
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	165,448	(1,524,250)	(1,886,551)
Embedded derivatives | Revenue.
Summary of realized and unrealized gains (losses) on derivative instruments
Derivative fair value gains (losses)	$ 876	$ (91,586)	$ (49,958)

Leases (Details)

Leases (Details)	12 Months Ended
	Dec. 31, 2023
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, 2023	Dec. 31, 2022
Lease Assets
Operating leases right-of-use assets	$ 2,965,880	$ 3,444,331
Short-term operating lease obligation	$ 538,954	$ 556,137
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	$ 2,425,785	$ 2,888,194
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	$ 2,964,739	$ 3,444,331
Finance leases, right of use assets	3,771	2,159
Short-term finance lease obligation	$ 1,106	$ 499
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	$ 2,665	$ 1,660
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	$ 3,771	$ 2,159
Finance leases, accumulated amortization	$ 1,000
Vehicles
Lease Assets
Operating leases right-of-use assets		$ 756
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	$ 3,771	$ 2,159
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	$ 416	$ 3,476
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	$ 1,611,903	$ 1,849,116
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	$ 32,187	$ 85,405
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	$ 1,283,668	$ 1,463,756
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	$ 1,300,000	$ 1,400,000
Office space
Lease Assets
Operating leases right-of-use assets	$ 37,706	$ 41,822
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, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases
Total operating lease cost	$ 1,800,338	$ 1,628,427	$ 1,637,302
Total finance lease cost	2,127	544	874
Short-term lease payments	137,781	141,470	86,039
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	1,366,677	1,380,968	1,352,941
Operating cash flows from finance leases	597	193	352
Investing cash flows from operating leases	126,483	103,244	88,910
Financing cash flows from finance leases	830	575	859
Right-of-use assets obtained in exchange for new operating lease obligations	76,797	366,194	437,045
Increase (decrease) to existing right-of-use assets and lease obligations from operating lease modifications, net	$ (15,858)	$ 154,101	$ 702,512
Weighted average discount rate for remeasured operating leases (as a percent)	5.10%	5.10%	5.60%	14.40%
Weighted average discount rate for new operating leases (as a percent)	6.50%	5.20%	5%
Proved properties
Leases
Total operating lease cost	$ 160,638	$ 123,756	$ 103,741
Gathering, compression, water handling and treatment, processing, and transportation
Leases
Total operating lease cost	1,623,268	1,481,022	1,518,305
General and administrative.
Leases
Total operating lease cost	12,121	11,472	10,901
Contract termination
Leases
Total operating lease cost	4,227	12,000	4,213
Lease operating.
Leases
Total operating lease cost	84	177	142
Depletion, depreciation and amortization
Leases
Amortization of right-of-use assets	1,530	351	522
Interest expense
Leases
Interest on lease liabilities	$ 597	$ 193	$ 352

Leases - Maturities of Lease Li

Leases - Maturities of Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Future minimum payments for operating lease liabilities
2024	$ 699,335
2025	608,160
2026	555,915
2027	457,782
2028	379,922
Thereafter	872,055
Total lease payments	3,573,169
Less: imputed interest	(608,430)
Total operating lease obligation	2,964,739	$ 3,444,331
Future minimum payments for financing lease liabilities
2024	1,628
2025	1,585
2026	1,230
2027	197
2028	23
Thereafter	9
Total lease payments	4,672
Less: imputed interest	(901)
Total finance lease obligation	3,771	$ 2,159
Future minimum payments for total lease liabilities
2024	700,963
2025	609,745
2026	557,145
2027	457,979
2028	379,945
Thereafter	872,064
Total lease payments	3,577,841
Less: imputed interest	(609,331)
Total	$ 2,968,510

Leases - Lease Term and Discoun

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2023	Dec. 31, 2022
Leases
Weighted-average remaining lease term: Operating lease	6 years 6 months	7 years 2 months 12 days
Weighted-average discount rate: Operating lease	5.90%	5.30%
Weighted-average remaining lease term: Finance lease	3 years	3 years 6 months
Weighted-average discount rate: Finance lease	8.30%	7.40%

