Antero Resources (AR) 10-K 13 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 08, 2019	Jun. 29, 2018
Document and Entity Information
Entity Registrant Name	ANTERO RESOURCES Corp
Entity Central Index Key	1,433,270
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 4.1
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		308,651,020
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,018

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents		$ 28,441
Accounts receivable, net of allowance for doubtful accounts of $1,320 and $-0- at December 31, 2017 and 2018, respectively	$ 51,073	34,896
Accrued revenue	474,827	300,122
Derivative instruments	245,263	460,685
Other current assets	35,450	8,943
Total current assets	806,613	833,087
Natural gas properties, at cost (successful efforts method):
Unproved properties	1,767,600	2,266,673
Proved properties	12,705,672	11,096,462
Water handling and treatment systems	1,013,818	946,670
Gathering systems and facilities	2,470,708	2,050,490
Other property and equipment	65,842	57,429
Property and equipment, gross	18,023,640	16,417,724
Less accumulated depletion, depreciation, and amortization	(4,153,725)	(3,182,171)
Property and equipment, net	13,869,915	13,235,553
Derivative instruments	362,169	841,257
Investments in unconsolidated affiliates	433,642	303,302
Other assets	47,125	48,291
Total assets	15,519,464	15,261,490
Current liabilities:
Accounts payable	66,289	62,982
Accrued liabilities	465,070	443,225
Revenue distributions payable	310,827	209,617
Derivative instruments	532	28,476
Other current liabilities	10,822	17,796
Total current liabilities	853,540	762,096
Long-term liabilities:
Long-term debt	5,461,688	4,800,090
Deferred income tax liability	650,788	779,645
Derivative instruments		207
Other liabilities	65,971	43,316
Total liabilities	7,031,987	6,385,354
Commitments and contingencies (notes 13 and 14)
Equity:
Common stock, $0.01 par value; authorized - 1,000,000 shares; 316,379 shares and 308,594 shares issued and outstanding at December 31, 2017 and 2018, respectively	3,086	3,164
Additional paid-in capital	6,485,174	6,570,952
Accumulated earnings	1,177,548	1,575,065
Total stockholders' equity	7,665,808	8,149,181
Noncontrolling interest in consolidated subsidiary	821,669	726,955
Total equity	8,487,477	8,876,136
Total liabilities and equity	$ 15,519,464	$ 15,261,490

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Condensed Consolidated Balance Sheets
Allowance for doubtful accounts	$ 0	$ 1,320
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized shares	1,000,000,000	1,000,000,000
Common stock, shares issued	308,594,000	316,379,000
Common stock, shares outstanding	308,594,000	316,379,000
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, authorized shares	50,000,000	50,000,000
Preferred stock, shares issued	0	0

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue:
Revenues from contracts with customers									$ 4,133,139	$ 3,018,685	$ 2,161,071
Marketing derivative fair value gains (losses)									94,081	(21,394)
Commodity derivative fair value gains (losses)									(87,594)	658,283	(514,181)
Gain on sale of assets											97,635
Total revenue and other	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	4,139,626	3,655,574	1,744,525
Operating expenses:
Production and ad valorem taxes									126,474	94,521	66,588
Impairment of unproved properties									549,437	159,598	162,935
Impairment of gathering systems and facilities									9,658	23,431	0
Depletion, depreciation, and amortization									972,465	824,610	809,873
Accretion of asset retirement obligations									2,819	2,610	2,473
General and administrative									240,344	251,196	239,324
Total operating expenses	1,092,279	1,071,728	1,022,107	881,607	834,667	719,932	666,646	694,236	4,067,721	2,915,481	2,720,326
Operating income (loss)	(46,630)	4,804	(32,763)	146,494	187,059	(72,052)	123,743	501,343	71,905	740,093	(975,801)
Other income (expenses):
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Interest									(286,743)	(268,701)	(253,552)
Loss on early extinguishment of debt										(1,500)	(16,956)
Total other expenses									(246,463)	(250,007)	(270,023)
Income (loss) before income taxes									(174,558)	490,086	(1,245,824)
Provision for income tax benefit									128,857	295,051	496,376
Net income (loss) and comprehensive income (loss) including noncontrolling interest	18,736	(77,972)	(67,275)	80,810	529,614	(90,000)	39,965	305,558	(45,701)	785,137	(749,448)
Net income and comprehensive income attributable to noncontrolling interest	140,282	76,447	69,110	65,977	42,745	45,063	45,097	37,162	351,816	170,067	99,368
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	$ (397,517)	$ 615,070	$ (848,816)
Earnings (loss) per common share:
Earnings (loss) per common share - basic (in dollars per share)	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.26)	$ 1.95	$ (2.88)
Earnings (loss) per common share assuming dilution:
Earnings (loss) per common share—assuming dilution (in dollars per share)	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.26)	$ 1.94	$ (2.88)
Weighted average number of shares outstanding
Basic (in shares)									316,036	315,426	294,945
Diluted (in shares)									316,036	316,283	294,945
Natural gas sales
Revenue:
Revenues from contracts with customers									$ 2,287,939	$ 1,769,284	$ 1,260,750
Natural gas liquids sales
Revenue:
Revenues from contracts with customers									1,177,777	870,441	432,992
Oil sales
Revenue:
Revenues from contracts with customers									187,178	108,195	61,319
Gathering, compression, water handling and treatment
Revenue:
Revenues from contracts with customers									21,344	12,720	12,961
Operating expenses:
Cost of goods and services sold									1,339,358	1,095,639	882,838
Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									136,153	89,057	50,090
Marketing
Revenue:
Revenues from contracts with customers									458,901	258,045	393,049
Operating expenses:
Cost of goods and services sold									686,055	366,281	499,343
Exploration
Operating expenses:
Cost of goods and services sold									$ 4,958	$ 8,538	$ 6,862

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Equity-based compensation expense	$ 70,414	$ 103,445	$ 102,421

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional paid-in capital	Accumulated earnings	Noncontrolling Interests	Total
Balance at Dec. 31, 2015	$ 2,770	$ 4,122,811	$ 1,808,811	$ 1,352,286	$ 7,286,678
Balance (in shares) at Dec. 31, 2015	277,036
Increase (Decrease) in Stockholders' Equity
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs	$ 365	1,012,066			1,012,431
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs (in shares)	36,493
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	$ 14	(21,274)			(21,260)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares)	1,348
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		106,659		6,419	113,078
Issuance of common units by subsidiary - Antero Midstream Partners LP				65,395	65,395
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings		(15,190)		9,555	(5,635)
Equity-based compensation		94,409		8,012	102,421
Net income (loss) and comprehensive income (loss) including noncontrolling interest			(848,816)	99,368	(749,448)
Distributions to non-controlling interests				(75,082)	(75,082)
Balance at Dec. 31, 2016	$ 3,149	5,299,481	959,995	1,465,953	7,728,578
Balance (in shares) at Dec. 31, 2016	314,877
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	$ 15	(18,244)			(18,229)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares)	1,502
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		206,486		(19,940)	186,546
Issuance of common units by subsidiary - Antero Midstream Partners LP				248,956	248,956
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings		(15,636)		9,691	(5,945)
Equity-based compensation		93,669		9,776	103,445
Net income (loss) and comprehensive income (loss) including noncontrolling interest			615,070	170,067	785,137
Effects of changes in ownership interests in consolidated subsidiaries		1,005,196		(1,005,196)
Distributions to non-controlling interests				(152,352)	(152,352)
Balance at Dec. 31, 2017	$ 3,164	6,570,952	1,575,065	726,955	8,876,136
Balance (in shares) at Dec. 31, 2017	316,379
Increase (Decrease) in Stockholders' Equity
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	$ 13	(11,504)			(11,491)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares)	1,360
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings		(16,536)		11,007	(5,529)
Repurchases and retirements of common stock	$ (91)	(128,993)			(129,084)
Repurchases and retirements of common stock (in shares)	(9,145)
Equity-based compensation		62,618		7,796	70,414
Net income (loss) and comprehensive income (loss) including noncontrolling interest			(397,517)	351,816	(45,701)
Effects of changes in ownership interests in consolidated subsidiaries		8,637		(8,637)
Distributions to non-controlling interests				(267,271)	(267,271)
Other				3	3
Balance at Dec. 31, 2018	$ 3,086	$ 6,485,174	$ 1,177,548	$ 821,669	$ 8,487,477
Balance (in shares) at Dec. 31, 2018	308,594

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests	$ (45,701)	$ 785,137	$ (749,448)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	975,284	827,220	812,346
Impairment of unproved properties	549,437	159,598	162,935
Impairment of gathering systems and facilities	9,658	23,431	0
Commodity derivative fair value (gains) losses	87,594	(658,283)	514,181
Gains on settled commodity derivatives	243,112	213,940	1,003,083
Premium paid on derivative contracts	(13,318)
Proceeds from derivative monetizations	370,365	749,906
Marketing derivative fair value (gains) losses	(94,081)	21,394
Gains on settled marketing derivatives	72,687
Deferred income tax expense	(128,857)	(295,126)	(485,392)
Gain on sale of assets			(97,635)
Equity-based compensation expense	70,414	103,445	102,421
Loss on early extinguishment of debt		1,500	16,956
Equity in earnings of unconsolidated affiliates	(40,280)	(20,194)	(485)
Distributions from unconsolidated affiliates	46,415	20,195	7,702
Other	4,681	(1,907)	(12,488)
Changes in current assets and liabilities:
Accounts receivable	(15,156)	(5,214)	39,857
Accrued revenue	(174,706)	(38,162)	(133,718)
Other current assets	(5,817)	(2,755)	1,774
Accounts payable	9,307	9,462	7,365
Accrued liabilities	63,562	64,862	18,853
Revenue distributions payable	101,210	45,628	34,040
Other current liabilities	(3,823)	2,214	(1,091)
Net cash provided by operating activities	2,081,987	2,006,291	1,241,256
Cash flows used in investing activities:
Additions to proved properties		(175,650)	(134,113)
Additions to unproved properties	(172,387)	(204,272)	(611,631)
Drilling and completion costs	(1,488,573)	(1,281,985)	(1,327,759)
Additions to water handling and treatment systems	(97,699)	(194,502)	(188,188)
Additions to gathering systems and facilities	(444,413)	(346,217)	(231,044)
Additions to other property and equipment	(7,514)	(14,127)	(2,694)
Investments in unconsolidated affiliates	(136,475)	(235,004)	(75,516)
Change in other assets	(3,663)	(12,029)	3,977
Proceeds from asset sales		2,156	171,830
Net cash used in investing activities	(2,350,724)	(2,461,630)	(2,395,138)
Cash flows provided by (used in) financing activities:
Issuance of common stock			1,012,431
Issuance of common units by Antero Midstream		248,956	65,395
Proceeds From Sale Of Interest In Partnership Unit		311,100	178,000
Repurchases of common stock	(129,084)
Issuance of senior notes			1,250,000
Repayment of senior notes			(525,000)
Borrowings (repayments) on bank credit facilities, net	660,379	90,000	(677,000)
Make-whole premium on debt extinguished			(15,750)
Payments of deferred financing costs	(2,169)	(16,377)	(18,759)
Distributions to noncontrolling interest in consolidated subsidiary	(267,271)	(152,352)	(75,082)
Employee tax withholding for settlement of equity compensation awards	(17,020)	(24,174)	(26,895)
Other	(4,539)	(4,983)	(5,321)
Net cash provided by financing activities	240,296	452,170	1,162,019
Net increase (decrease) in cash and cash equivalents	(28,441)	(3,169)	8,137
Cash and cash equivalents, beginning of period	28,441	31,610	23,473
Cash and cash equivalents, end of period		28,441	31,610
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	275,769	263,919	239,369
Supplemental disclosure of noncash investing activities:
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$ (47,717)	$ (547)	$ (152,093)

Organization

Organization	12 Months Ended
	Dec. 31, 2018
Organization
Organization	(1) Organization Antero Resources Corporation (individually referred to as “Antero” or the “Parent”) and its consolidated subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, and acquisition of natural gas, NGLs, and oil properties in the Appalachian Basin in West Virginia and Ohio. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. Through its consolidated subsidiary, Antero Midstream Partners LP, a publicly-traded limited partnership (“Antero Midstream”), the Company has gathering and compression, as well as water handling and treatment, operations in the Appalachian Basin. The Company’s corporate headquarters are located in Denver, Colorado.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	(2) Summary of Significant Accounting Policies (a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2017 and 2018, and the results of its operations and its cash flows for the years ended December 31, 2016, 2017, and 2018. 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. As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified. (b) Principles of Consolidation The accompanying consolidated financial statements include the accounts of Antero, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. For the years ended December 31, 2016, 2017 and 2018, we have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are consolidated in the Company’s consolidated financial statements. Antero is the primary beneficiary of Antero Midstream based on its power to direct the activities that most significantly impact Antero Midstream’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Antero Midstream that could be significant to Antero Midstream. In reaching the determination that Antero is the primary beneficiary of Antero Midstream, the Company considered the following: · Antero Midstream was formed to own, operate, and develop midstream energy assets to service Antero’s production and completion activities under long-term service contracts. · Antero owned 52.8% of the outstanding limited partner interests in Antero Midstream at December 31, 2018. · Antero’s officers and management group also act as management of Antero Midstream and AMGP under services and secondment agreements between the respective parties. · Substantially all of Antero Midstream’s revenues are derived from services provided to Antero. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. Noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream which are owned by the public and the incentive distribution rights in Antero Midstream. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under the nature of the distribution 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 which affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates. The Company’s consolidated financial statements are based on a number of significant estimates including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s consolidated financial statements which involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies. (d) Risks and Uncertainties The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities. (e) Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short‑term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable 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, 2018, the book overdraft included within accounts payable and revenue distributions payable was $10 million and $28 million, respectively. (f) Oil and Gas Properties The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells‑in‑progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred no such charges during the years ended December 31, 2016, 2017, and 2018. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units‑of‑production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property‑by‑property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired, or are expected to expire, was $163 million, $160 million, and $549 million for the years ended December 31, 2016, 2017, and 2018, respectively. The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties at the end of each quarter, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties during the years ended December 31, 2016, 2017 and 2018. At December 31, 2018, the Company did not have capitalized costs related to exploratory wells‑in‑progress which have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units‑of‑production method. Depletion expense for oil and gas properties was $700 million, $694 million, and $832 million for the years ended December 31, 2016, 2017, and 2018, respectively. (g) Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that is not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred. Gathering pipelines and compressor stations are depreciated using the straight‑line method over their estimated useful lives of 50 years. Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of 5 to 20 years. Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was $101 million, $120 million, and $131 million for the years ended December 31, 2016, 2017, and 2018, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment. (h) Impairment of Long‑Lived Assets Other than Oil and Gas Properties The Company evaluates its long‑lived assets other than natural 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. There were no impairments for such assets during the year ended December 31, 2016. Impairment of gathering systems and facilities of $23 million and $10 million during the years ended December 31, 2017 and 2018, respectively, relates to gathering facilities no longer or not expected to be utilized. (i) Other Property and Equipment Other property and equipment assets are depreciated using the straight‑line method over their estimated useful lives, which range from 2 to 20 years. Depreciation expense for other property and equipment was $9 million, $10 million, and $9 million for the years ended December 31, 2016, 2017, and 2018, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment. (j) Deferred Financing Costs Deferred financing costs represent loan origination fees and other initial borrowing costs. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2018, the Company had $19 million of unamortized deferred financing costs included in other long‑term assets, and $35 million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write‑off of previously deferred debt issuance costs were $16 million, $13 million, and $13 million for the years ended December 31, 2016, 2017, and 2018, respectively. (k) Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions. The Company records derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes. (l) Asset Retirement Obligations The Company is obligated to dispose of certain long‑lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives, as well as Antero Midstream’s future closure and postclosure costs associated with the landfill, fresh water impoundments and waste water pits at its wastewater treatment facility. 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. Antero Midstream is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines and facilities and wastewater treatment facility upon abandonment. Antero Midstream’s gathering pipelines, compressor stations, fresh water delivery pipelines and facilities and wastewater treatment facility have an indeterminate life, if properly maintained. Accordingly, Antero Midstream is not able to make a reasonable estimate of when future dismantlement and removal dates of its pipelines, compressor stations and facilities will occur. (m) Environmental Liabilities Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2017 and 2018, the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows. (n) Natural Gas, NGLs, and Oil Revenues On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. The Company elected the modified retrospective transition method when new standard became effective for the Company on January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on the Company’s financial results. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the month that the sale occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a revenue distribution payable to the extent it receives more than its proportionate share of production revenues. At December 31, 2017 and 2018, the Company had no production imbalance positions. Under our natural gas sales contracts, we deliver natural gas to purchasers at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses. NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to further process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor. Under our oil sales contracts, we generally sell oil to the purchaser and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to the purchaser. (o) Marketing Revenues and Expenses Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense. (p)  Gathering, compression, water handling and treatment revenue Substantially all revenues from our gathering, compression, water handling and treatment operations are derived from intersegment transactions for services Antero Midstream provides to our exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream or usage of Antero Midstream’s gathering and compression systems. For gathering and compression revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line. Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility. For services contracted through third party providers, Antero Midstream’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream in accordance with the water services agreement. (q) Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry. The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables. The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2016, 2017, and 2018 are as follows: 2016 2017 2018 Company A 1 % — % 16 % Company B 29 22 14 Company C 13 15 7 All others 57 63 63 100 % 100 % 100 % The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due could have a material adverse effect on the Company’s financial condition and results of operations. The Company has economic hedges in place with sixteen different counterparties. The fair value of the Company’s commodity derivative contracts of approximately $607 million (excluding short-term commodity derivatives related to our marketing activities) at December 31, 2018 includes the following values by bank counterparty: Morgan Stanley - $115 million; JP Morgan - $102 million; Scotiabank - $97 million; Citigroup - $91 million; Wells Fargo - $80 million; Canadian Imperial Bank of Commerce - $51 million; BNP Paribas - $24 million; Bank of Montreal - $14 million; Toronto Dominion - $8 million; PNC - $8 million; SunTrust - $7 million; Natixis - $7 million; and Capital One - $3 million. The estimated fair value of commodity derivative assets has been risk-adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2018 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts. (r) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense. (s) Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long‑lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over‑the‑counter commodity price swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. (t) Industry Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing and utilization of excess firm transportation capacity. 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 resell the Company’s production to third parties located in foreign countries. (u) Earnings (loss) Per Common Share Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive. 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, 2016 2017 2018 Basic weighted average number of shares outstanding 294,945 315,426 316,036 Add: Dilutive effect of restricted stock units — 817 — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — 40 — Diluted weighted average number of shares outstanding 294,945 316,283 316,036 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1) : Restricted stock units 6,740 1,521 2,844 Outstanding stock options 702 676 626 Performance stock units 659 1,054 1,705 (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive. (v)  Treasury Share Retirement The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares issued, to the balance of add