Leases - Related Party Lease Di

Leases - Related Party Lease Disclosure (Details) $ in Thousands		12 Months Ended
	Dec. 08, 2019	Dec. 31, 2023 USD ($) area	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
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%
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%
Term of lease	10 years
Notice period	180 days
Rebate received		$ 52,000	$ 48,000	$ 12,000
Gathering and compression fees paid		738,000	660,000	$ 705,000
Accounts payable		$ 65,000	59,000
Percentage of rate of return	13%
Term for rate of return on constructions	7 years
Antero Midstream Corporation | Marcellus
Leases
Minimum volume commitments that require Antero to utilize or pay certain percentage of the capacity of new construction of compressor stations (as a percent)	25%
Term of lease	10 years
Gathering and Compression Agreement | Utica
Leases
Compression Agreement Number Of Dedicated Areas | area		2
Affiliated Entity
Leases
Accounts payable		$ 86,284	$ 80,708

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income tax expense from continuing operations
Current income tax expense	$ 1,587	$ 847	$ 216
Deferred income tax expense (benefit)	74,407	447,845	(74,293)
Total income tax expense (benefit)	$ 75,994	$ 448,692	$ (74,077)
U.S. Statutory federal income tax rate (as a percent)	21%	21%	21%
Reconciliation of income tax expense (benefit) from the amount that would be computed by applying the U.S. statutory federal income tax rate to income or loss before taxes
Federal income tax expense (benefit)	$ 87,746	$ 519,679	$ (47,919)
State income tax expense (benefit), net of federal benefit	3,512	12,461	(6,576)
Change in state tax rate, net of federal effect	11,417	(52,747)	(30,910)
Equity-based compensation	(772)	(9,717)	1,117
Dividends received deduction	(3,186)	(1,749)	(3,832)
Noncontrolling interest	(21,525)	(27,347)	(7,862)
Change in valuation allowance	(2,567)	7,070	4,606
Nondeductible loss on 2026 Convertible Notes equitizations and inducement	81	36	12,174
Other	1,288	1,006	5,125
Total income tax expense (benefit)	75,994	448,692	$ (74,077)
Deferred income tax assets:
NOL carryforwards	281,217	282,829
Interest expense carryforwards	25,258
Equity-based compensation	7,056	3,362
Investment in Antero Midstream	234,423	254,164
Unrealized losses on derivative instruments	51,025	83,269
Lease liabilities	644,622	740,254
Asset retirement obligations and other	17,093	15,859
Total deferred income tax assets	1,260,694	1,379,737
Valuation allowance	(54,805)	(57,375)
Deferred income tax assets, net	1,205,889	1,322,362
Deferred income tax liabilities:
Oil and gas properties	1,338,442	1,295,847
Lease right-of-use assets	644,870	740,254
Investment in Martica	55,759	45,507
2026 Convertible Notes and other	1,086	615
Total deferred income tax liabilities	2,040,157	2,082,223
Deferred tax liability, net	$ (834,268)	$ (759,861)

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) $ in Millions	Dec. 31, 2023 USD ($)
Unrecognized tax benefits
Unrecognized tax benefits	$ 0
U.S. Federal
Income Taxes
Net operating loss carryforward	1,000
State
Income Taxes
Net operating loss carryforward	$ 1,900

Commitments (Details)

Commitments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) MMBTU / d	Dec. 31, 2022 USD ($)
Future minimum payments
2024	$ 1,948,319
2025	1,828,683
2026	1,737,868
2027	1,630,517
2028	1,495,014
Thereafter	5,332,557
Total	13,972,958
Firm transportation
Future minimum payments
2024	1,171,743
2025	1,158,209
2026	1,155,797
2027	1,151,152
2028	1,095,015
Thereafter	4,382,740
Total	$ 10,114,656
Commitments
Early termination of commitment per day (in MMBtu/d) | MMBTU / d	200,000
Cash payment for early termination	$ 24,000
Gas processing, gathering and compression
Future minimum payments
2024	67,201
2025	55,853
2026	22,676
2027	21,387
2028	20,054
Thereafter	77,753
Total	264,924
Commitments
Cash payment for cancellation of construction project		$ 12,000
Operating and Financing Leases
Future minimum payments
2024	540,101
2025	479,666
2026	455,118
2027	381,598
2028	324,786
Thereafter	787,241
Total	2,968,510
Imputed Interest for Leases
Future minimum payments
2024	160,862
2025	130,080
2026	102,027
2027	76,380
2028	55,159
Thereafter	84,823
Total	609,331
Other.
Future minimum payments
2024	8,412
2025	4,875
2026	2,250
Total	$ 15,537

Contingencies (Details)

Contingencies (Details) - WGL $ in Millions		1 Months Ended
	Jun. 20, 2019 USD ($)	Feb. 28, 2021 USD ($)	Jun. 30, 2019 lawsuit	Mar. 31, 2017 USD ($)
Settled Litigation
Contingencies
Damages awarded to the Company	$ 96
Settlement amount received		$ 107
Pending Litigation
Contingencies
Number of cases | lawsuit			2
Pending Litigation | Minimum
Contingencies
Damages sought by other party				$ 40

Reportable Segments (Details)

Reportable Segments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) segment	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Operating results and assets of reportable segments
Number of reportable segments | segment	3
Sales and revenues:
Sales and revenues - Third-party	$ 4,680,091	$ 7,136,970	$ 4,618,407
Sales and revenues - Intersegment	1,881	1,466	1,025
Revenues	4,681,972	7,138,436	4,619,432
Operating expenses:
Lease operating	118,441	99,595	96,793
General and administrative	224,516	172,909	145,006
Depletion, depreciation and amortization	689,966	680,600	742,009
Impairment of property and equipment	51,302	149,731	90,523
Other	502,259	856,316	1,022,067
Total operating expenses	4,228,842	4,564,531	4,595,572
Operating income (loss)	453,130	2,573,905	23,860
Equity in earnings of unconsolidated affiliate	82,952	72,327	77,085
Capital expenditures for segment assets	1,131,863	943,971	715,936
Investments in unconsolidated affiliates	222,255	220,429
Total assets	13,619,414	14,118,039
Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	2,642,358	2,605,380	2,499,174
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues - Third-party	4,473,969	6,720,212	3,899,486
Sales and revenues - Intersegment	1,881	1,466	1,025
Revenues	4,475,850	6,721,678	3,900,511
Operating expenses:
Lease operating	118,441	99,595	96,793
General and administrative	224,516	172,909	145,006
Depletion, depreciation and amortization	689,966	680,600	742,009
Impairment of property and equipment	51,302	149,731	90,523
Other	193,531	325,012	210,369
Total operating expenses	3,920,114	4,033,227	3,783,874
Operating income (loss)	555,736	2,688,451	116,637
Equity in earnings of unconsolidated affiliate	82,952	72,327	77,085
Capital expenditures for segment assets	1,131,863	943,971	715,936
Investments in unconsolidated affiliates	222,255	220,429
Total assets	13,602,297	14,081,077
Operating segments | Exploration and production | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	2,642,358	2,605,380	2,499,174
Operating segments | Marketing
Sales and revenues:
Sales and revenues - Third-party	206,122	416,758	718,921
Revenues	206,122	416,758	718,921
Operating expenses:
Other	308,728	531,304	811,698
Total operating expenses	308,728	531,304	811,698
Operating income (loss)	(102,606)	(114,546)	(92,777)
Total assets	17,117	36,962
Operating segments | Antero Midstream Corporation
Sales and revenues:
Sales and revenues - Third-party	1,414	2,622	516
Sales and revenues - Intersegment	1,040,357	917,363	897,686
Revenues	1,041,771	919,985	898,202
Operating expenses:
General and administrative	71,068	62,125	63,838
Depletion, depreciation and amortization	136,059	131,762	108,790
Impairment of property and equipment	146	3,702	5,042
Other	9,471	2,676	8,085
Total operating expenses	429,909	380,519	342,875
Operating income (loss)	611,862	539,466	555,327
Equity in earnings of unconsolidated affiliate	105,456	94,218	90,451
Capital expenditures for segment assets	183,733	298,924	232,825
Investments in unconsolidated affiliates	626,650	652,767
Total assets	5,737,618	5,791,320
Operating segments | Antero Midstream Corporation | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	213,165	180,254	157,120
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues - Third-party	(1,414)	(2,622)	(516)
Sales and revenues - Intersegment	(1,040,357)	(917,363)	(897,686)
Revenues	(1,041,771)	(919,985)	(898,202)
Operating expenses:
General and administrative	(71,068)	(62,125)	(63,838)
Depletion, depreciation and amortization	(136,059)	(131,762)	(108,790)
Impairment of property and equipment	(146)	(3,702)	(5,042)
Other	(9,471)	(2,676)	(8,085)
Total operating expenses	(429,909)	(380,519)	(342,875)
Operating income (loss)	(611,862)	(539,466)	(555,327)
Equity in earnings of unconsolidated affiliate	(105,456)	(94,218)	(90,451)
Capital expenditures for segment assets	(183,733)	(298,924)	(232,825)
Investments in unconsolidated affiliates	(626,650)	(652,767)
Total assets	(5,737,618)	(5,791,320)
Elimination of intersegment transaction | Gathering, compression, water handling and treatment, processing, and transportation
Operating expenses:
Cost of goods and services sold	$ (213,165)	$ (180,254)	$ (157,120)