Antero Midstream Partners LP

Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2018
Antero Midstream Partners LP
Antero Midstream Partners LP	(3) In 2014, the Company formed Antero Midstream to own, operate, and develop midstream energy assets that service Antero’s production. Antero Midstream’s assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to Antero under long-term, fixed-fee contracts. AMGP indirectly owns the general partnership interest in Antero Midstream and directly owns capital interests in IDR LLC, which owns the incentive distribution rights in Antero Midstream. Antero Midstream is an unrestricted subsidiary as defined by Antero’s senior secured revolving bank credit facility (the “Credit Facility”). As an unrestricted subsidiary, Antero Midstream and its subsidiaries are not guarantors of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see Note 17). On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced wastewater treatment facility under construction in Doddridge County, West Virginia, to Antero Treatment LLC (“Antero Treatment”), a subsidiary of Antero Midstream (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). In consideration for the Contributed Assets, Antero Midstream (i) paid to Antero a cash distribution equal to $552 million, less $171 million of assumed debt, (ii) issued to Antero 10,988,421 common units representing limited partner interests in Antero Midstream, (iii) distributed to Antero proceeds of approximately $241 million from a private placement of Antero Midstream common units, and (iv) has agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2018, Antero Midstream has delivered 128 million of the 176 million barrels and we expect to receive the entire amount of the contingent consideration for the 176 million barrels or more fresh water delivered during the period between January 1, 2017 and December 31, 2019, but Antero Midstream has delivered 71 million of the 219 million barrels and we do not expect Antero Midstream to deliver 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”) pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. Antero Midstream is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2018, Antero Midstream did not sell any common units under the Distribution Agreement. During the year ended December 31, 2017, Antero Midstream issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $26 million after deducting commissions and other offering costs. As of December 31, 2018, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157 million. On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P. (see Note 5). In conjunction with the formation of the Joint Venture, on February 10, 2017, Antero Midstream issued 6,900,000 common units, including common units issued pursuant to the underwriters’ option to purchase additional common units, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under its credit facility, and for general partnership purposes. On March 30, 2016, Antero sold 8,000,000 of its Antero Midstream common units for $178 million. On September 11, 2017, Antero sold 10,000,000 of its Antero Midstream common units for $311 million. These sales of units are reflected in stockholders’ equity as additional paid-in capital, net of taxes. Antero Midstream also owns a 15% equity interest in the gathering system of Stonewall Gas Gathering LLC (“Stonewall”) which operates a 67-mile pipeline on which Antero is an anchor shipper. Antero owned approximately 52.9% and 52.8% of the limited partner interests of Antero Midstream at December 31, 2017 and December 31, 2018, respectively.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2018
Revenue
Revenue	(4) (a) Disaggregation of Revenue In the following table, revenue is disaggregated by type (in thousands). The table also identifies the reportable segment to which the disaggregated revenues relate. For more information on reportable segments, see Note 16—Segment Information. Year Ended December 31, Segment to which 2016 2017 2018 revenues relate Revenues from contracts with customers: Natural gas sales $ 1,260,750 1,769,284 2,287,939 Exploration and production Natural gas liquids sales (ethane) 52,949 93,041 172,653 Exploration and production Natural gas liquids sales (C3+ NGLs) 380,043 777,400 1,005,124 Exploration and production Oil sales 61,319 108,195 187,178 Exploration and production Gathering and compression 12,169 11,386 17,817 Gathering and processing Water handling and treatment 792 1,334 3,527 Water handling and treatment Marketing 393,049 258,045 458,901 Marketing Total 2,161,071 3,018,685 4,133,139 Income from derivatives and other sources (416,546) 636,889 6,487 Total revenue and other $ 1,744,525 3,655,574 4,139,626 (b) Transaction Price Allocated to Remaining Performance Obligations For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. (c) Contract Balances Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2017 and 2018, our receivables from contracts with customers were $300 million and $475 million, respectively.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2018
Equity Method Investments
Equity Method Investments	(3) In 2014, the Company formed Antero Midstream to own, operate, and develop midstream energy assets that service Antero’s production. Antero Midstream’s assets consist of gathering systems and compression facilities, water handling and treatment facilities, and interests in processing and fractionation plants, through which it provides services to Antero under long-term, fixed-fee contracts. AMGP indirectly owns the general partnership interest in Antero Midstream and directly owns capital interests in IDR LLC, which owns the incentive distribution rights in Antero Midstream. Antero Midstream is an unrestricted subsidiary as defined by Antero’s senior secured revolving bank credit facility (the “Credit Facility”). As an unrestricted subsidiary, Antero Midstream and its subsidiaries are not guarantors of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see Note 17). On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced wastewater treatment facility under construction in Doddridge County, West Virginia, to Antero Treatment LLC (“Antero Treatment”), a subsidiary of Antero Midstream (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). In consideration for the Contributed Assets, Antero Midstream (i) paid to Antero a cash distribution equal to $552 million, less $171 million of assumed debt, (ii) issued to Antero 10,988,421 common units representing limited partner interests in Antero Midstream, (iii) distributed to Antero proceeds of approximately $241 million from a private placement of Antero Midstream common units, and (iv) has agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2018, Antero Midstream has delivered 128 million of the 176 million barrels and we expect to receive the entire amount of the contingent consideration for the 176 million barrels or more fresh water delivered during the period between January 1, 2017 and December 31, 2019, but Antero Midstream has delivered 71 million of the 219 million barrels and we do not expect Antero Midstream to deliver 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. Antero Midstream has an Equity Distribution Agreement (the “Distribution Agreement”) pursuant to which Antero Midstream may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between Antero Midstream and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. Antero Midstream is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2018, Antero Midstream did not sell any common units under the Distribution Agreement. During the year ended December 31, 2017, Antero Midstream issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $26 million after deducting commissions and other offering costs. As of December 31, 2018, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157 million. On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P. (see Note 5). In conjunction with the formation of the Joint Venture, on February 10, 2017, Antero Midstream issued 6,900,000 common units, including common units issued pursuant to the underwriters’ option to purchase additional common units, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial contribution to the Joint Venture, repay outstanding borrowings under its credit facility, and for general partnership purposes. On March 30, 2016, Antero sold 8,000,000 of its Antero Midstream common units for $178 million. On September 11, 2017, Antero sold 10,000,000 of its Antero Midstream common units for $311 million. These sales of units are reflected in stockholders’ equity as additional paid-in capital, net of taxes. Antero Midstream also owns a 15% equity interest in the gathering system of Stonewall Gas Gathering LLC (“Stonewall”) which operates a 67-mile pipeline on which Antero is an anchor shipper. Antero owned approximately 52.9% and 52.8% of the limited partner interests of Antero Midstream at December 31, 2017 and December 31, 2018, respectively.
Antero Midstream Partners LP
Equity Method Investments
Equity Method Investments	(5) Equity Method Investments In 2016, Antero Midstream acquired a 15% equity interest in Stonewall Gas Gathering LLC (“Stonewall”), which operates a regional gathering pipeline on which Antero is an anchor shipper. On February 6, 2017, Antero Midstream formed the Joint Venture to develop gas processing and fractionation assets in Appalachia with MarkWest, a wholly owned subsidiary of MPLX. Antero Midstream and MarkWest each own a 50% equity interest in the Joint Venture and MarkWest operates the Joint Venture assets, which consist of processing plants in West Virginia, and a one-third interest in a MarkWest fractionator in Ohio. The Company’s consolidated statements of operations and comprehensive income (loss) include Antero Midstream’s proportionate share of the net income of equity method investees. When Antero Midstream records its proportionate share of net income, it increases equity income in the consolidated statements of operations and comprehensive income (loss) and the carrying value of that investment on the Company’s consolidated balance sheet. When a distribution is received, it is recorded as a reduction to the carrying value of that investment on the consolidated balance sheet. The Company uses the equity method of accounting to account for its investments in Stonewall and the Joint Venture because Antero Midstream exercises significant influence, but not control, over the entities. The Company’s judgment regarding the level of influence over its equity investments includes considering key factors such as Antero Midstream’s ownership interest, representation on the board of directors, and participation in the policy-making decisions of Stonewall and the Joint Venture. The following table is a reconciliation of investments in unconsolidated affiliates for the years ending December 31, 2017 and 2018 in thousands): Stonewall (2) MarkWest Total Balance at December 31, 2016 $ 68,299 — 68,299 Investments (1) — 235,004 235,004 Equity in net income of unconsolidated affiliates 10,304 9,890 20,194 Distributions from unconsolidated affiliates (11,475) (8,720) (20,195) Balance at December 31, 2017 67,128 236,174 303,302 Investments (1) — 136,475 136,475 Equity in net income of unconsolidated affiliates 10,740 29,540 40,280 Distributions from unconsolidated affiliates (9,765) (36,650) (46,415) Balance at December 31, 2018 $ 68,103 365,539 433,642 (1) Investments in the Joint Venture relate to capital contributions for construction of additional processing facilities. (2) Distributions are net of operating and capital requirements retained by Stonewall.

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities
Accrued Liabilities	(6) Accrued Liabilities Accrued liabilities as of December 31, 2017 and 2018 consisted of the following items (in thousands): December 31, 2017 December 31, 2018 Capital expenditures $ 155,300 113,237 Gathering, compression, processing, and transportation expenses 88,850 148,032 Marketing expenses 59,049 67,082 Interest expense 40,861 43,444 Other 99,165 93,275 $ 443,225 465,070

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Long-Term Debt.
Long-Term Debt	(7) Long‑Term Debt Long‑term debt was as follows at December 31, 2017 and 2018 (in thousands): December 31, 2017 December 31, 2018 Antero Resources: Credit Facility (a) $ 185,000 405,000 5.375% senior notes due 2021 (b) 1,000,000 1,000,000 5.125% senior notes due 2022 (c) 1,100,000 1,100,000 5.625% senior notes due 2023 (d) 750,000 750,000 5.00% senior notes due 2025 (e) 600,000 600,000 Net unamortized premium 1,520 1,241 Net unamortized debt issuance costs (32,430) (26,700) Antero Midstream: Midstream Credit Facility (g) 555,000 990,000 5.375% senior notes due 2024 (h) 650,000 650,000 Net unamortized debt issuance costs (9,000) (7,853) $ 4,800,090 5,461,688 Antero Resources Corporation (a) Senior Secured Revolving Credit Facility Antero has a senior secured revolving credit facility (the “Credit Facility”) with a consortium of bank lenders. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero’s assets and are subject to regular annual redeterminations. At December 31, 2018, the borrowing base under the Credit Facility was $4.5 billion and lender commitments were $2.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2019. The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of Antero’s senior notes, unless such series of notes is refinanced. Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at least one of (i) a BBB- or better rating from Standard and Poor’s and (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”). An Investment Grade Period can end at Antero’s election. During any period that is not an Investment Grade Period, the Credit Facility is ratably secured by mortgages on substantially all of Antero’s properties and guarantees from Antero’s restricted subsidiaries, as applicable. During an Investment Grade Period, the liens securing the obligations under the Credit Facility shall be automatically released (subject to the provisions of the Credit Facility). The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. During any period that is not an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero’s election at the time of borrowing, plus an applicable rate based on Antero’s borrowing base utilization which ranges from 25 basis points to 225 basis points. During an Investment Grade Period, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero’s election at the time of borrowing, plus an applicable rate based on Antero’s credit rating which ranges from 12.5 basis points to 175 basis points. Antero was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2017 and 2018. As of December 31, 2018, Antero had an outstanding balance under the Credit Facility of $405 million with a weighted average interest rate of 3.95%, and outstanding letters of credit of $685 million. As of December 31, 2017, Antero had an outstanding balance under the Credit Facility of $185 million, with a weighted average interest rate of 2.96%, and outstanding letters of credit of $705 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from (i) 0.300% to 0.375% (during any period that is not an Investment Grade Period) of the unused portion based on utilization and (ii) 0.150% to 0.300% (during an Investment Grade Period) of the unused portion based on Antero’s credit rating. (b) 5.375% Senior Notes Due 2021 On November 5, 2013, Antero issued $1 billion of 5.375% senior notes due November 1, 2021 (the “2021 notes”) at par. The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 notes rank pari passu to Antero’s other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. Antero may redeem all or part of the 2021 notes at any time at redemption prices ranging from 101.344% currently to 100.00% on or after November 1, 2019. If Antero undergoes a change of control, the holders of the 2021 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued and unpaid interest. (c) 5.125% Senior Notes Due 2022 On May 6, 2014, Antero issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 notes”) at par. On September 18, 2014, Antero issued an additional $500 million of the 2022 notes at 100.5% of par. The 2022 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2022 notes rank pari passu to Antero’s other outstanding senior notes. The 2022 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2022 notes at any time at redemption prices ranging from 102.563% currently to 100.00% on or after June 1, 2020. If Antero undergoes a change of control, the holders of the 2022 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued and unpaid interest. (d) 5.625% Senior Notes Due 2023 On March 17, 2015, Antero issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 notes”) at par. The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2023 notes rank pari passu to Antero’s other outstanding senior notes. The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2023 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2023 notes at any time at redemption prices ranging from 104.219% to 100.00% on or after June 1, 2021. If Antero undergoes a change of control, the holders of the 2023 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2023 notes, plus accrued and unpaid interest. (e) 5.00% Senior Notes Due 2025 On December 21, 2016, Antero issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 notes”) at par. The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2025 notes rank pari passu to Antero’s other outstanding senior notes. The 2025 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2025 notes is payable on March 1 and September 1 of each year. Antero may redeem all or part of the 2025 notes at any time on or after March 1, 2020 at redemption prices ranging from 103.750% on or after March 1, 2020 to 100.00% on or after March 1, 2023. In addition, on or before March 1, 2020, Antero may redeem up to 35% of the aggregate principal amount of the 2025 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.00% of the principal amount of the 2025 notes, plus accrued and unpaid interest. At any time prior to March 1, 2020, Antero may also redeem the 2025 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero undergoes a change of control, the holders of the 2025 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2025 notes, plus accrued and unpaid interest. (f) Treasury Management Facility Antero has a stand‑alone revolving note with a lender that is part of the Credit Facility lending consortium which provides for up to $25 million of cash management obligations in order to facilitate Antero’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the revolving note bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2019. At December 31, 2017, there were no outstanding borrowings under this facility and $5.4 million at December 31, 2018 included in “Other current liabilities” on the Company’s Consolidated Balance Sheet. Antero Midstream Partners LP (g) Senior Secured Revolving Credit Facility – Antero Midstream Antero Midstream has a senior secured revolving credit facility (the “Midstream Credit Facility”) with a consortium of bank lenders. At December 31, 2018, lender commitments under the Midstream Credit Facility were $2.0 billion. The maturity date of the Midstream Credit Facility is October 26, 2022. During any period that is not an Investment Grade Period (as such term is defined in the Midstream Credit Facility), the Midstream Credit Facility is ratably secured by mortgages on substantially all of the properties of Antero Midstream and guarantees from its restricted subsidiaries, as applicable. During an Investment Grade Period under the Midstream Credit Facility, the liens securing the Midstream Credit Facility are automatically released (subject to the provisions of the Midstream Credit Facility). The Midstream Credit Facility contains certain covenants, including restrictions on indebtedness and certain distributions to owners, and requirements with respect to leverage and interest coverage ratios. During any period that is not an Investment Grade Period under the Midstream Credit Facility, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Midstream’s election at the time of borrowing, plus an applicable rate based on Antero Midstream’s borrowing base utilization which ranges from 25 basis points to 225 basis points. During an Investment Grade Period under the Midstream Credit Facility, interest is payable at a variable rate based on LIBOR or the prime rate determined by Antero Midstream’s election at the time of borrowing, plus an applicable rate based on Antero Midstream’s credit rating which ranges from 12.5 basis points to 200 basis points. Antero Midstream was in compliance with all of the financial covenants under the Midstream Credit Facility as of December 31, 2017 and 2018. As of December 31, 2018, Antero Midstream had an outstanding balance under the Midstream Credit Facility of $990 million with a weighted average interest rate of 3.75%, and no letters of credit outstanding. As of December 31, 2017, Antero Midstream had an outstanding balance under the Midstream Credit Facility of $555 million with a weighted average interest rate of 2.81%. Commitment fees on the unused portion of the Midstream Credit Facility are due quarterly at rates ranging from (i) 0.25% to 0.375% of the unused portion (during an period that is not an Investment Grade Period) based on the leverage ratio and (ii) 0.175% to 0.375% of the unused portion (during an Investment Grade Period) based on Antero Midstream’s credit rating. (h) 5.375% Senior Notes Due 2024 – Antero Midstream On September 13, 2016, Antero Midstream and its wholly-owned subsidiary, Antero Midstream Finance Corporation (“Midstream Finance Corp.”) as co-issuers, issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Midstream notes”) at par. The 2024 Midstream notes are unsecured and effectively subordinated to the Midstream Credit Facility to the extent of the value of the collateral securing the Midstream Credit Facility. The 2024 Midstream notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Midstream’s wholly-owned subsidiaries, excluding Midstream Finance Corp., and certain of Antero Midstream’s future restricted subsidiaries. Interest on the 2024 Midstream notes is payable on March 15 and September 15 of each year. Antero Midstream may redeem all or part of the 2024 Midstream notes at any time on or after September 15, 2019 at redemption prices ranging from 104.031% on or after September 15, 2019 to 100.00% on or after September 15, 2022. In addition, prior to September 15, 2019, Antero Midstream may redeem up to 35% of the aggregate principal amount of the 2024 Midstream notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest. At any time prior to September 15, 2019, Antero Midstream may also redeem the 2024 Midstream notes, in whole or in part, at a price equal to 100% of the principal amount of the 2024 Midstream notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream undergoes a change of control, the holders of the 2024 Midstream notes will have the right to require Antero Midstream to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations
Asset Retirement Obligations	(8) Asset Retirement Obligations The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2017 and 2018 (in thousands): 2017 2018 Asset retirement obligations—beginning of year $ 32,736 34,610 Obligations settled (22) — Obligations incurred 4,044 9,981 Revisions to prior estimates (4,758) 11,569 Accretion expense 2,610 2,819 Asset retirement obligations—end of year $ 34,610 58,979 Revisions to prior estimates in 2018 are primarily due to an increase in estimated abandonment costs for vertical wells. Revisions to prior estimates in 2017 are primarily due to an increase in the estimated economic lives of our wells as a result of increases in commodity prices in 2017 and improved well performance. 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, 2018
Equity-Based Compensation
Equity-Based Compensation	(9) Equity‑Based Compensation Antero is authorized to grant up to 16,906,500 shares of common stock to employees and directors of the Company under the Antero Resources Corporation Long‑Term Incentive Plan (the “Plan”). The Plan allows equity‑based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero’s Board of Directors. A total of 8,351,638 shares were available for future grant under the Plan as of December 31, 2018. Antero Midstream’s general partner is authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream under the Antero Midstream Partners LP Long-Term Incentive Plan (the “Midstream Plan”) to non-employee directors of its general partner and certain officers, employees, and consultants of Antero Midstream and its affiliates (which include Antero). A total of 7,932,261 common units were available for future grant under the Midstream Plan as of December 31, 2018. The Company’s equity‑based compensation expense, by type of award, was as follows for the years ended December 31, 2016, 2017, and 2018 (in thousands): Year Ended December 31, 2016 2017 2018 Restricted stock unit awards $ 73,081 70,866 41,505 Stock options 2,578 2,375 1,799 Performance share unit awards 8,685 10,797 9,659 Antero Midstream phantom unit awards 16,095 17,461 15,351 Equity awards issued to directors 1,982 1,946 2,100 Total expense $ 102,421 103,445 70,414 Restricted Stock Unit Awards Restricted stock unit awards vest subject to the satisfaction of service requirements. Expense related to each restricted stock unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. A summary of restricted stock unit award activity for the year ended December 31, 2018 is as follows: Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2017 3,424,084 $ 28.51 $ 65,058 Granted 687,626 $ 20.69 Vested (1,933,130) $ 29.90 Forfeited (466,095) $ 25.65 Total awarded and unvested—December 31, 2018 1,712,485 $ 24.57 $ 16,080 Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. As of December 31, 2018, there was $27 million of unamortized equity-based compensation expense related to unvested restricted stock units. That expense is expected to be recognized over a weighted average period of approximately 2.3 years. Stock Options Stock options granted under the Plan have a maximum contractual life of 10 years. Expense related to stock options is recognized on a straight‑line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Stock options were granted with an exercise price equal to or greater than the market price of the Company’s common stock on the dates of grant. A summary of stock option activity for the year ended December 31, 2018 is as follows: Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2017 660,512 $ 50.48 7.06 $ — Granted — $ — Exercised — $ — Forfeited (80,895) $ 50.00 Expired — $ — Outstanding at December 31, 2018 579,617 $ 50.55 5.81 $ — Vested or expected to vest as of December 31, 2018 579,617 $ 50.55 5.81 $ — Exercisable at December 31, 2018 462,217 $ 50.69 5.69 $ — Intrinsic values are based on the exercise price of the options and the closing price of the Company’s 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 the Company’s common stock had traded for a relatively short period of time at the dates the options were granted. The risk‑free interest rate was determined using the implied yield available for zero‑coupon U.S. government issues with a remaining term approximating the expected life of the options. A dividend yield of zero was assumed. No stock options were granted during the years ended December 31, 2016, 2017 and 2018. As of December 31, 2018, there was $0.5 million of unamortized equity‑based compensation expense related to unvested stock options. That expense is expected to be recognized over a weighted average period of approximately 0.3 years. Performance Share Unit Awards Performance Share Unit Awards Based on Price Targets In 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers that are based on price targets. The vesting of these PSUs is conditioned on the closing price of the Company’s common stock achieving specific price thresholds over 10-day periods, subject to the following vesting restrictions: no PSUs may vest before the first anniversary of the grant date; no more than one-third of the PSUs may vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs may vest before the third anniversary of the grant date. Any PSUs which have not vested by the fifth anniversary of the grant date will expire. Expense related to these PSUs is recognized on a graded basis over three years. Performance Share Unit Awards Based on Total Shareholder Return (“TSR”) In 2016 and 2017, the Company granted PSUs to certain of its employees and executive officers that vest based on the TSR of the Company’s common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of common shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years. Performance Share Unit Awards Based on TSR and Return on Capital Employed (“ROCE”) In 2018, the Company granted PSUs to certain of its employees and executive officers, a portion of which vest based on the Company’s common stock reaching a target price per share equal to 125% of the beginning price (as defined in the award agreement) at the end of a three-year performance period (“TSR PSUs”). The number of awards actually earned with respect to the TSR PSUs will be subject to further adjustment based on the TSR of the Company’s common stock relative to the TSR of a peer group of companies over the same period. The number of shares of common stock that may ultimately be earned with respect to the TSR PSUs ranges from zero to 200% of the target number of TSR PSUs originally granted. Expense related to the TSR PSUs is recognized on a straight-line basis over three years. The other portion of the PSUs granted in 2018 vest based on the Company’s actual ROCE (as defined in the award agreement) over a three-year period as compared to a targeted ROCE (“ROCE PSUs”). The number of shares of common stock that may ultimately be earned with respect to the ROCE PSUs ranges from zero to 200% of the target number of ROCE PSUs originally granted. Expense related to the ROCE PSUs is recognized based on the number of shares of common stock that are expected to be issued at the end of the measurement period, and is reversed if the likelihood of achieving the performance condition decreases. Summary Information for Performance Share Unit Awards A summary of PSU activity for the year ended December 31, 2018 is as follows: Number of Weighted Total awarded and unvested—December 31, 2017 1,283,843 $ 28.29 Granted 756,466 $ 23.61 Vested (41,666) $ 27.38 Forfeited (231,344) $ 27.89 Total awarded and unvested—December 31, 2018 1,767,299 $ 26.36 The grant-date fair values of market-based PSUs were determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair values of the awards. Expected volatilities were derived from the volatility of the historical stock prices of a peer group of similar publicly-traded companies. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs. A dividend yield of zero was assumed. The grant-date fair value for the ROCE-based PSUs is based on the closing price of the Company’s common stock on the date of the grant, assuming the achievement of the performance condition. The following table presents information regarding the weighted average fair values for market-based PSUs granted during the years ended December 31, 2017 and 2018, and the assumptions used to determine the fair values: Year Ended December 31, 2017 2018 Dividend yield — % — % Volatility 42 % 41 % Risk-free interest rate 1.40 % 2.49 % Weighted average fair value of awards granted $ 26.21 $ 24.85 As of December 31, 2018, there was $20 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 1.9 years. Antero Midstream Partners Phantom Unit Awards Phantom units granted by Antero Midstream vest subject to the satisfaction of service requirements, upon the completion of which common units in Antero Midstream are delivered to the holder of the phantom units. Phantom units also contain distribution equivalent rights which entitle the holder of vested common units to receive a “catch up” payment equal to common unit distributions paid by Antero Midstream during the vesting period of the phantom unit award. These phantom units are treated, for accounting purposes, as if Antero Midstream distributed the units to Antero. Antero recognizes compensation expense as the units are granted to its employees, and a portion of the expense is allocated to Antero Midstream. Expense related to each phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero Midstream’s common units on the date of grant. A summary of phantom unit awards activity for the year ended December 31, 2018 is as follows: Number of Weighted Aggregate Total awarded and unvested—December 31, 2017 1,042,963 $ 28.69 $ 30,288 Granted 260,847 $ 25.84 Vested (577,566) $ 28.63 Forfeited (143,244) $ 28.08 Total awarded and unvested—December 31, 2018 583,000 $ 27.63 $ 12,470 Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. As of December 31, 2018, there was $12 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately 2.5 years.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2018
Financial Instruments
Financial Instruments	(10) Financial Instruments The carrying values of accounts receivable and accounts payable at December 31, 2017 and 2018 approximated market values because of their short‑term nature. The carrying values of the amounts outstanding under the Credit Facility and Midstream Credit Facility at December 31, 2017 and 2018 approximated fair value because the variable interest rates are reflective of current market conditions. Based on Level 2 market data inputs, the fair value of the Antero’s senior notes was approximately $3.5 billion and $3.3 billion at December 31, 2017 and 2018. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $670 million at December 31, 2017 and $608 million at December 31, 2018. See Note 11 for information regarding the fair value of derivative financial instruments.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments.
Derivative Instruments	(11) Derivative Instruments (a)  Commodity Derivative Positions The Company periodically enters into natural gas, NGLs, and oil derivative contracts with counterparties to hedge the price risk associated with its production. These derivatives are not entered into for trading purposes. To the extent that changes occur in the market prices of natural gas, NGLs, and oil, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas, NGLs, and oil recognized upon the ultimate sale of the Company’s production. The Company was party to various fixed price commodity swap contracts that settled during the years ended December 31, 2016, 2017, and 2018. The Company enters into these swap contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices upon settlement exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices upon settlement are less than the contractually provided fixed price, the Company receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price. The Company has also entered into natural gas collar contracts, which establish ceiling and floor prices for the sale of notional volumes of natural gas as specified in the collar contracts. Under these contracts, the Company pays the difference between the ceiling price and the published index price in the event the published index price is above the ceiling price. When the published index price is below the floor price, the Company receives the difference between the floor price and the published index price. No amounts are paid or received if the index price is between the floor and the ceiling prices. The index prices in our collars are consistent with the index prices used to sell our production. The Company’s derivative contracts have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in the Company’s statements of operations. As of December 31, 2018, the Company’s fixed price natural gas positions from January 1, 2019 through December 31, 2023 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: NYMEX=Henry Hub): Natural gas Weighted Three months ending March 31, 2019: NYMEX ($/MMBtu) 2,330,000 $ 3.62 Three months ending June 30, 2019: NYMEX ($/MMBtu) 755,000 $ 3.26 Three months ending September 30, 2019: NYMEX ($/MMBtu) 755,000 $ 3.32 Three months ending December 31, 2019: NYMEX ($/MMBtu) 755,000 $ 3.45 Year ending December 31, 2020: NYMEX ($/MMBtu) 1,417,500 $ 3.00 Year ending December 31, 2021: NYMEX ($/MMBtu) 710,000 $ 3.00 Year ending December 31, 2022: NYMEX ($/MMBtu) 850,000 $ 3.00 Year ending December 31, 2023: NYMEX ($/MMBtu) 90,000 $ 2.91 As of December 31, 2018, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of Chicago City Gate to the NYMEX Henry Hub natural gas price, totaled 225,000 MMbtu/day for January 2019 with pricing differentials ranging from $0.215 to $0.40. As of December 31, 2018, the Company’s fixed price natural gas collar positions from April 1, 2019 through December 31, 2019 were as follows (abbreviations in the table refer to the index to which the collar position is tied, as follows: NYMEX=Henry Hub. Natural gas Weighted average index price MMbtu/day Ceiling price Floor price Three months ending June 30, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.30 $ 2.50 Three months ending September 30, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.30 $ 2.50 Three months ending December 31, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.52 $ 2.50 An initial premium of $13 million was paid at the inception of natural gas collar contracts with one counterparty, and is recorded as a derivative asset measured at fair value. (b) Marketing Derivatives In 2017, due to delay of the in-service date for a pipeline on which the Company is to be an anchor shipper, the Company realized it would not be able to fulfill its delivery obligations under a 2018 natural gas sales contract. In order to acquire gas to fulfill its delivery obligations, the Company entered into several natural gas purchase agreements with index-based pricing to purchase gas for resale under this sales contract. Subsequently, the Company and the counterparty to the sales contract came to an agreement that the Company’s delivery obligations under the contract would not begin until the earlier of (1) the in-service date of the pipeline and (2) January 1, 2019. Consequently, in December 2017, the Company entered into natural gas sales agreements with index-based pricing to resell the purchased gas for delivery during the period from February to October 2018. The natural gas that it had purchased for January was sold on the spot market during January. As a result of severe cold weather in the local area in January resulting in wide basis premiums at the index for these contracts, the Company realized a cash gain on these contracts of $73 million during the year ended December 31, 2018. The Company determined that these gas purchase and sales agreements should be accounted for as derivatives and measured at fair value at the end of each period. The Company recognized a loss in the fourth quarter of 2017 of $21 million. For the year ended December 31, 2018, the Company recognized a fair value gain of $94 million and realized proceeds of $73 million. (c)  Summary The following table presents a summary of the fair values of the Company’s derivative instruments and where such values are recorded in the consolidated balance sheets as of December 31, 2017 and 2018. None of the Company’s derivative instruments are designated as hedges for accounting purposes. December 31, 2017 December 31, 2018 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity derivatives - current Derivative instruments $ 460,685 Derivative instruments $ 245,263 Commodity derivatives - noncurrent Derivative instruments 841,257 Derivative instruments 362,169 Total asset derivatives 1,301,942 607,432 Liability derivatives not designated as hedges for accounting purposes: Marketing derivatives - current Derivative instruments 21,394 Derivative instruments — Commodity derivatives - current Derivative instruments 7,082 Derivative instruments 532 Commodity derivatives - noncurrent Derivative instruments 207 Derivative instruments — Total liability derivatives 28,683 532 Net derivatives $ 1,273,259 $ 606,900 The following table presents the gross values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value (in thousands): December 31, 2017 December 31, 2018 Gross Gross amounts Net amounts of assets (liabilities) on balance sheet Gross Gross amounts Net amounts Commodity derivative assets $ 1,367,554 (65,612) 1,301,942 $ 658,830 (51,398) 607,432 Commodity derivative liabilities $ (72,901) 65,612 (7,289) $ (51,930) 51,398 (532) Marketing derivative assets $ 311,083 (311,083) — $ — — — Marketing derivative liabilities $ (332,477) 311,083 (21,394) $ — — — The following is a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2016, 2017, and 2018 (in thousands): Statement of Year ended December 31, location 2016 2017 2018 Commodity derivative fair value gains (losses) Revenue $ (514,181) 658,283 (87,594) Marketing derivative fair value gains (losses) Revenue $ — (21,394) 94,081 Commodity derivative fair value gains (losses) for the years ended December 31, 2017 and 2018, include gains of $750 million and $370 million, respectively, related to certain natural gas derivatives that were monetized prior to their contractual settlement dates. Proceeds received from the monetizations are classified as operating cash flows on the Company’s consolidated statement of cash flows for the year ended December 31, 2017 and 2018. The 2017 monetizations were effected by reducing the average fixed index prices on certain natural gas swap contracts maturing from 2018 through 2022 while maintaining the total volumes hedged. The 2018 monetizations were affected by the early settlement of April through December 2019 swaps and reducing the average fixed index prices on certain natural gas swap contracts maturing in 2020 while maintaining the total volumes hedged. The April through December 2019 swaps were replaced with collar agreements for which the Company paid a $13 million premium. The Company’s commodity derivative position presented in Note 11(a) reflects the volume and adjusted fixed price indices after the monetization. The fair value of derivative instruments was determined using Level 2 inputs.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Taxes
Income Taxes	(12) Income Taxes For the years ended December 31, 2016, 2017, and 2018, income tax expense (benefit) consisted of the following (in thousands): Year ended December 31, 2016 2017 2018 Current income tax expense (benefit) $ (10,984) 75 — Deferred income tax benefit (485,392) (295,126) (128,857) Total income tax benefit $ (496,376) (295,051) (128,857) Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% for the years ended December 31, 2016 and 2017, and 21% for the year ended December 31, 2018, to income or loss before taxes as a result of the following (in thousands): Year ended December 31, 2016 2017 2018 Federal income tax expense (benefit) $ (436,038) 171,530 (36,657) State income tax expense (benefit), net of federal benefit (20,364) 10,779 (12,627) Change in Federal tax rate, net of state benefit (1) — (427,962) — Change in State tax rate, net of federal effect — — (40,415) Nondeductible equity-based compensation 3,691 12,098 6,079 Noncontrolling interest in Antero Midstream (34,780) (59,523) (73,881) Change in valuation allowance (10,852) (2,073) 28,116 Other 1,967 100 528 Total income tax benefit $ (496,376) (295,051) (128,857) (1) The change in the Federal tax rate was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. The passage of this legislation resulted in the Company generating a deferred tax benefit in 2017 primarily due to the reduction in the U.S. statutory rate from 35% to 21%. Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2017 and 2018 is as follows (in thousands): 2017 2018 Deferred tax assets: Net operating loss carryforwards $ 727,522 734,255 Equity-based compensation 12,062 10,633 Investment in Antero Midstream 38,613 — Other 11,236 15,726 Total deferred tax assets 789,433 760,614 Valuation allowance (17,361) (45,477) Net deferred tax assets 772,072 715,137 Deferred tax liabilities: Unrealized gains on derivative instruments 442,855 271,747 Oil and gas properties 1,058,543 1,055,850 Investment in Antero Midstream — 11,258 Other 50,319 27,070 Total deferred tax liabilities 1,551,717 1,365,925 Net deferred tax liabilities $ (779,645) (650,788) In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the projections of future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of certain of these deductible differences and has recorded a valuation allowance of approximately $17 million and $45 million at December 31, 2017 and 2018, respectively related to state net operating loss (“NOL”) carryforwards. The increase in the valuation allowance from $17 million at December 31, 2017 to $45 million at December 31, 2018, is due to an additional allowance provided for Colorado NOLs because of a change in Colorado apportionment regulations. The amount of the deferred tax asset considered realizable could be further reduced in the near term if estimates of future taxable income during the carryforward period are revised. The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more‑likely-than‑not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. In 2016, the Company reversed unrecognized benefits recorded in prior years due to the expiration of the applicable statutes of limitations. The removal of the unrecognized benefits did not impact the Company’s 2016 effective tax rate. The Company will continue to monitor potential uncertain tax positions, but does not anticipate any changes within the next year. The Company had an $11 million unrecognized tax benefit at the beginning of the year ended December 31, 2016, which was reduced in the year ended December 31, 2016, and has no other balances through December 31, 2018. As of December 31, 2018, the Company has U.S. federal and state NOL carryforwards of $3.0 billion and $2.3 billion, respectively, which expire at various dates from 2019 to 2038. Tax years 2015 through 2018 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 2014 through 2018.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2018
Commitments
Commitments	(13) Commitments The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, which include leases that have remaining lease terms in excess of one year as of December 31, 2018 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (in millions) (a) (b) (c) (d) Total 2019 $ 1,075 389 133 15 1,612 2020 1,112 399 64 13 1,588 2021 1,089 390 7 11 1,497 2022 1,037 387 — 9 1,433 2023 1,024 379 — 7 1,410 Thereafter 8,752 1,722 — 49 10,523 Total $ 14,089 3,666 204 104 18,063 (a)  Firm Transportation The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of its production to market. These contracts commit the Company to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates. The amounts in this table are based on the Company’s minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. (b)  Processing, Gathering, and Compression Service Commitments The Company has entered into various long‑term gas processing agreements for certain of its production that will allow it to realize the value of its NGLs. The minimum payment obligations under the agreements are presented in the table. Certain of these obligations are accounted for as operating leases. The Company has various gathering and compression service agreements with third parties that provide for payments based on volumes gathered or compressed. The minimum payment obligations under these agreements are presented in the table. 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. The values in the table also include minimum processing fees to be paid to the Joint Venture owned by Antero Midstream and MarkWest. The table does not include intracompany commitments. Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance. (c)  Drilling Rigs and Completion Services Commitments The Company has obligations under agreements with service providers to procure drilling rigs and completion services. 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. Certain of these obligations are accounted for as operating leases. (d)  Office and Equipment Leases The Company leases various office space and equipment under capital and operating lease arrangements. Rental expense under operating leases was $9 million, $7 million, and $9 million for the years ended December 31, 2016, 2017, and 2018, respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2018
Contingencies
Contingencies	(14) Contingencies SJGC The Company is the plaintiff in two lawsuits against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) pending in United States District Court in Colorado. In March 2015, the Company filed suit against SJGC seeking relief for breach of contract and damages in the amounts that SJGC had short paid, and continued to short pay, the Company in connection with two nearly identical long term gas contracts. Under those contracts, SJGC are long term purchasers of 80,000 MMBtu/day of the Company’s natural gas production. Deliveries under the contracts began in October 2011 and the term of the contracts continues through October 2019. The price for gas was based on specified indices in the contracts. Beginning in October 2014, SJGC began short paying the Company based on price indices unilaterally selected by SJGC and not the applicable index specified in the contracts. SJGC claimed that the index price specified in the contracts, and the index at which SJGC paid for deliveries from 2011 through September 2014, was no longer appropriate under the contracts because a market disruption event (as defined by the contract) had occurred and, as a result, a new index price was required to be determined by the parties. The Company rejected SJGC’s contention that a market disruption event occurred. SJGC’s actions constituted a breach of the contracts by failing to pay the Company based on the express price terms of the contracts and paying the Company based on unilaterally selected price indices in violation of the contracts’ remedial provisions. On May 8, 2017, a jury in the United States District Court in Colorado returned a unanimous verdict finding in favor of Antero’s positions in the lawsuit against SJGC. On July 21, 2017, final judgment on the jury’s unanimous verdict was entered by the court. On August 18, 2017, SJGC filed post-judgment motions with the court. On March 23, 2018, the court denied SJGC’s post-judgment motions. On April 20, 2018, SJGC appealed the final judgment to the United States Court of Appeals for the Tenth Circuit and the appeal remains pending. Subsequent to the entry of judgment, SJGC has continued to short pay the Company on the basis of unilaterally selected price indices and not the index specified in the contract. Accordingly, on December 21, 2017, Antero filed suit against SJGC to recover for its damages since March of 2017. The second lawsuit remains pending. Through December 31, 2018, the Company estimates that it is owed approximately $86 million (gross damages, including interest) more than SJGC has paid using the indices unilaterally selected by them. Substantially all of this amount has not been accrued in the Company’s financial statements. The Company will vigorously seek recovery from SJGC of all underpayments and damages, including interest, based on the contracted price. WGL The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) were involved in a pricing dispute involving firm gas sales contracts executed June 20, 2014 (the “Contracts”) that the Company began delivering gas under in January 2016. From January 2016 through July 2017 and from December 2017 through January 2018, the aggregate daily gas volumes contracted for under the Contracts was 500,000 MMBtu/day, with the aggregate daily contracted volumes having increased to 600,000 MMBtu/day from August through November 2017. The Company invoiced WGL based on the natural gas index price specified in the Contracts and WGL paid the Company based on that invoice price. However, WGL asserted that the index price was no longer appropriate under the Contracts and claimed that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the Contracts and there will be no adjustments to the invoices that have been paid by WGL, nor will future invoices to WGL be adjusted based on the same claim rejected by the arbitration panel. The arbitration panel’s award was confirmed by the Colorado district court on April 14, 2017. In March of 2017, WGL filed a second legal proceeding against the Company in Colorado district court alleging breach of contract and seeking damages of more than $30 million. In this lawsuit, WGL claimed that the Company breached its contractual obligations under the Contracts by failing to deliver “TCO pool” gas. In subsequent filings, WGL explained that its claims were based on an alleged obligation that the Company must deliver gas to the Columbia IPP Pool (“IPP Pool”). WGL asserted this exact same issue in the arbitration and it was rejected by the arbitration panel. The arbitration panel specifically found that the Delivery Point under the Contracts was at a specific point in Braxton, West Virginia, not the IPP Pool. On August 24, 2017, the Colorado district court dismissed with prejudice WGL’s claims against the Company in its new lawsuit and found that the Company had not breached its Contracts with WGL by allegedly failing to deliver to the IPP Pool. The Court dismissed WGL’s lawsuit because WGL had not adequately pled a claim against Antero for the alleged failure to deliver “TCO pool” gas under the Contracts. WGL has appealed this decision to the Colorado Court of Appeals and on October 11, 2018 the Colorado Court of Appeals reversed the Colorado district court’s decision finding that WGL had adequately pled a claim for relief and remanded the case back to the district court for further proceedings. The Colorado Court of Appeals did not address the issue of whether WGL’s claims were independently barred by the prior arbitration’s findings. The Company is also actively engaged in pursuing cover damages against WGL based on WGL’s failure to take receipt of all of the agreed quantities of gas required under the Contracts. WGL’s failure to take the gas volumes specified in the Contracts is directly related to WGL’s lack of primary firm transportation rights at the Delivery Point. The failures by WGL to take the full contracted volumes gas began in April 2017 and continued each month through December 2017 in varying quantities. In defense of its conduct, WGL has asserted to the Company that their failure to receive gas is excused by (1) the Company’s failure to deliver gas to the IPP Pool or (2) alleged instances of Force Majeure under the Contracts. However, as stated above, the alleged obligation that the Company must deliver gas to the IPP Pool was already rejected by the arbitration panel. Further, the Contracts expressly prohibit a Force Majeure claim in circumstances in which the gas purchaser does not have primary firm transportation agreements in place to transport the purchased gas. In each instance that WGL has failed to receive the quantity of gas required under the Contracts, the Company has resold the quantities not taken and invoiced WGL for cover damages pursuant to the terms of the Contracts. WGL has refused to pay for the invoiced cover damages as required by the Contracts and has also short paid the Company for, among other things, certain amounts of gas received by WGL. Through December 31, 2018, these damages amounted to approximately $109 million (gross damages, including interest). This amount has not been accrued in the Company’s financial statements. The Company is currently pursuing its cover damages in a lawsuit filed in Colorado district court on October 24, 2017. The Company will continue to vigorously seek recovery of its cover damages and other unpaid amounts, including interest, as part of its claims against WGL. WGL’s claims have been consolidated with Antero’s claims in the same district court and trial is scheduled to begin on June 10, 2019. WGL has quantified its damages claim for the alleged failure to deliver TCO Pool gas and is seeking approximately $40 million from Antero. Effective February 1, 2018, as a result of a recent amendment to its firm gas sales contract with WGL Midstream, Inc. that was executed on December 28, 2017, the total aggregate volumes to be delivered to WGL at the delivery point in Braxton, West Virginia were reduced from 500,000 MMBtu/day to 200,000 MMBtu/day and in November 2018, the total aggregate contract volumes to be delivered to WGL at a delivery point in Loudoun County, Virginia increased by 330,000 MMBtu/day. This increase of 330,000 MMBtu/day is in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes are subject to NYMEX-based pricing. Following this increase, the aggregate contract volumes delivered to WGL total 530,000 MMBtu/day. Other The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes that certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2018
Related Parties
Related Parties	(15) Related Parties Certain of the Company’s shareholders, including members of its executive management group, own a significant interest in the Company and, either through their representatives or directly, serve as members of the Board of Directors of Antero and the Boards of Directors of the general partners of Antero Midstream and AMGP. These same groups or individuals own limited partner interests in Antero Midstream and common shares and other interests in AMGP, which indirectly owns the incentive distribution rights in Antero Midstream. Antero’s executive management group also manages the operations and business affairs of Antero Midstream and AMGP. Antero Midstream’s operations comprise substantially all of the operations of our gathering and processing segment and our water handling and treatment segment. Substantially all of the revenues for those segments in the years ended December 31, 2016, 2017, and 2018 were derived from transactions with Antero. See Note 16 for the operating results of the Company’s reportable segments.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Information
Segment Information	(16) Segment Information See Note 2(t) for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations are primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. Operating segments are evaluated based on their contribution to consolidated results, which is primarily determined by the respective operating income of each segment. General and administrative expenses are allocated to the gathering and processing and water handling and treatment segments 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 are transacted at prices which approximate market. Accounting policies for each segment as described in Note 2 to the consolidated financial statements. The operating results and assets of the Company’s reportable segments were as follows for the years ended December 31, 2016, 2017, and 2018 (in thousands): Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2016: Sales and revenues: Third-party $ 1,334,656 16,028 792 393,049 — 1,744,525 Intersegment 18,324 291,916 281,475 — (591,715) — Total $ 1,352,980 307,944 282,267 393,049 (591,715) 1,744,525 Operating expenses: Lease operating $ 50,651 — 136,386 — (136,947) 50,090 Gathering, compression, processing, and transportation 1,146,221 28,098 — — (291,481) 882,838 Depletion, depreciation, and amortization 709,127 70,847 29,899 — — 809,873 General and administrative 186,672 39,832 14,331 — (1,511) 239,324 Other 241,755 (809) 14,401 499,343 (16,489) 738,201 Total 2,334,426 137,968 195,017 499,343 (446,428) 2,720,326 Operating income (loss) $ (981,446) 169,976 87,250 (106,294) (145,287) (975,801) Equity in earnings of unconsolidated affiliates $ — 485 — — — 485 Segment assets $ 12,512,973 1,750,354 615,687 37,890 (661,354) 14,255,550 Capital expenditures for segment assets $ 2,220,688 231,044 188,188 — (144,491) 2,495,429 Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2017: Sales and revenues: Third-party $ 3,406,203 11,386 1,334 236,651 — 3,655,574 Intersegment 17,358 385,080 374,697 — (777,135) — Total $ 3,423,561 396,466 376,031 236,651 (777,135) 3,655,574 Operating expenses: Lease operating $ 93,758 — 189,702 — (194,403) 89,057 Gathering, compression, processing, and transportation 1,441,129 39,147 — — (384,637) 1,095,639 Depletion, depreciation, and amortization 704,152 87,268 33,190 — — 824,610 General and administrative 195,153 40,337 18,475 — (2,769) 251,196 Other 261,578 23,535 17,061 366,281 (13,476) 654,979 Total 2,695,770 190,287 258,428 366,281 (595,285) 2,915,481 Operating income (loss) $ 727,791 206,179 117,603 (129,630) (181,850) 740,093 Equity in earnings of unconsolidated affiliates $ — 20,194 — — — 20,194 Segment assets $ 13,074,027 2,253,163 804,296 36,701 (906,697) 15,261,490 Capital expenditures for segment assets $ 1,859,481 346,217 194,502 — (183,447) 2,216,753 Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2018: Sales and revenues: Third-party $ 3,565,300 17,817 3,527 552,982 — 4,139,626 Intersegment (87,472) 503,332 503,846 — (919,706) — Total $ 3,477,828 521,149 507,373 552,982 (919,706) 4,139,626 Operating expenses: Lease operating $ 142,234 — 262,704 — (268,785) 136,153 Gathering, compression, processing, and transportation 1,792,898 48,998 552 — (503,090) 1,339,358 Impairment of unproved properties 549,437 — — — — 549,437 Impairment of gathering systems and facilities — 9,658 — — — 9,658 Depletion, depreciation, and amortization 841,645 84,057 46,763 — — 972,465 General and administrative 181,305 46,609 15,020 — (2,590) 240,344 Other 129,947 258 (88,973) 686,055 93,019 820,306 Total 3,637,466 189,580 236,066 686,055 (681,446) 4,067,721 Operating income (loss) $ (159,638) 331,569 271,307 (133,073) (238,260) 71,905 Equity in earnings of unconsolidated affiliates $ — 40,280 — — — 40,280 Segment assets $ 12,986,945 2,465,858 1,077,004 34,499 (1,044,842) 15,519,464 Capital expenditures for segment assets $ 1,923,488 444,413 97,699 — (255,014) 2,210,586