Subsidiary Guarantors - Balance

Subsidiary Guarantors - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Other current assets	$ 14,192	$ 31,872
Total current assets	475,692	787,525
Total assets	13,619,414	14,118,039
Liabilities and Stockholders' Equity
Other current liabilities	1,295	1,707
Total current liabilities	1,452,091	1,774,909
Total liabilities	6,405,312	7,100,885
Parent (Antero) And Guarantor Subsidiaries
Current assets:
Other current assets	453,581	739,104
Noncurrent assets	12,562,439	12,663,911
Total assets	13,016,020	13,403,015
Liabilities and Stockholders' Equity
Other current liabilities	1,360,102	1,668,426
Total current liabilities	1,446,386	1,749,134
Noncurrent liabilities	4,951,464	5,306,539
Total liabilities	6,397,850	7,055,673
Affiliated Entity
Liabilities and Stockholders' Equity
Accounts payable	86,284	80,708
Affiliated Entity | Parent (Antero) And Guarantor Subsidiaries
Liabilities and Stockholders' Equity
Accounts payable	$ 86,284	$ 80,708

Subsidiary Guarantors - Stateme

Subsidiary Guarantors - Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Operations
Revenues	$ 4,483,200	$ 8,711,507	$ 6,509,680
Operating expenses	4,228,842	4,564,531	4,595,572
Income from operations	453,130	2,573,905	23,860
Net income and comprehensive income including noncontrolling interests	341,844	2,025,972	(154,109)
Net income and comprehensive income attributable to Antero Resources Corporation	242,919	$ 1,898,771	$ (186,899)
Parent (Antero) And Guarantor Subsidiaries
Statement of Operations
Revenues	4,539,184
Operating expenses	4,184,979
Income from operations	354,205
Net income and comprehensive income including noncontrolling interests	242,919
Net income and comprehensive income attributable to Antero Resources Corporation	$ 242,919

Supplemental Information on O_3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 13,908,804	$ 13,234,777
Unproved properties	974,642	997,715
Total oil and gas properties	14,883,446	14,232,492
Accumulated depletion	(4,996,691)	(4,624,674)
Net capitalized costs	9,886,755	9,607,818
Costs Incurred in Certain Oil and Gas Activities
Unproved property	151,135	149,009	$ 79,138
Development costs	956,267	775,106	581,352
Exploration costs	8,079	5,543	19,822
Total costs incurred	1,115,481	929,658	680,312
Results of Operations for Oil and Gas Producing Activities
Revenues	4,276,445	8,294,749	5,790,759
Operating expenses:
Production expenses	2,919,654	2,992,381	2,793,877
Exploration expenses	2,691	3,651	1,164
Depletion	682,109	737,504	735,687
Impairment of unproved properties	51,302	98,324	90,523
Results of operations before income tax expense	620,689	4,462,889	2,169,508
Income tax expense	(135,063)	(959,477)	(520,168)
Results of operations	$ 485,626	$ 3,503,412	$ 1,649,340