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2018
Condensed Consolidating Financial Information
Condensed Consolidating Financial Information	(17) Condensed Consolidating Financial Information Each of Antero’s wholly-owned subsidiaries has fully and unconditionally guaranteed Antero’s senior notes. Antero Midstream and its subsidiaries have been designated as unrestricted subsidiaries under the Credit Facility and the indentures governing Antero’s senior notes, and do not guarantee any of Antero’s obligations (see Note 7). In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a “Subsidiary” of the Company (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease)) and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person which is not Antero or a restricted subsidiary of Antero, such subsidiary guarantor will be released from its obligations under its subsidiary guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the notes. In addition, a subsidiary guarantor will be released from its obligations under the indentures and its guarantee, upon the release or discharge of the guarantee of other Indebtedness (as defined in the indentures governing the notes) that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if Antero designates such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indentures governing the notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes. The following Condensed Consolidating Balance Sheets at December 31, 2017 and 2018, and the related Condensed Consolidating Statements of Operations and Comprehensive Income (Loss) and Condensed Consolidating Statements of Cash Flows for the years ended December 31, 2016, 2017, and 2018, present financial information for Antero on a stand‑alone basis (carrying its investment in subsidiaries using the equity method), financial information for the subsidiary guarantors, financial information for the non-guarantor subsidiaries, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. Antero’s wholly-owned subsidiaries are not restricted from making distributions to the Parent. Condensed Consolidating Balance Sheet December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 20,078 — 8,363 — 28,441 Accounts receivable, net 33,726 — 1,170 — 34,896 Intercompany receivables 6,459 — 110,182 (116,641) — Accrued revenue 300,122 — — — 300,122 Derivative instruments 460,685 — — — 460,685 Other current assets 8,273 — 670 — 8,943 Total current assets 829,343 — 120,385 (116,641) 833,087 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 2,266,673 — — — 2,266,673 Proved properties 11,460,615 — — (364,153) 11,096,462 Water handling and treatment systems — — 942,361 4,309 946,670 Gathering systems and facilities 17,929 — 2,032,561 — 2,050,490 Other property and equipment 57,429 — — — 57,429 13,802,646 — 2,974,922 (359,844) 16,417,724 Less accumulated depletion, depreciation, and amortization (2,812,851) — (369,320) — (3,182,171) Property and equipment, net 10,989,795 — 2,605,602 (359,844) 13,235,553 Derivative instruments 841,257 — — — 841,257 Investment in Antero Midstream (573,926) — — 573,926 — Contingent acquisition consideration 208,014 — — (208,014) — Investments in unconsolidated affiliates — — 303,302 — 303,302 Other assets 35,371 — 12,920 — 48,291 Total assets $ 12,329,854 — 3,042,209 (110,573) 15,261,490 Liabilities and Equity Current liabilities: Accounts payable $ 54,340 — 8,642 — 62,982 Intercompany payable 110,182 — 6,459 (116,641) — Accrued liabilities 338,819 — 106,006 (1,600) 443,225 Revenue distributions payable 209,617 — — — 209,617 Derivative instruments 28,476 — — — 28,476 Other current liabilities 17,587 — 209 — 17,796 Total current liabilities 759,021 — 121,316 (118,241) 762,096 Long-term liabilities: Long-term debt 3,604,090 — 1,196,000 — 4,800,090 Deferred income tax liability 779,645 — — — 779,645 Contingent acquisition consideration — — 208,014 (208,014) — Derivative instruments 207 — — — 207 Other liabilities 42,906 — 410 — 43,316 Total liabilities 5,185,869 — 1,525,740 (326,255) 6,385,354 Equity: Stockholders' equity: Partners' capital — — 1,516,469 (1,516,469) — Common stock 3,164 — — — 3,164 Additional paid-in capital 5,565,756 — — 1,005,196 6,570,952 Accumulated earnings 1,575,065 — — — 1,575,065 Total stockholders' equity 7,143,985 — 1,516,469 (511,273) 8,149,181 Noncontrolling interests in consolidated subsidiary — — — 726,955 726,955 Total equity 7,143,985 — 1,516,469 215,682 8,876,136 Total liabilities and equity $ 12,329,854 — 3,042,209 (110,573) 15,261,490 Condensed Consolidating Balance Sheet December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Accounts receivable, net $ 49,529 — 1,544 — 51,073 Intercompany receivables 383 — 115,378 (115,761) — Accrued revenue 474,827 — — — 474,827 Derivative instruments 245,263 — — — 245,263 Other current assets 13,937 — 21,513 — 35,450 Total current assets 783,939 — 138,435 (115,761) 806,613 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 1,767,600 — — — 1,767,600 Proved properties 13,306,585 — — (600,913) 12,705,672 Water handling and treatment systems — — 1,004,793 9,025 1,013,818 Gathering systems and facilities 17,825 — 2,452,883 — 2,470,708 Other property and equipment 65,770 — 72 — 65,842 15,157,780 — 3,457,748 (591,888) 18,023,640 Less accumulated depletion, depreciation, and amortization (3,654,392) — (499,333) — (4,153,725) Property and equipment, net 11,503,388 — 2,958,415 (591,888) 13,869,915 Derivative instruments 362,169 — — — 362,169 Investment in Antero Midstream (740,031) — — 740,031 — Contingent acquisition consideration 114,995 — — (114,995) — Investments in unconsolidated affiliates — — 433,642 — 433,642 Other assets 31,200 — 15,925 — 47,125 Total assets $ 12,055,660 — 3,546,417 (82,613) 15,519,464 Liabilities and Equity Current liabilities: Accounts payable $ 44,917 — 21,372 — 66,289 Intercompany payable 111,620 — 4,141 (115,761) — Accrued liabilities 392,949 — 72,121 — 465,070 Revenue distributions payable 310,827 — — — 310,827 Derivative instruments 532 — — — 532 Other current liabilities 4,621 — 2,052 4,149 10,822 Total current liabilities 865,466 — 99,686 (111,612) 853,540 Long-term liabilities: Long-term debt 3,829,541 — 1,632,147 — 5,461,688 Deferred income tax liability 650,788 — — — 650,788 Contingent acquisition consideration — — 114,995 (114,995) — Other liabilities 57,890 — 8,081 — 65,971 Total liabilities 5,403,685 — 1,854,909 (226,607) 7,031,987 Equity: Stockholders' equity: Partners' capital — — 1,691,508 (1,691,508) — Common stock 3,086 — — — 3,086 Additional paid-in capital 5,471,341 — — 1,013,833 6,485,174 Accumulated earnings 1,177,548 — — — 1,177,548 Total stockholders' equity 6,651,975 — 1,691,508 (677,675) 7,665,808 Noncontrolling interests in consolidated subsidiary — — — 821,669 821,669 Total equity 6,651,975 — 1,691,508 143,994 8,487,477 Total liabilities and equity $ 12,055,660 — 3,546,417 (82,613) 15,519,464 Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,260,750 — — — 1,260,750 Natural gas liquids sales 432,992 — — — 432,992 Oil sales 61,319 — — — 61,319 Gathering, compression, water handling and treatment — — 586,352 (573,391) 12,961 Marketing 393,049 — — — 393,049 Commodity derivative fair value losses (514,181) — — — (514,181) Gain on sale of assets 93,776 — 3,859 — 97,635 Other income 18,324 — — (18,324) — Total revenue and other 1,746,029 — 590,211 (591,715) 1,744,525 Operating expenses: Lease operating 50,651 — 136,387 (136,948) 50,090 Gathering, compression, processing, and transportation 1,146,221 — 28,097 (291,480) 882,838 Production and ad valorem taxes 69,485 — (2,897) — 66,588 Marketing 499,343 — — — 499,343 Exploration 6,862 — — — 6,862 Impairment of unproved properties 162,935 — — — 162,935 Depletion, depreciation, and amortization 710,012 — 99,861 — 809,873 Accretion of asset retirement obligations 2,473 — — — 2,473 General and administrative 186,672 — 54,163 (1,511) 239,324 Change in fair value of contingent acquisition consideration — — 16,489 (16,489) — Total operating expenses 2,834,654 — 332,100 (446,428) 2,720,326 Operating income (loss) (1,088,625) — 258,111 (145,287) (975,801) Other income (expenses): Equity in earnings of unconsolidated affiliates — — 485 — 485 Interest (232,455) — (21,893) 796 (253,552) Loss on early extinguishment of debt (16,956) — — — (16,956) Equity in earnings (loss) of Antero Midstream (7,156) — — 7,156 — Total other expenses (256,567) — (21,408) 7,952 (270,023) Income (loss) before income taxes (1,345,192) — 236,703 (137,335) (1,245,824) Provision for income tax benefit 496,376 — — — 496,376 Net income (loss) and comprehensive income (loss) including noncontrolling interests (848,816) — 236,703 (137,335) (749,448) Net income and comprehensive income attributable to noncontrolling interests — — — 99,368 99,368 Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ (848,816) — 236,703 (236,703) (848,816) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,769,975 — — (691) 1,769,284 Natural gas liquids sales 870,441 — — — 870,441 Oil sales 108,195 — — — 108,195 Commodity derivative fair value gains 658,283 — — — 658,283 Gathering, compression, water handling and treatment — — 772,497 (759,777) 12,720 Marketing 258,045 — — — 258,045 Marketing derivative loss (21,394) — — — (21,394) Other income 16,667 — — (16,667) — Total revenue and other 3,660,212 — 772,497 (777,135) 3,655,574 Operating expenses: Lease operating 93,758 — 189,702 (194,403) 89,057 Gathering, compression, processing, and transportation 1,441,129 — 39,147 (384,637) 1,095,639 Production and ad valorem taxes 90,832 — 3,689 — 94,521 Marketing 366,281 — — — 366,281 Exploration 8,538 — — — 8,538 Impairment of unproved properties 159,598 — — — 159,598 Impairment of gathering systems and facilities — — 23,431 — 23,431 Depletion, depreciation, and amortization 705,048 — 119,562 — 824,610 Accretion of asset retirement obligations 2,610 — — — 2,610 General and administrative 195,153 — 58,812 (2,769) 251,196 Change in fair value of contingent acquisition consideration — — 13,476 (13,476) — Total operating expenses 3,062,947 — 447,819 (595,285) 2,915,481 Operating income 597,265 — 324,678 (181,850) 740,093 Other income (expenses): Equity in earnings of unconsolidated affiliates — — 20,194 — 20,194 Interest (232,331) — (37,262) 892 (268,701) Loss on early extinguishment of debt (1,205) — (295) — (1,500) Equity in earnings (loss) of Antero Midstream (43,710) — — 43,710 — Total other expenses (277,246) — (17,363) 44,602 (250,007) Income before income taxes 320,019 — 307,315 (137,248) 490,086 Provision for income tax benefit 295,051 — — — 295,051 Net income and comprehensive income including noncontrolling interests 615,070 — 307,315 (137,248) 785,137 Net income and comprehensive income attributable to noncontrolling interests — — — 170,067 170,067 Net income and comprehensive income attributable to Antero Resources Corporation $ 615,070 — 307,315 (307,315) 615,070 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 2,287,939 — — — 2,287,939 Natural gas liquids sales 1,177,777 — — — 1,177,777 Oil sales 187,178 — — — 187,178 Commodity derivative fair value losses (87,594) — — — (87,594) Gathering, compression, water handling and treatment — — 1,027,939 (1,006,595) 21,344 Marketing 458,901 — — — 458,901 Marketing derivative gains 94,081 — — — 94,081 Gain on sale of assets — — 583 (583) — Other income (87,217) — — 87,217 — Total revenue and other 4,031,065 — 1,028,522 (919,961) 4,139,626 Operating expenses: Lease operating 142,234 — 262,704 (268,785) 136,153 Gathering, compression, processing, and transportation 1,792,898 — 49,550 (503,090) 1,339,358 Production and ad valorem taxes 122,305 — 4,169 — 126,474 Marketing 686,055 — — — 686,055 Exploration 4,958 — — — 4,958 Impairment of unproved properties 549,437 — — — 549,437 Impairment of gathering systems and facilities 4,470 — 5,771 (583) 9,658 Depletion, depreciation, and amortization 842,452 — 130,013 — 972,465 Accretion of asset retirement obligations 2,684 — 135 — 2,819 General and administrative 181,305 — 61,629 (2,590) 240,344 Change in fair value of contingent acquisition consideration — — (93,019) 93,019 — Total operating expenses 4,328,798 — 420,952 (682,029) 4,067,721 Operating income (loss) (297,733) — 607,570 (237,932) 71,905 Other income (expenses): Equity in earnings of unconsolidated affiliates — — 40,280 — 40,280 Interest (224,977) — (61,906) 140 (286,743) Equity in earnings (loss) of Antero Midstream (3,664) — — 3,664 — Total other expenses (228,641) — (21,626) 3,804 (246,463) Income (loss) before income taxes (526,374) — 585,944 (234,128) (174,558) Provision for income tax benefit 128,857 — — — 128,857 Net income (loss) and comprehensive income (loss) including noncontrolling interests (397,517) — 585,944 (234,128) (45,701) Net income and comprehensive income attributable to noncontrolling interests — — — 351,816 351,816 Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ (397,517) — 585,944 (585,944) (397,517) Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in) operating activities: Net income (loss) including noncontrolling interests $ (848,816) — 236,703 (137,335) (749,448) Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 712,485 — 99,861 — 812,346 Change in fair value of contingent acquisition consideration (16,489) — 16,489 — — Impairment of unproved properties 162,935 — — — 162,935 Commodity derivative fair value losses 514,181 — — — 514,181 Gains on settled commodity derivatives 1,003,083 — — — 1,003,083 Deferred income tax benefit (485,392) — — — (485,392) Gain on sale of assets (93,776) — (3,859) — (97,635) Equity-based compensation expense 76,372 — 26,049 — 102,421 Loss on early extinguishment of debt 16,956 — — — 16,956 Equity in earnings of Antero Midstream 7,156 — — (7,156) — Equity in earnings of unconsolidated affiliates — — (485) — (485) Distributions of earnings from unconsolidated affiliates — — 7,702 — 7,702 Other (14,302) — 1,814 — (12,488) Distributions from subsidiaries 107,364 — — (107,364) — Changes in current assets and liabilities (36,519) — (5,667) 9,266 (32,920) Net cash provided by operating activities 1,105,238 — 378,607 (242,589) 1,241,256 Cash flows provided by (used in) investing activities: Additions to proved properties (134,113) — — — (134,113) Additions to unproved properties (611,631) — — — (611,631) Drilling and completion costs (1,462,984) — — 135,225 (1,327,759) Additions to water handling and treatment systems 32 — (188,220) — (188,188) Additions to gathering systems and facilities (2,944) — (228,100) — (231,044) Additions to other property and equipment (2,694) — — — (2,694) Investments in unconsolidated affiliates — — (75,516) — (75,516) Change in other assets 304 — 3,673 — 3,977 Proceeds from asset sales 161,830 — 10,000 — 171,830 Net cash used in investing activities (2,052,200) — (478,163) 135,225 (2,395,138) Cash flows provided by (used in) financing activities: Issuance of common stock 1,012,431 — — — 1,012,431 Issuance of common units by Antero Midstream — — 65,395 — 65,395 Sale of common units in Antero Midstream by Antero 178,000 — — — 178,000 Issuance of senior notes 600,000 — 650,000 — 1,250,000 Repayment of senior notes (525,000) — — — (525,000) Repayments on bank credit facility, net (267,000) — (410,000) — (677,000) Make-whole premium on debt extinguished (15,750) — — — (15,750) Payments of deferred financing costs (8,324) — (10,435) — (18,759) Distributions — — (182,446) 107,364 (75,082) Employee tax withholding for settlement of equity compensation awards (21,260) — (5,635) — (26,895) Other (5,157) — (164) — (5,321) Net cash provided by financing activities 947,940 — 106,715 107,364 1,162,019 Net increase in cash and cash equivalents 978 — 7,159 — 8,137 Cash and cash equivalents, beginning of period 16,590 — 6,883 — 23,473 Cash and cash equivalents, end of period $ 17,568 — 14,042 — 31,610 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in)operating activities: Net income including noncontrolling interests $ 615,070 — 307,315 (137,248) 785,137 Adjustment to reconcile net income to net cash — Depletion, depreciation, amortization, and accretion 707,658 — 119,562 — 827,220 Change in fair value of contingent acquisition consideration (13,476) — 13,476 — — Impairment of unproved properties 159,598 — — — 159,598 Impairment of gathering systems and facilities — — 23,431 — 23,431 Commodity derivative fair value gains (658,283) — — — (658,283) Gains on settled commodity derivatives 213,940 — — — 213,940 Proceeds from derivative monetizations 749,906 — — — 749,906 Marketing derivative losses 21,394 — — — 21,394 Deferred income tax benefit (295,126) — — — (295,126) Equity-based compensation expense 76,162 — 27,283 — 103,445 Loss on early extinguishment of debt 1,205 — 295 — 1,500 Equity in earnings of Antero Midstream 43,710 — — (43,710) — Equity in earnings of unconsolidated affiliates — — (20,194) — (20,194) Distributions of earnings from unconsolidated affiliates — — 20,195 — 20,195 Other (4,500) — 2,593 — (1,907) Distributions from subsidiaries 131,598 — — (131,598) — Changes in current assets and liabilities 87,466 — (18,160) 6,729 76,035 Net cash provided by operating activities 1,836,322 — 475,796 (305,827) 2,006,291 Cash flows provided by (used in) investing activities: Additions to proved properties (175,650) — — — (175,650) Additions to unproved properties (204,272) — — — (204,272) Drilling and completion costs (1,455,554) — — 173,569 (1,281,985) Additions to water handling and treatment systems — — (195,162) 660 (194,502) Additions to gathering systems and facilities — — (346,217) — (346,217) Additions to other property and equipment (14,127) — — — (14,127) Investments in unconsolidated affiliates — — (235,004) — (235,004) Change in other assets (8,594) — (3,435) — (12,029) Other 2,156 — — — 2,156 Net cash used in investing activities (1,856,041) — (779,818) 174,229 (2,461,630) Cash flows provided by (used in) financing activities: Issuance of common units by Antero Midstream — — 248,956 — 248,956 Sale of common units in Antero Midstream by Antero Resources Corporation 311,100 — — — 311,100 Borrowings (repayments) on bank credit facility, net (255,000) — 345,000 — 90,000 Payments of deferred financing costs (10,857) — (5,520) — (16,377) Distributions — — (283,950) 131,598 (152,352) Employee tax withholding for settlement of equity compensation awards (18,229) — (5,945) — (24,174) Other (4,785) — (198) — (4,983) Net cash provided by financing activities 22,229 — 298,343 131,598 452,170 Net increase (decrease) in cash and cash equivalents 2,510 — (5,679) — (3,169) Cash and cash equivalents, beginning of period 17,568 — 14,042 — 31,610 Cash and cash equivalents, end of period $ 20,078 — 8,363 — 28,441 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in) operating activities: Net income (loss) including noncontrolling interests $ (397,517) — 585,944 (234,128) (45,701) Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 845,136 — 130,148 — 975,284 Change in fair value of contingent acquisition consideration 93,019 — (93,019) — — Impairment of unproved properties 549,437 — — — 549,437 Impairment of gathering systems and facilities 4,470 — 5,771 (583) 9,658 Commodity derivative fair value losses 87,594 — — — 87,594 Gains on settled commodity derivatives 243,112 — — — 243,112 Premium paid on derivative contracts (13,318) — — — (13,318) Proceeds from derivative monetizations 370,365 — — — 370,365 Marketing derivative fair value gains (94,081) — — — (94,081) Gains on settled marketing derivatives 72,687 — — — 72,687 Deferred income tax benefit (128,857) — — — (128,857) Gain on sale of assets — — (583) 583 — Equity-based compensation expense 49,341 — 21,073 — 70,414 Equity in earnings of Antero Midstream 3,664 — — (3,664) — Equity in earnings of unconsolidated affiliates — — (40,280) — (40,280) Distributions of earnings from unconsolidated affiliates — — 46,415 — 46,415 Distributions from Antero Midstream 159,181 — — (159,181) — Other 4,681 — 2,879 (2,879) 4,681 Changes in current assets and liabilities (26,059) — (788) 1,424 (25,423) Net cash provided by operating activities 1,822,855 — 657,560 (398,428) 2,081,987 Cash flows provided by (used in) investing activities: Additions to unproved properties (172,387) — — — (172,387) Drilling and completion costs (1,743,587) — — 255,014 (1,488,573) Additions to water handling and treatment systems — — (88,674) (9,025) (97,699) Additions to gathering systems and facilities 103 — (446,270) 1,754 (444,413) Additions to other property and equipment (7,441) — — (73) (7,514) Investments in unconsolidated affiliates — — (136,475) — (136,475) Change in other assets (72) — (3,591) — (3,663) Change in other liabilities — — 2,273 (2,273) — Other — — 6,150 (6,150) — Net cash used in investing activities (1,923,384) — (666,587) 239,247 (2,350,724) Cash flows provided by (used in) financing activities: Issuance of common units by Antero Midstream — — — — — Repurchases of common stock (129,084) — — — (129,084) Borrowings on bank credit facility, net 225,379 — 435,000 — 660,379 Payments of deferred financing costs — — (2,169) — (2,169) Distributions — — (426,452) 159,181 (267,271) Employee tax withholding for settlement of equity compensation awards (11,491) — (5,529) — (17,020) Other (4,353) — (186) — (4,539) Net cash provided by financing activities 80,451 — 664 159,181 240,296 Net decrease in cash and cash equivalents (20,078) — (8,363) — (28,441) Cash and cash equivalents, beginning of period 20,078 — 8,363 — 28,441 Cash and cash equivalents, end of period $ — — — — —

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information (Unaudited)
Quarterly Financial Information (Unaudited)	(18) Quarterly Financial Information (Unaudited) The Company’s quarterly consolidated financial information for the years ended December 31, 2017 and 2018 is summarized in the tables below (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. First Second Third Fourth Year Ended December 31, 2017: Total operating revenues $ 1,195,579 790,389 647,880 1,021,726 Total operating expenses 694,236 666,646 719,932 834,667 Operating income (loss) 501,343 123,743 (72,052) 187,059 Net income (loss) and comprehensive income (loss) including noncontrolling interest 305,558 39,965 (90,000) 529,614 Net income attributable to noncontrolling interest 37,162 45,097 45,063 42,745 Net income (loss) attributable to Antero Resources Corporation 268,396 (5,132) (135,063) 486,869 Earnings (loss) per common share—basic $ 0.85 (0.02) (0.43) 1.54 Earnings (loss) per common share—assuming dilution $ 0.85 (0.02) (0.43) 1.54 First Second Third Fourth Year Ended December 31, 2018: Total operating revenues $ 1,028,101 989,344 1,076,532 1,045,649 Total operating expenses 881,607 1,022,107 1,071,728 1,092,279 Operating income (loss) 146,494 (32,763) 4,804 (46,630) Net income (loss) and comprehensive income (loss) including noncontrolling interest 80,810 (67,275) (77,972) 18,736 Net income attributable to noncontrolling interest 65,977 69,110 76,447 140,282 Net income (loss) attributable to Antero Resources Corporation 14,833 (136,385) (154,419) (121,546) Earnings (loss) per common share $ 0.05 (0.43) (0.49) (0.39) Earnings (loss) per common share—diluted $ 0.05 (0.43) (0.49) (0.39)

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2018
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 following is supplemental information regarding the Company’s consolidated oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties. (a)  Capitalized Costs Relating to Oil and Gas Producing Activities Year ended December 31, (In thousands) 2017 2018 Proved properties $ 11,096,462 12,705,672 Unproved properties 2,266,673 1,767,600 13,363,135 14,473,272 Accumulated depletion and depreciation (2,783,832) (3,615,680) Net capitalized costs $ 10,579,303 10,857,592 (b)  Costs Incurred in Certain Oil and Gas Activities Year ended December 31, (In thousands) 2016 2017 2018 Acquisition costs: Proved property $ 134,113 175,650 — Unproved property 611,631 204,272 172,387 Development costs 1,000,903 897,287 1,164,800 Exploration costs 326,856 384,698 323,773 Total costs incurred $ 2,073,503 1,661,907 1,660,960 (c)  Results of Operations for Oil and Gas Producing Activities Year ended December 31, (In thousands) 2016 2017 2018 Revenues $ 1,755,061 2,747,920 3,652,894 Operating expenses: Production expenses 999,516 1,279,217 1,601,985 Exploration expenses 6,862 8,538 4,958 Depletion and depreciation 700,274 694,332 832,326 Impairment of unproved properties 162,935 159,598 549,437 Results of operations before income tax (expense) benefit (114,526) 606,235 664,188 Income tax (expense) benefit 43,334 (228,096) (156,350) Results of operations $ (71,192) 378,139 507,838 (d)  Oil and Gas Reserves The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the years ended December 31, 2016, 2017, and 2018 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (D&M) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States. Proved reserves are the estimated quantities of oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months. Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, cash flows from operations, future drilling and completion costs, and other economic factors. Natural NGLs Oil and Equivalents Proved reserves: December 31, 2015 9,533 587 26 13,215 Revisions (2,069) 275 3 (404) Extensions, discoveries and other additions 1,990 99 9 2,637 Production (505) (27) (2) (676) Purchases of reserves 475 23 2 624 Sales of reserves in place (10) — — (10) December 31, 2016 9,414 957 38 15,386 Revisions 342 (22) (6) 176 Extensions, discoveries and other additions 1,644 77 7 2,148 Production (591) (36) (2) (822) Purchases of reserves 289 13 1 373 December 31, 2017 11,098 989 38 17,261 Revisions (1,087) 8 (1) (1,042) Extensions, discoveries and other additions 2,125 98 12 2,781 Production (711) (43) (3) (989) Purchases of reserves — — — — December 31, 2018 11,425 1,052 46 18,011 Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2016 4,426 401 13 6,914 December 31, 2017 5,587 467 16 8,488 December 31, 2018 6,669 600 20 10,389 Proved undeveloped reserves: December 31, 2016 4,988 556 25 8,472 December 31, 2017 5,511 522 22 8,773 December 31, 2018 4,756 452 26 7,622 Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2016, 2017, and 2018 in the above table include the following: 2016 Changes in Reserves · Extensions, discoveries and other additions of 2,637 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales, which was aided in 2016 by longer laterals than in previous years and the utilization of advanced completion techniques. · Purchases of 624 Bcfe relate to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales. · Net downward revisions of 404 Bcfe include: · Upward revisions of 1,359 Bcfe are due to an increase in our actual and assumed future ethane recovery rate based on existing sales contracts for ethane. · Upward performance revisions of 762 Bcfe primarily relate to improved well performance. · Downward revisions of 2,478 Bcfe were due to the impact of the SEC 5-year development rule. Due to the SEC 5-year development rule, these primarily dry gas reserves were displaced by our updated development plan targeting more liquids-rich areas in our portfolio which have better economic returns. · Downward revisions of 47 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. · A downward revision of 10 Bcfe was related to our sale of producing and non-producing leasehold in Pennsylvania. · We produced 676 Bcfe during the year ended December 31, 2016. 2017 Changes in Reserves · Extensions, discoveries, and other additions of 2,148 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. · Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales. · Net upward revisions of 176 Bcfe include: · Upward revisions of 345 Bcfe related to improved well performance. · Net downward revisions of 188 Bcfe related to revisions to our 5-year development plan. This figure includes upward revisions of 2,092 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and downward revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. · Upward revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil. · Downward revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery. · We produced 822 Bcfe during the year ended December 31, 2017. 2018 Changes in Reserves · Extensions, discoveries, and other additions of 2, 781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. · Net downward revisions of 1,042 Bcfe include: · Downward revisions of 433 Bcfe related to well performance. · Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan. This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. · Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil. · Upward revisions of 115 Bcfe are due to an increase in our assumed future ethane recovery. · We produced 989 Bcfe during the year ended December 31, 2018. The following table sets forth the standardized measure of the discounted future net cash flows attributable to the Company’s proved reserves. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure. Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate. Year ended December 31, (in millions) 2016 2017 2018 Future cash inflows $ 36,800 55,824 64,199 Future production costs (21,275) (26,375) (30,007) Future development costs (3,902) (3,312) (3,453) Future net cash flows before income tax 11,623 26,137 30,739 Future income tax expense (1,042) (4,104) (5,505) Future net cash flows 10,581 22,033 25,234 10% annual discount for estimated timing of cash flows (7,294) (13,406) (14,756) Standardized measure of discounted future net cash flows $ 3,287 8,627 10,478 The 12‑month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe): December 31, 2016 $ 2.39 December 31, 2017 $ 3.23 December 31, 2018 $ 3.56 (f)  Changes in Standardized Measure of Discounted Future Net Cash Flow Year ended December 31, (in millions) 2016 2017 2018 Sales of oil and gas, net of productions costs $ (756) (1,469) (2,051) Net changes in prices and production costs (1,540) 3,918 707 Development costs incurred during the period 733 627 755 Net changes in future development costs 212 229 37 Extensions, discoveries and other additions 673 1,448 1,925 Acquisitions 66 258 — Divestitures (7) — — Revisions of previous quantity estimates 461 734 (53) Accretion of discount 363 368 1,018 Net change in income taxes 12 (1,159) (563) Other changes (163) 386 76 Net increase 54 5,340 1,851 Beginning of year 3,233 3,287 8,627 End of year $ 3,287 8,627 10,478

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Basis of Presentation	(a) Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of December 31, 2017 and 2018, and the results of its operations and its cash flows for the years ended December 31, 2016, 2017, and 2018. 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. As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.
Principles of Consolidation	(b) Principles of Consolidation The accompanying consolidated financial statements include the accounts of Antero, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. For the years ended December 31, 2016, 2017 and 2018, we have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are consolidated in the Company’s consolidated financial statements. Antero is the primary beneficiary of Antero Midstream based on its power to direct the activities that most significantly impact Antero Midstream’s economic performance, and its obligation to absorb losses of, or right to receive benefits from, Antero Midstream that could be significant to Antero Midstream. In reaching the determination that Antero is the primary beneficiary of Antero Midstream, the Company considered the following: · Antero Midstream was formed to own, operate, and develop midstream energy assets to service Antero’s production and completion activities under long-term service contracts. · Antero owned 52.8% of the outstanding limited partner interests in Antero Midstream at December 31, 2018. · Antero’s officers and management group also act as management of Antero Midstream and AMGP under services and secondment agreements between the respective parties. · Substantially all of Antero Midstream’s revenues are derived from services provided to Antero. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. Noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream which are owned by the public and the incentive distribution rights in Antero Midstream. Noncontrolling interests in consolidated subsidiaries is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. Such investments are included in Investments in unconsolidated affiliates on the Company’s consolidated balance sheets. Income from investees that are accounted for under the equity method is included in Equity in earnings of unconsolidated affiliates on the Company’s consolidated statements of operations and cash flows. The Company accounts for distributions received from equity method investees under the “nature of the distribution” approach. Under the nature of the distribution 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 which affect revenues, expenses, assets, and liabilities, as well as the disclosure of contingent assets and liabilities. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates. The Company’s consolidated financial statements are based on a number of significant estimates including estimates of natural gas, NGLs, and oil reserve quantities, which are the basis for the calculation of depletion and impairment of oil and gas properties. Reserve estimates, by their nature, are inherently imprecise. Other items in the Company’s consolidated financial statements which involve the use of significant estimates include derivative assets and liabilities, accrued revenue, deferred income taxes, equity-based compensation, asset retirement obligations, depreciation, amortization, and commitments and contingencies.
Risks and Uncertainties	(d) Risks and Uncertainties The markets for natural gas, NGLs, and oil have, and continue to, experience significant price fluctuations. Price fluctuations can result from variations in weather, levels of production, availability of transportation capacity to other regions of the country, the level of imports to and exports from the United States, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.
Cash and Cash Equivalents	(e) Cash and Cash Equivalents The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short‑term nature of these instruments. From time to time, the Company may be in the position of a “book overdraft” in which outstanding checks exceed cash and cash equivalents. The Company classifies book overdrafts in accounts payable 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, 2018, the book overdraft included within accounts payable and revenue distributions payable was $10 million and $28 million, respectively.
Oil and Gas Properties	(f) Oil and Gas Properties The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells‑in‑progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred no such charges during the years ended December 31, 2016, 2017, and 2018. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units‑of‑production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property‑by‑property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired, or are expected to expire, was $163 million, $160 million, and $549 million for the years ended December 31, 2016, 2017, and 2018, respectively. The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties at the end of each quarter, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties during the years ended December 31, 2016, 2017 and 2018. At December 31, 2018, the Company did not have capitalized costs related to exploratory wells‑in‑progress which have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units‑of‑production method. Depletion expense for oil and gas properties was $700 million, $694 million, and $832 million for the years ended December 31, 2016, 2017, and 2018, respectively.
Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems	(g) Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that is not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred. Gathering pipelines and compressor stations are depreciated using the straight‑line method over their estimated useful lives of 50 years. Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of 5 to 20 years. Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was $101 million, $120 million, and $131 million for the years ended December 31, 2016, 2017, and 2018, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
Impairment of Long Lived Assets Other than Oil and Gas Properties	(h) Impairment of Long‑Lived Assets Other than Oil and Gas Properties The Company evaluates its long‑lived assets other than natural 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. There were no impairments for such assets during the year ended December 31, 2016. Impairment of gathering systems and facilities of $23 million and $10 million during the years ended December 31, 2017 and 2018, respectively, relates to gathering facilities no longer or not expected to be utilized.
Other Property and Equipment	(i) Other Property and Equipment Other property and equipment assets are depreciated using the straight‑line method over their estimated useful lives, which range from 2 to 20 years. Depreciation expense for other property and equipment was $9 million, $10 million, and $9 million for the years ended December 31, 2016, 2017, and 2018, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment.
Deferred Financing Costs	(j) Deferred Financing Costs Deferred financing costs represent loan origination fees and other initial borrowing costs. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2018, the Company had $19 million of unamortized deferred financing costs included in other long‑term assets, and $35 million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write‑off of previously deferred debt issuance costs were $16 million, $13 million, and $13 million for the years ended December 31, 2016, 2017, and 2018, respectively.
Derivative Financial Instruments	(k) Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative positions. The Company records derivative instruments on the consolidated balance sheets as either assets or liabilities measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.
Asset Retirement Obligations Policy	(l) Asset Retirement Obligations The Company is obligated to dispose of certain long‑lived assets upon their abandonment. The Company’s asset retirement obligations (“AROs”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives, as well as Antero Midstream’s future closure and postclosure costs associated with the landfill, fresh water impoundments and waste water pits at its wastewater treatment facility. 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. Antero Midstream is under no legal obligations, neither contractually nor under the doctrine of promissory estoppel, to restore or dismantle its gathering pipelines, compressor stations, water delivery pipelines and facilities and wastewater treatment facility upon abandonment. Antero Midstream’s gathering pipelines, compressor stations, fresh water delivery pipelines and facilities and wastewater treatment facility have an indeterminate life, if properly maintained. Accordingly, Antero Midstream is not able to make a reasonable estimate of when future dismantlement and removal dates of its pipelines, compressor stations and facilities will occur.
Environmental Liabilities	(m) Environmental Liabilities Environmental expenditures that relate to an existing condition caused by past operations, and that do not contribute to current or future revenue generation, are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2017 and 2018, the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that it believes are likely to have a material adverse effect on its financial position, results of operations, or cash flows.
Natural Gas, NGLs, and Oil Revenues	(n) Natural Gas, NGLs, and Oil Revenues On May 28, 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers , which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU replaced most existing revenue recognition guidance in GAAP when it became effective and was incorporated into GAAP as Accounting Standards Codification (“ASC”) Topic 606. The Company elected the modified retrospective transition method when new standard became effective for the Company on January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on the Company’s financial results. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas. Sales of natural gas, NGLs, and oil are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the month that the sale occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a revenue distribution payable to the extent it receives more than its proportionate share of production revenues. At December 31, 2017 and 2018, the Company had no production imbalance positions. Under our natural gas sales contracts, we deliver natural gas to purchasers at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, Antero Midstream or third parties gather, compress, process and transport our natural gas. We maintain control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer control of the product at the delivery point and recognize revenue based on the contract price. The costs to gather, compress, process and transport the natural gas are recorded as Gathering, compression, processing and transportation expenses. NGLs, which are extracted from natural gas through processing, are either sold by us directly or by the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. The costs to further process and transport NGLs are recorded as Gathering, compression, processing, and transportation expenses. For NGLs sold by the processor, our processing contracts provide that we transfer control to the processor at the tailgate of the processing plant and we recognize revenue based on the price received from the processor. Under our oil sales contracts, we generally sell oil to the purchaser and collect a contractually agreed upon index price, net of pricing differentials. We recognize revenue based on the contract price when we transfer control of the product to the purchaser.
Marketing Revenues and Expenses	(o) Marketing Revenues and Expenses Marketing revenues are derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. We retain control of the purchased natural gas and NGLs prior to delivery to the purchaser. The Company has concluded that we are the principal in these arrangements and therefore we recognize revenue on a gross basis, with costs to purchase and transport natural gas and NGLs presented as marketing expenses. Contracts to sell third party gas and NGLs are generally subject to similar terms as contracts to sell our produced natural gas and NGLs. We satisfy performance obligations to the purchaser by transferring control of the product at the delivery point and recognize revenue based on the price received from the purchaser. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense.
Gathering compression, water handling and treatment revenue	(p)  Gathering, compression, water handling and treatment revenue Substantially all revenues from our gathering, compression, water handling and treatment operations are derived from intersegment transactions for services Antero Midstream provides to our exploration and production operations. The portion of such fees shown in our consolidated financial statements represent amounts charged to interest owners in Antero-operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Antero Midstream or usage of Antero Midstream’s gathering and compression systems. For gathering and compression revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a compressor station, high pressure volumes are delivered to a processing plant or transmission pipeline, and compression volumes are delivered to a high pressure line. Revenue is recognized based on the per Mcf gathering or compression fee charged by Antero Midstream in accordance with the gathering and compression agreement. For water handling and treatment revenue, Antero Midstream satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the hydration unit of a specified well pad and the wastewater volumes have been delivered to its wastewater treatment facility. For services contracted through third party providers, Antero Midstream’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or wastewater treatment fee charged by Antero Midstream in accordance with the water services agreement.
Concentrations of Credit Risk	(q) Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry or the utilities industry. The concentration of credit risk in two related industries affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables. The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2016, 2017, and 2018 are as follows: 2016 2017 2018 Company A 1 % — % 16 % Company B 29 22 14 Company C 13 15 7 All others 57 63 63 100 % 100 % 100 % The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due could have a material adverse effect on the Company’s financial condition and results of operations. The Company has economic hedges in place with sixteen different counterparties. The fair value of the Company’s commodity derivative contracts of approximately $607 million (excluding short-term commodity derivatives related to our marketing activities) at December 31, 2018 includes the following values by bank counterparty: Morgan Stanley - $115 million; JP Morgan - $102 million; Scotiabank - $97 million; Citigroup - $91 million; Wells Fargo - $80 million; Canadian Imperial Bank of Commerce - $51 million; BNP Paribas - $24 million; Bank of Montreal - $14 million; Toronto Dominion - $8 million; PNC - $8 million; SunTrust - $7 million; Natixis - $7 million; and Capital One - $3 million. The estimated fair value of commodity derivative assets has been risk-adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at December 31, 2018 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	(r) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense.
Fair Value Measurements	(s) Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long‑lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over‑the‑counter commodity price swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures.
Industry Segments and Geographic Information	(t) Industry Segments and Geographic Information Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration, development, and production of natural gas, NGLs, and oil; (2) gathering and processing; (3) water handling and treatment; and (4) marketing and utilization of excess firm transportation capacity. 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 resell the Company’s production to third parties located in foreign countries.
Earnings (Loss) Per Common Share	(u) Earnings (loss) Per Common Share Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during the period. Earnings (loss) per common share—assuming dilution for each period is computed after giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the period was also the end of the performance period required for the vesting of the awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive. 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, 2016 2017 2018 Basic weighted average number of shares outstanding 294,945 315,426 316,036 Add: Dilutive effect of restricted stock units — 817 — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — 40 — Diluted weighted average number of shares outstanding 294,945 316,283 316,036 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1) : Restricted stock units 6,740 1,521 2,844 Outstanding stock options 702 676 626 Performance stock units 659 1,054 1,705 (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive
Treasury Share Retirement	(v)  Treasury Share Retirement The Company retires treasury shares acquired through share repurchases and returns those shares to the status of authorized but unissued. When treasury shares are retired, the Company’s policy is to allocate the excess of the repurchase price over the par value of shares acquired first, to additional paid-in capital, and then to accumulated earnings. The portion allocable to additional paid-in capital is determined by applying a percentage, determined by dividing the number of shares to be retired by the number of shares issued, to the balance of additional paid-in capital as of retirement.
Recently Issued Accounting Standard	(w)  Recently Issued Accounting Standard On February 25, 2016, the FASB issued ASU No. 2016-02, Leases, which replaced most existing lease guidance in GAAP when it became effective on January 1, 2019. The standard requires lessees to record lease liabilities and right-of-use assets and we have elected to adopt the ongoing effects of the new standard prospectively. The standard also provides for the election of practical expedients in applying and adopting the standard. Practical expedients adopted by the Company include, (i) not reassessing whether expired or existing contracts contain leases under the new definition of a lease and retaining lease classification for expired or existing leases, (ii) the use of hindsight in determining the lease term, the likelihood that a lessee purchase option will be exercised, and impairment assessment, (iii) carrying forward the existing accounting treatment for land easements, and (iv) combining lease and non-lease components by asset class. Adoption of the standard will increase assets and liabilities on the Company’s consolidated balance sheet as well as result in additional disclosures regarding lease expenses, assets, and liabilities. The Company will recognize right-of- use assets and lease liabilities related to certain contractual obligations for office space, processing plants, drilling rigs, gas gathering lines, compressor stations, and other office and field equipment. The Company estimates that adoption of the standard will result in the recognition of right-of-use assets and related liabilities of approximately $2.0 billion. The Company does not believe that adoption of the standard will impact its operational strategies, growth prospects, income or cash flows. The Company has updated internal controls impacted by the new standard and acquired and implemented software to collect and account for lease data under the standard.
Equity-Based Compensation	(x)  Equity-Based Compensation We recognize compensation cost related to all equity-based awards in the financial statements based on their estimated grant date fair value. We are authorized to grant various types of equity-based compensation awards including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The grant date fair values are determined based on the type of award and may utilize market prices on the date of grant, Black-Scholes option-pricing model, Monte Carlo simulations, or other acceptable valuation methodologies, as appropriate for the type of equity-based award. Compensation cost is recognized ratably over the applicable vesting or service period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. See Note 9 for additional information regarding our equity-based compensation.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of Significant Accounting Policies
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales)	2016 2017 2018 Company A 1 % — % 16 % Company B 29 22 14 Company C 13 15 7 All others 57 63 63 100 % 100 % 100 %
Reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding	. The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): Year Ended December 31, 2016 2017 2018 Basic weighted average number of shares outstanding 294,945 315,426 316,036 Add: Dilutive effect of restricted stock units — 817 — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — 40 — Diluted weighted average number of shares outstanding 294,945 316,283 316,036 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share (1) : Restricted stock units 6,740 1,521 2,844 Outstanding stock options 702 676 626 Performance stock units 659 1,054 1,705 (1) The potential dilutive effects of these awards were excluded from the computation of earnings (loss) per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive.

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue
Schedule of disaggregation of revenue	In the following table, revenue is disaggregated by type (in thousands). The table also identifies the reportable segment to which the disaggregated revenues relate. For more information on reportable segments, see Note 16—Segment Information. Year Ended December 31, Segment to which 2016 2017 2018 revenues relate Revenues from contracts with customers: Natural gas sales $ 1,260,750 1,769,284 2,287,939 Exploration and production Natural gas liquids sales (ethane) 52,949 93,041 172,653 Exploration and production Natural gas liquids sales (C3+ NGLs) 380,043 777,400 1,005,124 Exploration and production Oil sales 61,319 108,195 187,178 Exploration and production Gathering and compression 12,169 11,386 17,817 Gathering and processing Water handling and treatment 792 1,334 3,527 Water handling and treatment Marketing 393,049 258,045 458,901 Marketing Total 2,161,071 3,018,685 4,133,139 Income from derivatives and other sources (416,546) 636,889 6,487 Total revenue and other $ 1,744,525 3,655,574 4,139,626

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2018
Antero Midstream Partners LP
Equity Method Investments
Schedule of reconciliation of investments in unconsolidated affiliates	The following table is a reconciliation of investments in unconsolidated affiliates for the years ending December 31, 2017 and 2018 in thousands): Stonewall (2) MarkWest Total Balance at December 31, 2016 $ 68,299 — 68,299 Investments (1) — 235,004 235,004 Equity in net income of unconsolidated affiliates 10,304 9,890 20,194 Distributions from unconsolidated affiliates (11,475) (8,720) (20,195) Balance at December 31, 2017 67,128 236,174 303,302 Investments (1) — 136,475 136,475 Equity in net income of unconsolidated affiliates 10,740 29,540 40,280 Distributions from unconsolidated affiliates (9,765) (36,650) (46,415) Balance at December 31, 2018 $ 68,103 365,539 433,642 (1) Investments in the Joint Venture relate to capital contributions for construction of additional processing facilities. Distributions are net of operating and capital requirements retained by Stonewall.