Supplemental Information on O_4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details)	12 Months Ended
	Dec. 31, 2023 Bcfe Bcf MMBbls MMcf	Dec. 31, 2022 Bcfe MMBbls Bcf MMcf	Dec. 31, 2021 Bcfe Bcf MMBbls
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcfe	17,759	17,729	17,635
Revisions | Bcfe	1,187	596	1,486
Extensions, discoveries and other additions | Bcfe	413	604	472
Production | Bcfe	(1,238)	(1,170)	(1,194)
Sales | Bcfe			(670)
Balance at the end of the period | Bcfe	18,121	17,759	17,729
Oil and Gas Reserves
Proved developed reserves | Bcfe	13,783	13,373	12,753
Proved undeveloped reserves | Bcfe	4,338	4,386	4,976
VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf		167
Balance at the end of the period | Bcf			167
Balance at the beginning of the period | Bcfe	92
Balance at the end of the period | Bcfe	75	92
Oil and Gas Reserves
Proved developed reserves | Bcfe	75	91	133
Proved undeveloped reserves | Bcfe	0		34
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	10,270	10,204	10,025
Revisions | Bcf	863	427	993
Extensions, discoveries and other additions | Bcf	296	437	349
Production | Bcf	(815)	(798)	(826)
Sales | Bcf			(337)
Balance at the end of the period | Bcf	10,614	10,270	10,204
Oil and Gas Reserves
Proved developed reserves | Bcf	7,912	7,699	7,395
Proved undeveloped reserves | Bcf	2,702	2,571	2,809
Natural gas | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	71	101
Balance at the end of the period | Bcf	58	71	101
Oil and Gas Reserves
Proved undeveloped reserves | Bcfe		1
Proved developed reserves | Bcf	58	70	78
Proved undeveloped reserves | Bcf			23
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	1,217	1,219	1,236
Revisions	54	32	77
Extensions, discoveries and other additions	18	25	18
Production	(67)	(59)	(58)
Sales			(54)
Balance at the end of the period	1,222	1,217	1,219
Oil and Gas Reserves
Proved developed reserves	963	930	876
Proved undeveloped reserves	259	287	343
NGLS | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period	3	11
Balance at the end of the period	3	3	11
Oil and Gas Reserves
Proved developed reserves	3	3	9
Proved undeveloped reserves			2
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	31	36	33
Revisions		(4)	6
Extensions, discoveries and other additions	2	2	2
Production	(4)	(3)	(4)
Sales			(1)
Balance at the end of the period	29	31	36
Oil and Gas Reserves
Proved developed reserves	15	16	17
Proved undeveloped reserves	14	15	19
Oil and condensate | VIE, Martica
Proved developed and undeveloped reserves:
Balance at the beginning of the period	0.2	0.4
Balance at the end of the period	0.1	0.2	0.4
Oil and Gas Reserves
Proved developed reserves	0.1	0.2	0.2
Proved undeveloped reserves			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, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Extensions, discoveries and other additions	413	604	472
Revisions	1,187	596	1,486
Time period of the development plan	5 years	5 years	5 years
Increase in proved reserves due to additions to development plan	698	692	1,475
Decrease in proved reserves due to reclassifications related to five-year rule	(244)	(600)	824
Increase in proved reserve due to improved well performance			565
Increase (decrease) in proved reserves previous estimates	814
Increase (decrease) in proved reserves resulting from changes in ownership interests	846	414
Increase (decrease) in proved reserves resulting from changes in reserve forecast and operation cost estimates	(32)
Increase (decrease) in proved reserves resulting from price revisions	(81)	2	149
Increase Decrease In Proved Reserve Due To Ethane Recovery		88	121
Increase (decrease) in proved undeveloped properties reclassified from non-proved to proved undeveloped	454	92	651
Sales of reserves			670

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, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and gas reserves
Future cash inflows computation period	12 months
Discount rate for annual net cash inflows (as a percent)	10%	10%	10%
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	$ 58,061	$ 109,052	$ 74,622
Future production costs	(41,887)	(39,378)	(34,665)
Future development costs	(2,027)	(2,073)	(1,704)
Future net cash flows before income tax	14,147	67,601	38,253
Future income tax expense	(2,178)	(13,692)	(7,813)
Future net cash flows	11,969	53,909	30,440
10% annual discount for estimated timing of cash flows	(6,874)	(30,345)	(17,007)
Standardized measure of discounted future net cash flows	5,095	23,564	13,433	$ 1,210
VIE, Martica
Annual net cash inflows
Standardized measure of discounted future net cash flows	$ 170	$ 458	$ 501

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, 2023 USD ($) $ / Mcfe	Dec. 31, 2022 USD ($) $ / Mcfe	Dec. 31, 2021 USD ($) $ / Mcfe
Oil and gas reserves
12-month weighted average price (in dollars per Mcfe | $ / Mcfe	3.20	6.14	4.21
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs	$ (1,357)	$ (5,302)	$ (2,917)
Net changes in prices and production costs	(25,672)	13,793	14,099
Development costs incurred during the period	637	448	454
Net changes in future development costs	(96)	(289)	(117)
Extensions, discoveries and other additions	69	1,068	504
Divestitures			(125)
Revisions of previous quantity estimates	190	1,475	2,543
Accretion of discount	2,947	1,655	121
Net change in income taxes	5,069	(2,787)	(3,115)
Changes in timing and other	(256)	70	776
Net increase (decrease)	(18,469)	10,131	12,223
Beginning of year	23,564	13,433	1,210
End of year	5,095	23,564	13,433
Future income tax expense included in Standardized Measure	2,200	13,700	7,800
VIE, Martica
Changes in Standardized Measure of Discounted Future Net Cash Flow
Beginning of year	458	501
End of year	$ 170	$ 458	$ 501

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false