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities as of December 31, 2017 and 2018 consisted of the following items (in thousands): December 31, 2017 December 31, 2018 Capital expenditures $ 155,300 113,237 Gathering, compression, processing, and transportation expenses 88,850 148,032 Marketing expenses 59,049 67,082 Interest expense 40,861 43,444 Other 99,165 93,275 $ 443,225 465,070

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Long-Term Debt.
Schedule of long-term debt	Long‑term debt was as follows at December 31, 2017 and 2018 (in thousands): December 31, 2017 December 31, 2018 Antero Resources: Credit Facility (a) $ 185,000 405,000 5.375% senior notes due 2021 (b) 1,000,000 1,000,000 5.125% senior notes due 2022 (c) 1,100,000 1,100,000 5.625% senior notes due 2023 (d) 750,000 750,000 5.00% senior notes due 2025 (e) 600,000 600,000 Net unamortized premium 1,520 1,241 Net unamortized debt issuance costs (32,430) (26,700) Antero Midstream: Midstream Credit Facility (g) 555,000 990,000 5.375% senior notes due 2024 (h) 650,000 650,000 Net unamortized debt issuance costs (9,000) (7,853) $ 4,800,090 5,461,688

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligations
Schedule of reconciliation of asset retirement obligations	The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2017 and 2018 (in thousands): 2017 2018 Asset retirement obligations—beginning of year $ 32,736 34,610 Obligations settled (22) — Obligations incurred 4,044 9,981 Revisions to prior estimates (4,758) 11,569 Accretion expense 2,610 2,819 Asset retirement obligations—end of year $ 34,610 58,979

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Equity-Based Compensation
Schedule of equity-based compensation expense	The Company’s equity‑based compensation expense, by type of award, was as follows for the years ended December 31, 2016, 2017, and 2018 (in thousands): Year Ended December 31, 2016 2017 2018 Restricted stock unit awards $ 73,081 70,866 41,505 Stock options 2,578 2,375 1,799 Performance share unit awards 8,685 10,797 9,659 Antero Midstream phantom unit awards 16,095 17,461 15,351 Equity awards issued to directors 1,982 1,946 2,100 Total expense $ 102,421 103,445 70,414
Summary of restricted stock and restricted stock unit awards activity	Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2017 3,424,084 $ 28.51 $ 65,058 Granted 687,626 $ 20.69 Vested (1,933,130) $ 29.90 Forfeited (466,095) $ 25.65 Total awarded and unvested—December 31, 2018 1,712,485 $ 24.57 $ 16,080
Summary of stock option activity	Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2017 660,512 $ 50.48 7.06 $ — Granted — $ — Exercised — $ — Forfeited (80,895) $ 50.00 Expired — $ — Outstanding at December 31, 2018 579,617 $ 50.55 5.81 $ — Vested or expected to vest as of December 31, 2018 579,617 $ 50.55 5.81 $ — Exercisable at December 31, 2018 462,217 $ 50.69 5.69 $ —
Summary of Performance Stock Unit activity	A summary of PSU activity for the year ended December 31, 2018 is as follows: Number of Weighted Total awarded and unvested—December 31, 2017 1,283,843 $ 28.29 Granted 756,466 $ 23.61 Vested (41,666) $ 27.38 Forfeited (231,344) $ 27.89 Total awarded and unvested—December 31, 2018 1,767,299 $ 26.36
Schedule of weighted average fair value assumptions used for PSUs granted	Year Ended December 31, 2017 2018 Dividend yield — % — % Volatility 42 % 41 % Risk-free interest rate 1.40 % 2.49 % Weighted average fair value of awards granted $ 26.21 $ 24.85
Schedule of outstanding unvested restricted stock awards vesting schedule	Number of Weighted Aggregate Total awarded and unvested—December 31, 2017 1,042,963 $ 28.69 $ 30,288 Granted 260,847 $ 25.84 Vested (577,566) $ 28.63 Forfeited (143,244) $ 28.08 Total awarded and unvested—December 31, 2018 583,000 $ 27.63 $ 12,470

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments.
Schedule of outstanding commodity derivatives	Natural gas Weighted Three months ending March 31, 2019: NYMEX ($/MMBtu) 2,330,000 $ 3.62 Three months ending June 30, 2019: NYMEX ($/MMBtu) 755,000 $ 3.26 Three months ending September 30, 2019: NYMEX ($/MMBtu) 755,000 $ 3.32 Three months ending December 31, 2019: NYMEX ($/MMBtu) 755,000 $ 3.45 Year ending December 31, 2020: NYMEX ($/MMBtu) 1,417,500 $ 3.00 Year ending December 31, 2021: NYMEX ($/MMBtu) 710,000 $ 3.00 Year ending December 31, 2022: NYMEX ($/MMBtu) 850,000 $ 3.00 Year ending December 31, 2023: NYMEX ($/MMBtu) 90,000 $ 2.91
Tabular disclosure of commodity derivatives basis differential positions which settle on the pricing index to basis differential of Columbia Gas (TCO) to the NYMEX Henry Hub natural gas price.	As of December 31, 2018, the Company’s fixed price natural gas collar positions from April 1, 2019 through December 31, 2019 were as follows (abbreviations in the table refer to the index to which the collar position is tied, as follows: NYMEX=Henry Hub. Natural gas Weighted average index price MMbtu/day Ceiling price Floor price Three months ending June 30, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.30 $ 2.50 Three months ending September 30, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.30 $ 2.50 Three months ending December 31, 2019: NYMEX ($/MMBtu) 1,575,000 $ 3.52 $ 2.50
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	December 31, 2017 December 31, 2018 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity derivatives - current Derivative instruments $ 460,685 Derivative instruments $ 245,263 Commodity derivatives - noncurrent Derivative instruments 841,257 Derivative instruments 362,169 Total asset derivatives 1,301,942 607,432 Liability derivatives not designated as hedges for accounting purposes: Marketing derivatives - current Derivative instruments 21,394 Derivative instruments — Commodity derivatives - current Derivative instruments 7,082 Derivative instruments 532 Commodity derivatives - noncurrent Derivative instruments 207 Derivative instruments — Total liability derivatives 28,683 532 Net derivatives $ 1,273,259 $ 606,900
Schedule of gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts	The following table presents the gross values of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets as of the dates presented, all at fair value (in thousands): December 31, 2017 December 31, 2018 Gross Gross amounts Net amounts of assets (liabilities) on balance sheet Gross Gross amounts Net amounts Commodity derivative assets $ 1,367,554 (65,612) 1,301,942 $ 658,830 (51,398) 607,432 Commodity derivative liabilities $ (72,901) 65,612 (7,289) $ (51,930) 51,398 (532) Marketing derivative assets $ 311,083 (311,083) — $ — — — Marketing derivative liabilities $ (332,477) 311,083 (21,394) $ — — —
Summary of derivative fair value gains (losses)	The following is a summary of derivative fair value gains and losses and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2016, 2017, and 2018 (in thousands): Statement of Year ended December 31, location 2016 2017 2018 Commodity derivative fair value gains (losses) Revenue $ (514,181) 658,283 (87,594) Marketing derivative fair value gains (losses) Revenue $ — (21,394) 94,081

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Taxes
Schedule of income tax expense from continuing operations	For the years ended December 31, 2016, 2017, and 2018, income tax expense (benefit) consisted of the following (in thousands): Year ended December 31, 2016 2017 2018 Current income tax expense (benefit) $ (10,984) 75 — Deferred income tax benefit (485,392) (295,126) (128,857) Total income tax benefit $ (496,376) (295,051) (128,857)
Schedule of reconciliation of income tax expense from continuing operations	Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% for the years ended December 31, 2016 and 2017, and 21% for the year ended December 31, 2018, to income or loss before taxes as a result of the following (in thousands): Year ended December 31, 2016 2017 2018 Federal income tax expense (benefit) $ (436,038) 171,530 (36,657) State income tax expense (benefit), net of federal benefit (20,364) 10,779 (12,627) Change in Federal tax rate, net of state benefit (1) — (427,962) — Change in State tax rate, net of federal effect — — (40,415) Nondeductible equity-based compensation 3,691 12,098 6,079 Noncontrolling interest in Antero Midstream (34,780) (59,523) (73,881) Change in valuation allowance (10,852) (2,073) 28,116 Other 1,967 100 528 Total income tax benefit $ (496,376) (295,051) (128,857) (1) The change in the Federal tax rate was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act. The passage of this legislation resulted in the Company generating a deferred tax benefit in 2017 primarily due to the reduction in the U.S. statutory rate from 35% to 21%.
Schedule of net deferred tax assets and liabilities	The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2017 and 2018 is as follows (in thousands): 2017 2018 Deferred tax assets: Net operating loss carryforwards $ 727,522 734,255 Equity-based compensation 12,062 10,633 Investment in Antero Midstream 38,613 — Other 11,236 15,726 Total deferred tax assets 789,433 760,614 Valuation allowance (17,361) (45,477) Net deferred tax assets 772,072 715,137 Deferred tax liabilities: Unrealized gains on derivative instruments 442,855 271,747 Oil and gas properties 1,058,543 1,055,850 Investment in Antero Midstream — 11,258 Other 50,319 27,070 Total deferred tax liabilities 1,551,717 1,365,925 Net deferred tax liabilities $ (779,645) (650,788)

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments
Schedule of future minimum payments for firm transportation, drilling rig and completion services, gas processing, gathering and compression, office and equipment agreements, and leases that have remaining lease terms in excess of one year	The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, which include leases that have remaining lease terms in excess of one year as of December 31, 2018 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (in millions) (a) (b) (c) (d) Total 2019 $ 1,075 389 133 15 1,612 2020 1,112 399 64 13 1,588 2021 1,089 390 7 11 1,497 2022 1,037 387 — 9 1,433 2023 1,024 379 — 7 1,410 Thereafter 8,752 1,722 — 49 10,523 Total $ 14,089 3,666 204 104 18,063

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Information
Schedule of operating results and assets of reportable segments	The operating results and assets of the Company’s reportable segments were as follows for the years ended December 31, 2016, 2017, and 2018 (in thousands): Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2016: Sales and revenues: Third-party $ 1,334,656 16,028 792 393,049 — 1,744,525 Intersegment 18,324 291,916 281,475 — (591,715) — Total $ 1,352,980 307,944 282,267 393,049 (591,715) 1,744,525 Operating expenses: Lease operating $ 50,651 — 136,386 — (136,947) 50,090 Gathering, compression, processing, and transportation 1,146,221 28,098 — — (291,481) 882,838 Depletion, depreciation, and amortization 709,127 70,847 29,899 — — 809,873 General and administrative 186,672 39,832 14,331 — (1,511) 239,324 Other 241,755 (809) 14,401 499,343 (16,489) 738,201 Total 2,334,426 137,968 195,017 499,343 (446,428) 2,720,326 Operating income (loss) $ (981,446) 169,976 87,250 (106,294) (145,287) (975,801) Equity in earnings of unconsolidated affiliates $ — 485 — — — 485 Segment assets $ 12,512,973 1,750,354 615,687 37,890 (661,354) 14,255,550 Capital expenditures for segment assets $ 2,220,688 231,044 188,188 — (144,491) 2,495,429 Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2017: Sales and revenues: Third-party $ 3,406,203 11,386 1,334 236,651 — 3,655,574 Intersegment 17,358 385,080 374,697 — (777,135) — Total $ 3,423,561 396,466 376,031 236,651 (777,135) 3,655,574 Operating expenses: Lease operating $ 93,758 — 189,702 — (194,403) 89,057 Gathering, compression, processing, and transportation 1,441,129 39,147 — — (384,637) 1,095,639 Depletion, depreciation, and amortization 704,152 87,268 33,190 — — 824,610 General and administrative 195,153 40,337 18,475 — (2,769) 251,196 Other 261,578 23,535 17,061 366,281 (13,476) 654,979 Total 2,695,770 190,287 258,428 366,281 (595,285) 2,915,481 Operating income (loss) $ 727,791 206,179 117,603 (129,630) (181,850) 740,093 Equity in earnings of unconsolidated affiliates $ — 20,194 — — — 20,194 Segment assets $ 13,074,027 2,253,163 804,296 36,701 (906,697) 15,261,490 Capital expenditures for segment assets $ 1,859,481 346,217 194,502 — (183,447) 2,216,753 Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2018: Sales and revenues: Third-party $ 3,565,300 17,817 3,527 552,982 — 4,139,626 Intersegment (87,472) 503,332 503,846 — (919,706) — Total $ 3,477,828 521,149 507,373 552,982 (919,706) 4,139,626 Operating expenses: Lease operating $ 142,234 — 262,704 — (268,785) 136,153 Gathering, compression, processing, and transportation 1,792,898 48,998 552 — (503,090) 1,339,358 Impairment of unproved properties 549,437 — — — — 549,437 Impairment of gathering systems and facilities — 9,658 — — — 9,658 Depletion, depreciation, and amortization 841,645 84,057 46,763 — — 972,465 General and administrative 181,305 46,609 15,020 — (2,590) 240,344 Other 129,947 258 (88,973) 686,055 93,019 820,306 Total 3,637,466 189,580 236,066 686,055 (681,446) 4,067,721 Operating income (loss) $ (159,638) 331,569 271,307 (133,073) (238,260) 71,905 Equity in earnings of unconsolidated affiliates $ — 40,280 — — — 40,280 Segment assets $ 12,986,945 2,465,858 1,077,004 34,499 (1,044,842) 15,519,464 Capital expenditures for segment assets $ 1,923,488 444,413 97,699 — (255,014) 2,210,586

Condensed Consolidating Finan_2

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2018
Condensed Consolidating Financial Information
Schedule of condensed consolidated balance sheets	Condensed Consolidating Balance Sheet December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 20,078 — 8,363 — 28,441 Accounts receivable, net 33,726 — 1,170 — 34,896 Intercompany receivables 6,459 — 110,182 (116,641) — Accrued revenue 300,122 — — — 300,122 Derivative instruments 460,685 — — — 460,685 Other current assets 8,273 — 670 — 8,943 Total current assets 829,343 — 120,385 (116,641) 833,087 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 2,266,673 — — — 2,266,673 Proved properties 11,460,615 — — (364,153) 11,096,462 Water handling and treatment systems — — 942,361 4,309 946,670 Gathering systems and facilities 17,929 — 2,032,561 — 2,050,490 Other property and equipment 57,429 — — — 57,429 13,802,646 — 2,974,922 (359,844) 16,417,724 Less accumulated depletion, depreciation, and amortization (2,812,851) — (369,320) — (3,182,171) Property and equipment, net 10,989,795 — 2,605,602 (359,844) 13,235,553 Derivative instruments 841,257 — — — 841,257 Investment in Antero Midstream (573,926) — — 573,926 — Contingent acquisition consideration 208,014 — — (208,014) — Investments in unconsolidated affiliates — — 303,302 — 303,302 Other assets 35,371 — 12,920 — 48,291 Total assets $ 12,329,854 — 3,042,209 (110,573) 15,261,490 Liabilities and Equity Current liabilities: Accounts payable $ 54,340 — 8,642 — 62,982 Intercompany payable 110,182 — 6,459 (116,641) — Accrued liabilities 338,819 — 106,006 (1,600) 443,225 Revenue distributions payable 209,617 — — — 209,617 Derivative instruments 28,476 — — — 28,476 Other current liabilities 17,587 — 209 — 17,796 Total current liabilities 759,021 — 121,316 (118,241) 762,096 Long-term liabilities: Long-term debt 3,604,090 — 1,196,000 — 4,800,090 Deferred income tax liability 779,645 — — — 779,645 Contingent acquisition consideration — — 208,014 (208,014) — Derivative instruments 207 — — — 207 Other liabilities 42,906 — 410 — 43,316 Total liabilities 5,185,869 — 1,525,740 (326,255) 6,385,354 Equity: Stockholders' equity: Partners' capital — — 1,516,469 (1,516,469) — Common stock 3,164 — — — 3,164 Additional paid-in capital 5,565,756 — — 1,005,196 6,570,952 Accumulated earnings 1,575,065 — — — 1,575,065 Total stockholders' equity 7,143,985 — 1,516,469 (511,273) 8,149,181 Noncontrolling interests in consolidated subsidiary — — — 726,955 726,955 Total equity 7,143,985 — 1,516,469 215,682 8,876,136 Total liabilities and equity $ 12,329,854 — 3,042,209 (110,573) 15,261,490 Condensed Consolidating Balance Sheet December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Accounts receivable, net $ 49,529 — 1,544 — 51,073 Intercompany receivables 383 — 115,378 (115,761) — Accrued revenue 474,827 — — — 474,827 Derivative instruments 245,263 — — — 245,263 Other current assets 13,937 — 21,513 — 35,450 Total current assets 783,939 — 138,435 (115,761) 806,613 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 1,767,600 — — — 1,767,600 Proved properties 13,306,585 — — (600,913) 12,705,672 Water handling and treatment systems — — 1,004,793 9,025 1,013,818 Gathering systems and facilities 17,825 — 2,452,883 — 2,470,708 Other property and equipment 65,770 — 72 — 65,842 15,157,780 — 3,457,748 (591,888) 18,023,640 Less accumulated depletion, depreciation, and amortization (3,654,392) — (499,333) — (4,153,725) Property and equipment, net 11,503,388 — 2,958,415 (591,888) 13,869,915 Derivative instruments 362,169 — — — 362,169 Investment in Antero Midstream (740,031) — — 740,031 — Contingent acquisition consideration 114,995 — — (114,995) — Investments in unconsolidated affiliates — — 433,642 — 433,642 Other assets 31,200 — 15,925 — 47,125 Total assets $ 12,055,660 — 3,546,417 (82,613) 15,519,464 Liabilities and Equity Current liabilities: Accounts payable $ 44,917 — 21,372 — 66,289 Intercompany payable 111,620 — 4,141 (115,761) — Accrued liabilities 392,949 — 72,121 — 465,070 Revenue distributions payable 310,827 — — — 310,827 Derivative instruments 532 — — — 532 Other current liabilities 4,621 — 2,052 4,149 10,822 Total current liabilities 865,466 — 99,686 (111,612) 853,540 Long-term liabilities: Long-term debt 3,829,541 — 1,632,147 — 5,461,688 Deferred income tax liability 650,788 — — — 650,788 Contingent acquisition consideration — — 114,995 (114,995) — Other liabilities 57,890 — 8,081 — 65,971 Total liabilities 5,403,685 — 1,854,909 (226,607) 7,031,987 Equity: Stockholders' equity: Partners' capital — — 1,691,508 (1,691,508) — Common stock 3,086 — — — 3,086 Additional paid-in capital 5,471,341 — — 1,013,833 6,485,174 Accumulated earnings 1,177,548 — — — 1,177,548 Total stockholders' equity 6,651,975 — 1,691,508 (677,675) 7,665,808 Noncontrolling interests in consolidated subsidiary — — — 821,669 821,669 Total equity 6,651,975 — 1,691,508 143,994 8,487,477 Total liabilities and equity $ 12,055,660 — 3,546,417 (82,613) 15,519,464
Schedule of condensed consolidated statement of operations and comprehensive income (loss)	Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,260,750 — — — 1,260,750 Natural gas liquids sales 432,992 — — — 432,992 Oil sales 61,319 — — — 61,319 Gathering, compression, water handling and treatment — — 586,352 (573,391) 12,961 Marketing 393,049 — — — 393,049 Commodity derivative fair value losses (514,181) — — — (514,181) Gain on sale of assets 93,776 — 3,859 — 97,635 Other income 18,324 — — (18,324) — Total revenue and other 1,746,029 — 590,211 (591,715) 1,744,525 Operating expenses: Lease operating 50,651 — 136,387 (136,948) 50,090 Gathering, compression, processing, and transportation 1,146,221 — 28,097 (291,480) 882,838 Production and ad valorem taxes 69,485 — (2,897) — 66,588 Marketing 499,343 — — — 499,343 Exploration 6,862 — — — 6,862 Impairment of unproved properties 162,935 — — — 162,935 Depletion, depreciation, and amortization 710,012 — 99,861 — 809,873 Accretion of asset retirement obligations 2,473 — — — 2,473 General and administrative 186,672 — 54,163 (1,511) 239,324 Change in fair value of contingent acquisition consideration — — 16,489 (16,489) — Total operating expenses 2,834,654 — 332,100 (446,428) 2,720,326 Operating income (loss) (1,088,625) — 258,111 (145,287) (975,801) Other income (expenses): Equity in earnings of unconsolidated affiliates — — 485 — 485 Interest (232,455) — (21,893) 796 (253,552) Loss on early extinguishment of debt (16,956) — — — (16,956) Equity in earnings (loss) of Antero Midstream (7,156) — — 7,156 — Total other expenses (256,567) — (21,408) 7,952 (270,023) Income (loss) before income taxes (1,345,192) — 236,703 (137,335) (1,245,824) Provision for income tax benefit 496,376 — — — 496,376 Net income (loss) and comprehensive income (loss) including noncontrolling interests (848,816) — 236,703 (137,335) (749,448) Net income and comprehensive income attributable to noncontrolling interests — — — 99,368 99,368 Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ (848,816) — 236,703 (236,703) (848,816) Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,769,975 — — (691) 1,769,284 Natural gas liquids sales 870,441 — — — 870,441 Oil sales 108,195 — — — 108,195 Commodity derivative fair value gains 658,283 — — — 658,283 Gathering, compression, water handling and treatment — — 772,497 (759,777) 12,720 Marketing 258,045 — — — 258,045 Marketing derivative loss (21,394) — — — (21,394) Other income 16,667 — — (16,667) — Total revenue and other 3,660,212 — 772,497 (777,135) 3,655,574 Operating expenses: Lease operating 93,758 — 189,702 (194,403) 89,057 Gathering, compression, processing, and transportation 1,441,129 — 39,147 (384,637) 1,095,639 Production and ad valorem taxes 90,832 — 3,689 — 94,521 Marketing 366,281 — — — 366,281 Exploration 8,538 — — — 8,538 Impairment of unproved properties 159,598 — — — 159,598 Impairment of gathering systems and facilities — — 23,431 — 23,431 Depletion, depreciation, and amortization 705,048 — 119,562 — 824,610 Accretion of asset retirement obligations 2,610 — — — 2,610 General and administrative 195,153 — 58,812 (2,769) 251,196 Change in fair value of contingent acquisition consideration — — 13,476 (13,476) — Total operating expenses 3,062,947 — 447,819 (595,285) 2,915,481 Operating income 597,265 — 324,678 (181,850) 740,093 Other income (expenses): Equity in earnings of unconsolidated affiliates — — 20,194 — 20,194 Interest (232,331) — (37,262) 892 (268,701) Loss on early extinguishment of debt (1,205) — (295) — (1,500) Equity in earnings (loss) of Antero Midstream (43,710) — — 43,710 — Total other expenses (277,246) — (17,363) 44,602 (250,007) Income before income taxes 320,019 — 307,315 (137,248) 490,086 Provision for income tax benefit 295,051 — — — 295,051 Net income and comprehensive income including noncontrolling interests 615,070 — 307,315 (137,248) 785,137 Net income and comprehensive income attributable to noncontrolling interests — — — 170,067 170,067 Net income and comprehensive income attributable to Antero Resources Corporation $ 615,070 — 307,315 (307,315) 615,070 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) Year Ended December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 2,287,939 — — — 2,287,939 Natural gas liquids sales 1,177,777 — — — 1,177,777 Oil sales 187,178 — — — 187,178 Commodity derivative fair value losses (87,594) — — — (87,594) Gathering, compression, water handling and treatment — — 1,027,939 (1,006,595) 21,344 Marketing 458,901 — — — 458,901 Marketing derivative gains 94,081 — — — 94,081 Gain on sale of assets — — 583 (583) — Other income (87,217) — — 87,217 — Total revenue and other 4,031,065 — 1,028,522 (919,961) 4,139,626 Operating expenses: Lease operating 142,234 — 262,704 (268,785) 136,153 Gathering, compression, processing, and transportation 1,792,898 — 49,550 (503,090) 1,339,358 Production and ad valorem taxes 122,305 — 4,169 — 126,474 Marketing 686,055 — — — 686,055 Exploration 4,958 — — — 4,958 Impairment of unproved properties 549,437 — — — 549,437 Impairment of gathering systems and facilities 4,470 — 5,771 (583) 9,658 Depletion, depreciation, and amortization 842,452 — 130,013 — 972,465 Accretion of asset retirement obligations 2,684 — 135 — 2,819 General and administrative 181,305 — 61,629 (2,590) 240,344 Change in fair value of contingent acquisition consideration — — (93,019) 93,019 — Total operating expenses 4,328,798 — 420,952 (682,029) 4,067,721 Operating income (loss) (297,733) — 607,570 (237,932) 71,905 Other income (expenses): Equity in earnings of unconsolidated affiliates — — 40,280 — 40,280 Interest (224,977) — (61,906) 140 (286,743) Equity in earnings (loss) of Antero Midstream (3,664) — — 3,664 — Total other expenses (228,641) — (21,626) 3,804 (246,463) Income (loss) before income taxes (526,374) — 585,944 (234,128) (174,558) Provision for income tax benefit 128,857 — — — 128,857 Net income (loss) and comprehensive income (loss) including noncontrolling interests (397,517) — 585,944 (234,128) (45,701) Net income and comprehensive income attributable to noncontrolling interests — — — 351,816 351,816 Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ (397,517) — 585,944 (585,944) (397,517)
Schedule of condensed consolidated statement of cash flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in) operating activities: Net income (loss) including noncontrolling interests $ (848,816) — 236,703 (137,335) (749,448) Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 712,485 — 99,861 — 812,346 Change in fair value of contingent acquisition consideration (16,489) — 16,489 — — Impairment of unproved properties 162,935 — — — 162,935 Commodity derivative fair value losses 514,181 — — — 514,181 Gains on settled commodity derivatives 1,003,083 — — — 1,003,083 Deferred income tax benefit (485,392) — — — (485,392) Gain on sale of assets (93,776) — (3,859) — (97,635) Equity-based compensation expense 76,372 — 26,049 — 102,421 Loss on early extinguishment of debt 16,956 — — — 16,956 Equity in earnings of Antero Midstream 7,156 — — (7,156) — Equity in earnings of unconsolidated affiliates — — (485) — (485) Distributions of earnings from unconsolidated affiliates — — 7,702 — 7,702 Other (14,302) — 1,814 — (12,488) Distributions from subsidiaries 107,364 — — (107,364) — Changes in current assets and liabilities (36,519) — (5,667) 9,266 (32,920) Net cash provided by operating activities 1,105,238 — 378,607 (242,589) 1,241,256 Cash flows provided by (used in) investing activities: Additions to proved properties (134,113) — — — (134,113) Additions to unproved properties (611,631) — — — (611,631) Drilling and completion costs (1,462,984) — — 135,225 (1,327,759) Additions to water handling and treatment systems 32 — (188,220) — (188,188) Additions to gathering systems and facilities (2,944) — (228,100) — (231,044) Additions to other property and equipment (2,694) — — — (2,694) Investments in unconsolidated affiliates — — (75,516) — (75,516) Change in other assets 304 — 3,673 — 3,977 Proceeds from asset sales 161,830 — 10,000 — 171,830 Net cash used in investing activities (2,052,200) — (478,163) 135,225 (2,395,138) Cash flows provided by (used in) financing activities: Issuance of common stock 1,012,431 — — — 1,012,431 Issuance of common units by Antero Midstream — — 65,395 — 65,395 Sale of common units in Antero Midstream by Antero 178,000 — — — 178,000 Issuance of senior notes 600,000 — 650,000 — 1,250,000 Repayment of senior notes (525,000) — — — (525,000) Repayments on bank credit facility, net (267,000) — (410,000) — (677,000) Make-whole premium on debt extinguished (15,750) — — — (15,750) Payments of deferred financing costs (8,324) — (10,435) — (18,759) Distributions — — (182,446) 107,364 (75,082) Employee tax withholding for settlement of equity compensation awards (21,260) — (5,635) — (26,895) Other (5,157) — (164) — (5,321) Net cash provided by financing activities 947,940 — 106,715 107,364 1,162,019 Net increase in cash and cash equivalents 978 — 7,159 — 8,137 Cash and cash equivalents, beginning of period 16,590 — 6,883 — 23,473 Cash and cash equivalents, end of period $ 17,568 — 14,042 — 31,610 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2017 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in)operating activities: Net income including noncontrolling interests $ 615,070 — 307,315 (137,248) 785,137 Adjustment to reconcile net income to net cash — Depletion, depreciation, amortization, and accretion 707,658 — 119,562 — 827,220 Change in fair value of contingent acquisition consideration (13,476) — 13,476 — — Impairment of unproved properties 159,598 — — — 159,598 Impairment of gathering systems and facilities — — 23,431 — 23,431 Commodity derivative fair value gains (658,283) — — — (658,283) Gains on settled commodity derivatives 213,940 — — — 213,940 Proceeds from derivative monetizations 749,906 — — — 749,906 Marketing derivative losses 21,394 — — — 21,394 Deferred income tax benefit (295,126) — — — (295,126) Equity-based compensation expense 76,162 — 27,283 — 103,445 Loss on early extinguishment of debt 1,205 — 295 — 1,500 Equity in earnings of Antero Midstream 43,710 — — (43,710) — Equity in earnings of unconsolidated affiliates — — (20,194) — (20,194) Distributions of earnings from unconsolidated affiliates — — 20,195 — 20,195 Other (4,500) — 2,593 — (1,907) Distributions from subsidiaries 131,598 — — (131,598) — Changes in current assets and liabilities 87,466 — (18,160) 6,729 76,035 Net cash provided by operating activities 1,836,322 — 475,796 (305,827) 2,006,291 Cash flows provided by (used in) investing activities: Additions to proved properties (175,650) — — — (175,650) Additions to unproved properties (204,272) — — — (204,272) Drilling and completion costs (1,455,554) — — 173,569 (1,281,985) Additions to water handling and treatment systems — — (195,162) 660 (194,502) Additions to gathering systems and facilities — — (346,217) — (346,217) Additions to other property and equipment (14,127) — — — (14,127) Investments in unconsolidated affiliates — — (235,004) — (235,004) Change in other assets (8,594) — (3,435) — (12,029) Other 2,156 — — — 2,156 Net cash used in investing activities (1,856,041) — (779,818) 174,229 (2,461,630) Cash flows provided by (used in) financing activities: Issuance of common units by Antero Midstream — — 248,956 — 248,956 Sale of common units in Antero Midstream by Antero Resources Corporation 311,100 — — — 311,100 Borrowings (repayments) on bank credit facility, net (255,000) — 345,000 — 90,000 Payments of deferred financing costs (10,857) — (5,520) — (16,377) Distributions — — (283,950) 131,598 (152,352) Employee tax withholding for settlement of equity compensation awards (18,229) — (5,945) — (24,174) Other (4,785) — (198) — (4,983) Net cash provided by financing activities 22,229 — 298,343 131,598 452,170 Net increase (decrease) in cash and cash equivalents 2,510 — (5,679) — (3,169) Cash and cash equivalents, beginning of period 17,568 — 14,042 — 31,610 Cash and cash equivalents, end of period $ 20,078 — 8,363 — 28,441 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2018 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by (used in) operating activities: Net income (loss) including noncontrolling interests $ (397,517) — 585,944 (234,128) (45,701) Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 845,136 — 130,148 — 975,284 Change in fair value of contingent acquisition consideration 93,019 — (93,019) — — Impairment of unproved properties 549,437 — — — 549,437 Impairment of gathering systems and facilities 4,470 — 5,771 (583) 9,658 Commodity derivative fair value losses 87,594 — — — 87,594 Gains on settled commodity derivatives 243,112 — — — 243,112 Premium paid on derivative contracts (13,318) — — — (13,318) Proceeds from derivative monetizations 370,365 — — — 370,365 Marketing derivative fair value gains (94,081) — — — (94,081) Gains on settled marketing derivatives 72,687 — — — 72,687 Deferred income tax benefit (128,857) — — — (128,857) Gain on sale of assets — — (583) 583 — Equity-based compensation expense 49,341 — 21,073 — 70,414 Equity in earnings of Antero Midstream 3,664 — — (3,664) — Equity in earnings of unconsolidated affiliates — — (40,280) — (40,280) Distributions of earnings from unconsolidated affiliates — — 46,415 — 46,415 Distributions from Antero Midstream 159,181 — — (159,181) — Other 4,681 — 2,879 (2,879) 4,681 Changes in current assets and liabilities (26,059) — (788) 1,424 (25,423) Net cash provided by operating activities 1,822,855 — 657,560 (398,428) 2,081,987 Cash flows provided by (used in) investing activities: Additions to unproved properties (172,387) — — — (172,387) Drilling and completion costs (1,743,587) — — 255,014 (1,488,573) Additions to water handling and treatment systems — — (88,674) (9,025) (97,699) Additions to gathering systems and facilities 103 — (446,270) 1,754 (444,413) Additions to other property and equipment (7,441) — — (73) (7,514) Investments in unconsolidated affiliates — — (136,475) — (136,475) Change in other assets (72) — (3,591) — (3,663) Change in other liabilities — — 2,273 (2,273) — Other — — 6,150 (6,150) — Net cash used in investing activities (1,923,384) — (666,587) 239,247 (2,350,724) Cash flows provided by (used in) financing activities: Issuance of common units by Antero Midstream — — — — — Repurchases of common stock (129,084) — — — (129,084) Borrowings on bank credit facility, net 225,379 — 435,000 — 660,379 Payments of deferred financing costs — — (2,169) — (2,169) Distributions — — (426,452) 159,181 (267,271) Employee tax withholding for settlement of equity compensation awards (11,491) — (5,529) — (17,020) Other (4,353) — (186) — (4,539) Net cash provided by financing activities 80,451 — 664 159,181 240,296 Net decrease in cash and cash equivalents (20,078) — (8,363) — (28,441) Cash and cash equivalents, beginning of period 20,078 — 8,363 — 28,441 Cash and cash equivalents, end of period $ — — — — —

Quarterly Financial Informati_2

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information (Unaudited)
Schedule of quarterly financial information	The Company’s quarterly consolidated financial information for the years ended December 31, 2017 and 2018 is summarized in the tables below (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. First Second Third Fourth Year Ended December 31, 2017: Total operating revenues $ 1,195,579 790,389 647,880 1,021,726 Total operating expenses 694,236 666,646 719,932 834,667 Operating income (loss) 501,343 123,743 (72,052) 187,059 Net income (loss) and comprehensive income (loss) including noncontrolling interest 305,558 39,965 (90,000) 529,614 Net income attributable to noncontrolling interest 37,162 45,097 45,063 42,745 Net income (loss) attributable to Antero Resources Corporation 268,396 (5,132) (135,063) 486,869 Earnings (loss) per common share—basic $ 0.85 (0.02) (0.43) 1.54 Earnings (loss) per common share—assuming dilution $ 0.85 (0.02) (0.43) 1.54 First Second Third Fourth Year Ended December 31, 2018: Total operating revenues $ 1,028,101 989,344 1,076,532 1,045,649 Total operating expenses 881,607 1,022,107 1,071,728 1,092,279 Operating income (loss) 146,494 (32,763) 4,804 (46,630) Net income (loss) and comprehensive income (loss) including noncontrolling interest 80,810 (67,275) (77,972) 18,736 Net income attributable to noncontrolling interest 65,977 69,110 76,447 140,282 Net income (loss) attributable to Antero Resources Corporation 14,833 (136,385) (154,419) (121,546) Earnings (loss) per common share $ 0.05 (0.43) (0.49) (0.39) Earnings (loss) per common share—diluted $ 0.05 (0.43) (0.49) (0.39)

Supplemental Information on O_2

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Schedule of capitalized costs relating to oil and gas producing activities	Year ended December 31, (In thousands) 2017 2018 Proved properties $ 11,096,462 12,705,672 Unproved properties 2,266,673 1,767,600 13,363,135 14,473,272 Accumulated depletion and depreciation (2,783,832) (3,615,680) Net capitalized costs $ 10,579,303 10,857,592
Schedule of costs incurred in certain oil and gas activities	Year ended December 31, (In thousands) 2016 2017 2018 Acquisition costs: Proved property $ 134,113 175,650 — Unproved property 611,631 204,272 172,387 Development costs 1,000,903 897,287 1,164,800 Exploration costs 326,856 384,698 323,773 Total costs incurred $ 2,073,503 1,661,907 1,660,960
Schedule of results of operations (including discontinued operations) for oil and gas producing activities	Year ended December 31, (In thousands) 2016 2017 2018 Revenues $ 1,755,061 2,747,920 3,652,894 Operating expenses: Production expenses 999,516 1,279,217 1,601,985 Exploration expenses 6,862 8,538 4,958 Depletion and depreciation 700,274 694,332 832,326 Impairment of unproved properties 162,935 159,598 549,437 Results of operations before income tax (expense) benefit (114,526) 606,235 664,188 Income tax (expense) benefit 43,334 (228,096) (156,350) Results of operations $ (71,192) 378,139 507,838
Schedule of proved developed and undeveloped reserves	Natural NGLs Oil and Equivalents Proved reserves: December 31, 2015 9,533 587 26 13,215 Revisions (2,069) 275 3 (404) Extensions, discoveries and other additions 1,990 99 9 2,637 Production (505) (27) (2) (676) Purchases of reserves 475 23 2 624 Sales of reserves in place (10) — — (10) December 31, 2016 9,414 957 38 15,386 Revisions 342 (22) (6) 176 Extensions, discoveries and other additions 1,644 77 7 2,148 Production (591) (36) (2) (822) Purchases of reserves 289 13 1 373 December 31, 2017 11,098 989 38 17,261 Revisions (1,087) 8 (1) (1,042) Extensions, discoveries and other additions 2,125 98 12 2,781 Production (711) (43) (3) (989) Purchases of reserves — — — — December 31, 2018 11,425 1,052 46 18,011 Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2016 4,426 401 13 6,914 December 31, 2017 5,587 467 16 8,488 December 31, 2018 6,669 600 20 10,389 Proved undeveloped reserves: December 31, 2016 4,988 556 25 8,472 December 31, 2017 5,511 522 22 8,773 December 31, 2018 4,756 452 26 7,622
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	Year ended December 31, (in millions) 2016 2017 2018 Future cash inflows $ 36,800 55,824 64,199 Future production costs (21,275) (26,375) (30,007) Future development costs (3,902) (3,312) (3,453) Future net cash flows before income tax 11,623 26,137 30,739 Future income tax expense (1,042) (4,104) (5,505) Future net cash flows 10,581 22,033 25,234 10% annual discount for estimated timing of cash flows (7,294) (13,406) (14,756) Standardized measure of discounted future net cash flows $ 3,287 8,627 10,478
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	December 31, 2016 $ 2.39 December 31, 2017 $ 3.23 December 31, 2018 $ 3.56
Schedule of changes in standardized measure of discounted future net cash flow	Year ended December 31, (in millions) 2016 2017 2018 Sales of oil and gas, net of productions costs $ (756) (1,469) (2,051) Net changes in prices and production costs (1,540) 3,918 707 Development costs incurred during the period 733 627 755 Net changes in future development costs 212 229 37 Extensions, discoveries and other additions 673 1,448 1,925 Acquisitions 66 258 — Divestitures (7) — — Revisions of previous quantity estimates 461 734 (53) Accretion of discount 363 368 1,018 Net change in income taxes 12 (1,159) (563) Other changes (163) 386 76 Net increase 54 5,340 1,851 Beginning of year 3,233 3,287 8,627 End of year $ 3,287 8,627 10,478

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Principles of Consolidation (Details) $ in Thousands	12 Months Ended			36 Months Ended
	Dec. 31, 2018USD ($)segmentCounterparty	Dec. 31, 2017	Dec. 31, 2016USD ($)	Dec. 31, 2018USD ($)Counterparty
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 607,000			$ 607,000
Number of counterparties | Counterparty	16			16
Industry Segment and Geographic Information
Number of operating segments | segment	4
Basis of Presentation
Other comprehensive income (loss)				$ 0
Proceeds from issuance of stock			$ 1,012,431
Accounts Payable
Basis of Presentation
Bank Overdrafts	$ 10,000			10,000
Revenue distributions payable
Basis of Presentation
Bank Overdrafts	28,000			28,000
Morgan Stanley
Derivative Financial Instruments
Fair value of commodity derivative contracts	115,000			115,000
JP Morgan
Derivative Financial Instruments
Fair value of commodity derivative contracts	102,000			102,000
Scotiabank
Derivative Financial Instruments
Fair value of commodity derivative contracts	97,000			97,000
Citigroup
Derivative Financial Instruments
Fair value of commodity derivative contracts	91,000			91,000
Wells Fargo
Derivative Financial Instruments
Fair value of commodity derivative contracts	80,000			80,000
Canadian Imperial Bank of Commerce
Derivative Financial Instruments
Fair value of commodity derivative contracts	51,000			51,000
BNP Paribas
Derivative Financial Instruments
Fair value of commodity derivative contracts	24,000			24,000
Bank of Montreal
Derivative Financial Instruments
Fair value of commodity derivative contracts	14,000			14,000
Toronto Dominion
Derivative Financial Instruments
Fair value of commodity derivative contracts	8,000			8,000
PNC
Derivative Financial Instruments
Fair value of commodity derivative contracts	8,000			8,000
SunTrust
Derivative Financial Instruments
Fair value of commodity derivative contracts	7,000			7,000
Natixis
Derivative Financial Instruments
Fair value of commodity derivative contracts	7,000			7,000
Capital One
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 3,000			$ 3,000
Antero Midstream Partners LP
Basis of Presentation
Antero Resources ownership in Antero Midstream	52.80%	52.90%

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - USD ($) shares in Thousands, $ in Thousands	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings per share
Basic weighted average number of shares outstanding		316,036	315,426	294,945
Diluted weighted average number of shares outstanding		316,036	316,283	294,945
U.S. Statutory federal income tax rate (as a percent)	21.00%	21.00%	35.00%	35.00%
Benefit recognized from reduction in deferred tax liabilities due to a change in state tax laws			$ 427,962
Employee tax withholding for settlement of equity compensation awards		$ (17,020)	$ (24,174)	$ (26,895)
Restricted stock and restricted stock unit
Earnings per share
Add: Dilutive effect of non-vested restricted stock units			817
Weighted Average Anti-dilutive Awards		2,844	1,521	6,740
Stock options
Earnings per share
Weighted Average Anti-dilutive Awards		626	676	702
Performance share unit awards
Earnings per share
Add: Dilutive effect of non-vested restricted stock units			40
Weighted Average Anti-dilutive Awards		1,705	1,054	659

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Property and equipment (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)
Property and Equipment
Depreciation expense	$ 972,465	$ 824,610	$ 809,873
Oil and Gas Properties
Exploratory drilling costs initially capitalized, but subsequently charged to expense	0	0	0
Impairment of unproved properties for leases expired or expected to expire	549,000	160,000	163,000
Impairment of proved properties	0
Depreciation, depletion, and amortization expense for oil and gas properties	832,000	694,000	700,000
Asset Impairment Charges	$ 9,658	$ 23,431	0
Number of imbalance positions | item	0	0
Deferred Financing Costs
Unamortized deferred financing costs included in long-term debt	$ 35,000
Unamortized deferred financing costs included in other assets	19,000
Amounts amortized and the write-off of previously deferred debt issuance costs	$ 13,000	$ 13,000	16,000
Gathering Systems and Facilities
Property and Equipment
Estimated useful life	P50Y
Other property and equipment
Property and Equipment
Depreciation expense	$ 9,000	10,000	9,000
Other property and equipment | Minimum
Property and Equipment
Estimated useful life	P2Y
Other property and equipment | Maximum
Property and Equipment
Estimated useful life	P20Y
Gathering pipelines, compressor stations, and fresh water distribution systems
Property and Equipment
Depreciation expense	$ 131,000	$ 120,000	$ 101,000
Water handling and treatment | Minimum
Property and Equipment
Estimated useful life	P5Y
Water handling and treatment | Maximum
Property and Equipment
Estimated useful life	P20Y

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Credit Risk (Details) - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 25, 2016
ASU 2016-02
Concentrations of Credit Risk
Right-of-use assets and liabilities				$ 2
Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	100.00%	100.00%	100.00%
Company A | Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	16.00%		1.00%
Company B | Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	14.00%	22.00%	29.00%
Company C | Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	7.00%	15.00%	13.00%
All others | Sales | Customer concentration
Concentrations of Credit Risk
Sales to major customers (as a percent)	63.00%	63.00%	57.00%

Antero Midstream Partners LP (D

Antero Midstream Partners LP (Details) $ in Thousands, bbl in Millions	Sep. 11, 2017shares	Feb. 06, 2017USD ($)shares	Mar. 30, 2016shares	Sep. 23, 2015USD ($)sharesbbl	Dec. 31, 2018USD ($)mibbl	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)
Antero Midstream Partners LP
Investments in unconsolidated affiliates					$ 433,642	$ 303,302
Equity in earnings of unconsolidated affiliates					40,280	20,194	$ 485
Issuance of common stock							1,012,431
Consideration:
Amount borrowed on bank credit facility					$ 660,379	$ 90,000	$ (677,000)
Stonewall
Antero Midstream Partners LP
Distance of Pipeline Operation | mi					67
Antero Midstream Partners LP
Antero Midstream Partners LP
Number of shares of common stock issued (in shares) | shares		6,900,000
Issuance of common stock		$ 223,000
Equity Transactions
Number of Antero Midstream common units sold by Antero Resources (in units) | shares	10,000,000		8,000,000
Contingent Consideration Period One
Consideration:
Number of barrels of fresh water delivered | bbl					128
Contingent Consideration Period Two
Consideration:
Number of barrels of fresh water delivered | bbl					71
Antero Midstream Partners LP
Antero Midstream Partners LP
Antero Resources ownership in Antero Midstream					52.80%	52.90%
Stonewall
Antero Midstream Partners LP
Antero Resources ownership in Antero Midstream					15.00%
Antero Midstream Partners LP
Antero Midstream Partners LP
Equity in earnings of unconsolidated affiliates					$ 40,280	$ 20,194
Consideration:
Cash distribution				$ 552,000
Assumed debt				$ 171,000
Common units issued | shares				10,988,421
Antero Midstream Partners LP | Contingent Consideration Period One
Consideration:
Contingent consideration				$ 125,000
Threshold number of barrels of water to trigger contingent consideration payment | bbl				176
Antero Midstream Partners LP | Contingent Consideration Period Two
Consideration:
Contingent consideration				$ 125,000
Threshold number of barrels of water to trigger contingent consideration payment | bbl				219
Antero Midstream Partners LP | Private Placement
Equity Transactions
Proceeds from issuance of common units				$ 241,000
Antero Midstream Partners LP | At the Market Program
Equity Transactions
Units sold under At the Market program (in units) | shares						777,262
Proceeds from issuance of common units						$ 26,000
Aggregate dollar amount of common units available for issuance and sale under equity distribution agreement					250,000
Remaining capacity under equity distribution agreement					$ 157,000

Revenue (Details)

Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue
Revenues from contracts with customers									$ 4,133,139	$ 3,018,685	$ 2,161,071
Income from derivatives and other sources									6,487	636,889	(416,546)
Total revenue and other	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	4,139,626	3,655,574	1,744,525
Natural gas sales
Disaggregation of Revenue
Revenues from contracts with customers									2,287,939	1,769,284	1,260,750
Oil sales
Disaggregation of Revenue
Revenues from contracts with customers									187,178	108,195	61,319
Marketing
Disaggregation of Revenue
Revenues from contracts with customers									458,901	258,045	393,049
Exploration and production
Disaggregation of Revenue
Total revenue and other									3,565,300	3,406,203	1,334,656
Exploration and production | Natural gas sales
Disaggregation of Revenue
Revenues from contracts with customers									2,287,939	1,769,284	1,260,750
Exploration and production | Natural gas liquids sales (ethane)
Disaggregation of Revenue
Revenues from contracts with customers									172,653	93,041	52,949
Exploration and production | Natural gas liquids sales (C3+ NGLs)
Disaggregation of Revenue
Revenues from contracts with customers									1,005,124	777,400	380,043
Exploration and production | Oil sales
Disaggregation of Revenue
Revenues from contracts with customers									187,178	108,195	61,319
Gathering and compression
Disaggregation of Revenue
Total revenue and other									17,817	11,386	16,028
Gathering and compression | Gathering and compression
Disaggregation of Revenue
Revenues from contracts with customers									17,817	11,386	12,169
Water handling and treatment
Disaggregation of Revenue
Total revenue and other									3,527	1,334	792
Water handling and treatment | Water handling and treatment
Disaggregation of Revenue
Revenues from contracts with customers									3,527	1,334	792
Marketing
Disaggregation of Revenue
Total revenue and other									552,982	236,651	393,049
Marketing | Marketing
Disaggregation of Revenue
Revenues from contracts with customers									$ 458,901	$ 258,045	$ 393,049

Revenue - Transaction Price All

Revenue - Transaction Price Allocation and Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue
Original expected duration	true
Receivables from contracts with customers	$ 475	$ 300

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	Feb. 06, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Investments in unconsolidated affiliates
Equity in earnings of unconsolidated affiliates		$ 40,280	$ 20,194	$ 485
Distributions of earnings from unconsolidated affiliates		(46,415)	(20,195)	(7,702)
Antero Midstream Partners LP
Investments in unconsolidated affiliates
Balance at beginning of period		303,302	68,299
Investments		136,475	235,004
Equity in earnings of unconsolidated affiliates		40,280	20,194
Distributions of earnings from unconsolidated affiliates		(46,415)	(20,195)
Balance at end of period		433,642	303,302	$ 68,299
Antero Midstream Partners LP | Stonewall
Equity Method Investments
Ownership percentage				15.00%
Investments in unconsolidated affiliates
Balance at beginning of period		67,128	68,299
Equity in earnings of unconsolidated affiliates		10,740	10,304
Distributions of earnings from unconsolidated affiliates		(9,765)	(11,475)
Balance at end of period		68,103	67,128	$ 68,299
Antero Midstream Partners LP | Appalachia joint venture
Equity Method Investments
Ownership percentage	50.00%
Percentage of interest held by joint venture in third party fractionator in Ohio	33.33%
Investments in unconsolidated affiliates
Balance at beginning of period		236,174
Investments		136,475	235,004
Equity in earnings of unconsolidated affiliates		29,540	9,890
Distributions of earnings from unconsolidated affiliates		(36,650)	(8,720)
Balance at end of period		$ 365,539	$ 236,174
Antero Midstream Partners LP | MarkWest | Appalachia joint venture
Equity Method Investments
Ownership percentage	50.00%

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Accrued Liabilities
Accrued capital expenditures	$ 113,237	$ 155,300
Accrued gathering, compression, processing, and transportation expenses	148,032	88,850
Accrued marketing expenses	67,082	59,049
Accrued interest expense	43,444	40,861
Other accrued liabilities	93,275	99,165
Total accrued liabilities	$ 465,070	$ 443,225

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 21, 2016	Sep. 13, 2016	Mar. 17, 2015	Sep. 18, 2014	May 06, 2014	Nov. 05, 2013
Long- term Debt
Net unamortized premium	$ 1,241	$ 1,520
Net unamortized debt issuance costs	(26,700)	(32,430)
Long-term debt	5,461,688	4,800,090
Loss on Early Extinguishment of Debt		(1,500)	$ (16,956)
Credit Facility
Long- term Debt
Bank credit facility long-term debt	405,000	$ 185,000
Current borrowing base	4,500
Lender commitments	$ 2,500
Time period prior to maturity date of senior notes as one option for maturity date of Credit Facility	91 days
Weighted average interest rate (as a percent)	3.95%	2.96%
Outstanding letters of credit	$ 685,000	$ 705,000
Credit Facility | Minimum
Long- term Debt
Commitment fees on the unused portion during any period that is not an Investment Grade Period (as a percent)	0.30%
Commitment fees on the unused portion during an Investment Grade period (as a percent)	0.15%
Credit Facility | Minimum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate	0.25%
Credit Facility | Minimum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate	0.125%
Credit Facility | Maximum
Long- term Debt
Commitment fees on the unused portion during any period that is not an Investment Grade Period (as a percent)	0.375%
Commitment fees on the unused portion during an Investment Grade period (as a percent)	0.30%
Credit Facility | Maximum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate	2.25%
Credit Facility | Maximum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate	1.75%
5.375% senior notes due 2021
Long- term Debt
Long-term notes payable	$ 1,000,000	1,000,000
Interest rate (as a percent)									5.375%
Senior notes issued									$ 1,000,000
Issue price as percentage of par value									100.00%
Redemption price of the debt instrument in the event of change of control (as a percent)	101.00%
Redemption price	101.344%
5.375% senior notes due 2021 | On or after November 1, 2019
Long- term Debt
Redemption price	100.00%
Stand-alone revolving note
Long- term Debt
Maximum amount of the Credit Facility	$ 25,000
Stand-alone revolving note | Other Current Liabilities [Member]
Long- term Debt
Outstanding balance	$ 5,400	0
Stand-alone revolving note | Lender's Prime Rate
Long- term Debt
Basis spread on variable rate (as a percent)	1.00%
5.125 senior notes due 2022
Long- term Debt
Long-term notes payable	$ 1,100,000	1,100,000
Interest rate (as a percent)								5.125%
Senior notes issued							$ 500,000	$ 600,000
Issue price as percentage of par value							100.50%	100.00%
Redemption price	102.563%
Redemption price at which notes may be required to be repurchased in event of change of control	101.00%
5.125 senior notes due 2022 | On or after June 1, 2020
Long- term Debt
Redemption price of the debt instrument in the event of change of control (as a percent)	100.00%
5.625% senior notes due 2023
Long- term Debt
Long-term notes payable	$ 750,000	750,000
Interest rate (as a percent)						5.625%
Senior notes issued						$ 750,000
Issue price as percentage of par value	100.00%
Redemption price	104.219%
Redemption price at which notes may be required to be repurchased in event of change of control	101.00%
5.625% senior notes due 2023 | On Or After June 1, 2021
Long- term Debt
Redemption price	100.00%
5.00% senior notes due 2025
Long- term Debt
Long-term notes payable	$ 600,000	600,000
Interest rate (as a percent)				5.00%
Senior notes issued				$ 600,000
Issue price as percentage of par value				100.00%
Redemption price at which notes may be required to be repurchased in event of change of control	101.00%
5.00% senior notes due 2025 | Prior to March 1, 2020
Long- term Debt
Redemption price	100.00%
5.00% senior notes due 2025 | On or before March 1, 2020
Long- term Debt
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings	35.00%
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)	105.00%
5.00% senior notes due 2025 | On or after March 1, 2020
Long- term Debt
Redemption price	103.75%
5.00% senior notes due 2025 | On or after March1, 2023
Long- term Debt
Redemption price	100.00%
Antero Midstream Partners LP
Long- term Debt
Net unamortized debt issuance costs	$ (7,853)	(9,000)
Antero Midstream Partners LP | Midstream Credit Facility
Long- term Debt
Bank credit facility long-term debt	990,000	$ 555,000
Maximum amount of the Credit Facility	$ 2,000,000
Weighted average interest rate (as a percent)	3.75%	2.81%
Antero Midstream Partners LP | Midstream 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)	0.25%
Commitment fees on the unused portion during an Investment Grade period (as a percent)	0.175%
Antero Midstream Partners LP | Midstream Credit Facility | Minimum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate	0.25%
Antero Midstream Partners LP | Midstream Credit Facility | Minimum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate	0.125%
Antero Midstream Partners LP | Midstream Credit Facility | Maximum
Long- term Debt
Commitment fees on the unused portion during any period that is not an Investment Grade Period (as a percent)	0.375%
Commitment fees on the unused portion during an Investment Grade period (as a percent)	0.375%
Antero Midstream Partners LP | Midstream Credit Facility | Maximum | Not Investment Grade Period
Long- term Debt
Basis points added to the reference rate	2.25%
Antero Midstream Partners LP | Midstream Credit Facility | Maximum | Investment Grade Period
Long- term Debt
Basis points added to the reference rate	2.00%
Antero Midstream Partners LP | 5.375% senior notes due 2024
Long- term Debt
Long-term notes payable	$ 650,000	$ 650,000
Senior notes issued					$ 650,000
Issue price as percentage of par value					5.375%
Redemption price at which notes may be required to be repurchased in event of change of control	101.00%
Antero Midstream Partners LP | 5.375% senior notes due 2024 | On or after September 15, 2019
Long- term Debt
Redemption price	104.031%
Antero Midstream Partners LP | 5.375% senior notes due 2024 | On or after September 15, 2022
Long- term Debt
Redemption price	100.00%
Antero Midstream Partners LP | 5.375% senior notes due 2024 | Prior to September 15, 2019
Long- term Debt
Redemption price	100.00%
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings	35.00%
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)	105.375%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 34,610	$ 32,736
Obligations settled		(22)
Obligations incurred for wells drilled and producing properties acquired	9,981	4,044
Revisions to prior estimates	11,569	(4,758)
Accretion expense	2,819	2,610	$ 2,473
Asset retirement obligations - end of period	$ 58,979	$ 34,610	$ 32,736

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock-based compensation expense
Number of stock-based compensation awards authorized	16,906,500
Number of shares available for future grant under the Plan	8,351,638
Equity based compensation expense recognized	$ 70,414	$ 103,445	$ 102,421
Midstream Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized	10,000,000
Number of shares available for future grant under the Plan	7,932,261
Restricted stock awards
Stock-based compensation expense
Equity based compensation expense recognized	$ 41,505	70,866	73,081
Performance share unit awards
Stock-based compensation expense
Equity based compensation expense recognized	9,659	10,797	8,685
Stock options
Stock-based compensation expense
Equity based compensation expense recognized	1,799	2,375	2,578
Antero Midstream Partners Phantom Unit Awards
Stock-based compensation expense
Equity based compensation expense recognized	15,351	17,461	16,095
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized	$ 2,100	$ 1,946	$ 1,982

Equity-Based Compensation - Res

Equity-Based Compensation - Restricted Stock and RSU Awards (Details) - Restricted stock awards $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Number of shares
Total granted and unvested at the beginning of the period (in shares) | shares	3,424,084
Granted (in shares) | shares	687,626
Vested (in shares) | shares	(1,933,130)
Forfeited (in shares) | shares	(466,095)
Total awarded and unvested at the end of the period (in shares) | shares	1,712,485
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 28.51
Granted (in dollars per share) | $ / shares	20.69
Vested (in dollars per share) | $ / shares	29.90
Forfeited (in dollars per share) | $ / shares	25.65
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 24.57
Aggregate intrinsic value
Total awarded and unvested at the beginning of the period | $	$ 65,058
Total awarded and unvested at the end of the period | $	16,080
Additional equity compensation to be recognized over the remaining period | $	$ 27,000
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 3 months 18 days

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Stock options
Outstanding at the beginning of the period (in shares)	660,512
Options forfeited (in shares)	(80,895)
Outstanding at the end of the period (in shares)	579,617	660,512
Vested or expected to vest (in shares)	579,617
Exercisable (in shares)	462,217
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.48
Options forfeited (in dollars per share)	50
Outstanding at the end of the period (in dollars per share)	50.55	$ 50.48
Vested or expected to vest (in dollars per share)	50.55
Exercisable (in dollars per share)	$ 50.69
Weighted average remaining contractual life
Outstanding	5 years 9 months 22 days	7 years 22 days
Vested or expected to vest	5 years 9 months 22 days
Exercisable	5 years 8 months 9 days
Weighted-average assumptions used to calculate fair value of stock options granted
Dividend yield (as a percent)	0.00%
Additional disclosures
Unrecognized stock-based compensation expense	$ 0.5
Weighted average period for recognizing unrecognized stock-based compensation expense	3 months 18 days
Maximum
Stock-based compensation
Contractual life	10 years

Equity-Based Compensation - PSU

Equity-Based Compensation - PSU awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended		24 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2017
Performance share unit awards
Number of units
Total granted and unvested at the beginning of the period (in shares)	1,283,843
Granted (in shares)	756,466
Vested (in shares)	(41,666)
Forfeited (in shares)	(231,344)
Total awarded and unvested at the end of the period (in shares)	1,767,299	1,283,843	1,283,843
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share)	$ 28.29
Granted (in dollars per share)	23.61
Vested (in dollars per share)	27.38
Forfeited (in dollars per share)	27.89
Total awarded and unvested at the end of the period (in dollars per share)	26.36	$ 28.29	$ 28.29
Weighted-average assumptions used to calculate fair value of performance share units granted
Weighted average fair value of awards granted (in dollars per share)	$ 23.61
Price target and TSR performance share unit awards
Price target as a percentage of beginning price	125.00%
Vesting period	3 years
Amortization period of PSU expense	3 years
Price target and TSR performance share unit awards | Minimum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent	0.00%
Price target and TSR performance share unit awards | Maximum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent	200.00%
Price target performance share unit awards
Number of successive days closing stock price must achieve specific thresholds for PSUs to vest per schedule	10 days
Vesting period	3 years
Price target performance share unit awards | Vesting before first anniversary | Maximum
Number of PSUs that may vest, as a percent	0.00%
Price target performance share unit awards | Vesting before the second anniversary | Maximum
Number of PSUs that may vest, as a percent	33.33%
Price target performance share unit awards | Vesting before the third anniversary | Maximum
Number of PSUs that may vest, as a percent	66.66%
TSR performance share unit awards
Vesting period	3 years		3 years
TSR performance share unit awards | Minimum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent			0.00%
TSR performance share unit awards | Maximum
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent	200.00%
ROCE performance share unit awards
Vesting period	3 years
ROCE performance share unit awards | Minimum
Number of PSUs that may vest, as a percent	0.00%
ROCE performance share unit awards | Maximum
Number of PSUs that may vest, as a percent	200.00%
Market-Based PSUs
Weighted average grant date fair value
Granted (in dollars per share)	$ 24.85	$ 26.21
Additional disclosures
Additional equity compensation to be recognized over the remaining period	$ 20
Weighted average period for recognizing unrecognized stock-based compensation expense	1 year 10 months 24 days
Weighted-average assumptions used to calculate fair value of performance share units granted
Dividend yield (as a percent)		0.00%
Volatility (as a percent)	41.00%	42.00%
Risk-free interest rate (as a percent)	2.49%	1.40%
Weighted average fair value of awards granted (in dollars per share)	$ 24.85	$ 26.21

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Unit Awards (Details) - Antero Midstream Partners Phantom Unit Awards $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Number of units
Total granted and unvested at the beginning of the period (in shares) | shares	1,042,963
Granted (in shares) | shares	260,847
Vested (in shares) | shares	(577,566)
Forfeited (in shares) | shares	(143,244)
Total awarded and unvested at the end of the period (in shares) | shares	583,000
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 28.69
Granted (in dollars per share) | $ / shares	25.84
Vested (in dollars per share) | $ / shares	28.63
Forfeited (in dollars per share) | $ / shares	28.08
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 27.63
Aggregate intrinsic value
Outstanding at the beginning of the period | $	$ 30,288
Outstanding at the end of the period | $	12,470
Additional equity compensation to be recognized over the remaining period | $	$ 12,000
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 6 months

Financial Instruments (Details)

Financial Instruments (Details) - Recurring - Level 2 market data - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Financial Instruments
Fair value of senior notes	$ 3,300	$ 3,500
Antero Midstream Partners LP
Financial Instruments
Fair value of senior notes	$ 608	$ 670

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details) $ in Thousands	Dec. 31, 2018USD ($)MMBTU / d$ / MMBTU	Dec. 31, 2017USD ($)
Derivatives not designated as hedges for accounting purposes | NYMEX | Three Months Ending June302019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	1,575,000
Weighted average index price ceiling price	3.30
Weighted average index price floor price	2.50
Derivatives not designated as hedges for accounting purposes | NYMEX | Three Months Ending September302019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	1,575,000
Weighted average index price ceiling price	3.30
Weighted average index price floor price	2.50
Derivatives not designated as hedges for accounting purposes | NYMEX | Three Months Ending December312019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	1,575,000
Weighted average index price ceiling price	3.52
Weighted average index price floor price	2.50
Commodity derivative
Derivative Instruments
Gross amounts on balance sheet | $	$ 658,830	$ 1,367,554
Commodity derivative | Derivatives not designated as hedges for accounting purposes
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	225,000
Gross amounts on balance sheet | $	$ 13,000
Commodity derivative | Derivatives not designated as hedges for accounting purposes | Basis Differential Positions | Minimum
Derivative Instruments
Weighted average index price	0.215
Commodity derivative | Derivatives not designated as hedges for accounting purposes | Basis Differential Positions | Maximum
Derivative Instruments
Weighted average index price	0.40
Swaps | Natural gas | NYMEX | Three Months Ending March312019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,330,000
Weighted average index price	3.62
Swaps | Natural gas | NYMEX | Three Months Ending June302019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	755,000
Weighted average index price	3.26
Swaps | Natural gas | NYMEX | Three Months Ending September302019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	755,000
Weighted average index price	3.32
Swaps | Natural gas | NYMEX | Three Months Ending December312019 [Member]
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	755,000
Weighted average index price	3.45
Swaps | Natural gas | NYMEX | Year ending December 31, 2020
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	1,417,500
Weighted average index price	3
Swaps | Natural gas | NYMEX | Year Ending December 31, 2021
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	710,000
Weighted average index price	3
Swaps | Natural gas | NYMEX | Year ending December 31, 2022
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	850,000
Weighted average index price	3
Swaps | Natural gas | NYMEX | Year ending December 31, 2023
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	90,000
Weighted average index price	2.91

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) $ in Thousands	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)item
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 245,263	$ 460,685
Noncurrent portion of fair value of derivative assets	362,169	841,257
Current portion of fair value of derivative liabilities	532	28,476
Noncurrent portion of fair value of derivative liabilities		207
Net derivatives	606,900	1,273,259
Commodity derivative
Fair value of derivative instruments
Total asset derivatives	607,432	1,301,942
Total liability derivatives	532	7,289
Marketing derivative
Fair value of derivative instruments
Total liability derivatives		21,394
Derivatives not designated as hedges for accounting purposes
Fair value of derivative instruments
Total asset derivatives	607,432	1,301,942
Total liability derivatives	532	28,683
Derivatives not designated as hedges for accounting purposes | Commodity derivative
Fair value of derivative instruments
Current portion of fair value of derivative assets	245,263	460,685
Noncurrent portion of fair value of derivative assets	362,169	841,257
Current portion of fair value of derivative liabilities	$ 532	7,082
Noncurrent portion of fair value of derivative liabilities		207
Derivatives not designated as hedges for accounting purposes | Marketing derivative
Fair value of derivative instruments
Current portion of fair value of derivative liabilities		$ 21,394
Derivatives designated as hedges for accounting purposes
Fair value of derivative instruments
Number of derivative instruments held designated as hedges | item	0	0

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Commodity derivative
Commodity derivative assets
Gross amounts on balance sheet	$ 658,830	$ 1,367,554
Gross amounts offset on balance sheet	(51,398)	(65,612)
Total asset derivatives	607,432	1,301,942
Commodity derivative liabilities
Gross amounts on balance sheet	(51,930)	(72,901)
Gross amounts offset on balance sheet	51,398	65,612
Total liability derivatives	$ (532)	(7,289)
Marketing derivative
Commodity derivative assets
Gross amounts on balance sheet		311,083
Gross amounts offset on balance sheet		(311,083)
Commodity derivative liabilities
Gross amounts on balance sheet		(332,477)
Gross amounts offset on balance sheet		311,083
Total liability derivatives		$ (21,394)

Derivative Instruments - Fair_2

Derivative Instruments - Fair value gains (losses) (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)		$ (87,594)	$ 658,283	$ (514,181)
Gains on settled marketing derivatives		72,687
Marketing derivative fair value gains (losses)		94,081	(21,394)
Commodity derivative fair value gains (losses) on derivatives monetized prior to settlement dates		370,000	750,000
Premium paid for a collar agreement		13,000
Derivative liabilities
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)		73,000	94,000
Marketing derivative fair value gains (losses)		73,000
Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)		(87,594)	658,283	$ (514,181)
Marketing derivative fair value gains (losses)		$ 94,081	$ (21,394)
Commodity derivative fair value gains (losses)
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)	$ 21,000

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income tax expense from continuing operations
Current income tax expense (benefit)			$ 75	$ (10,984)
Deferred income tax expense (benefit)		$ (128,857)	(295,126)	(485,392)
Total income tax expense from continuing operations		$ (128,857)	$ (295,051)	$ (496,376)
U.S. Statutory federal income tax rate (as a percent)	21.00%	21.00%	35.00%	35.00%
Reconciliation of income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate to consolidated income
Federal income tax expense		$ (36,657)	$ 171,530	$ (436,038)
State income tax expense , net of federal benefit		(12,627)	10,779	(20,364)
Change in Federal tax rate, net of state benefit			(427,962)
Change in State tax rate, net of federal effect		(40,415)
Nondeductible stock compensation		6,079	12,098	3,691
Noncontrolling interest in Antero Midstream Partners LP		(73,881)	(59,523)	(34,780)
Change in valuation allowance		28,116	(2,073)	(10,852)
Other		528	100	1,967
Total income tax expense from continuing operations		(128,857)	(295,051)	(496,376)
Income tax expense (benefit) allocated to continuing and discontinued operations
Total income tax expense from continuing operations		(128,857)	(295,051)	$ (496,376)
Deferred tax assets:
Net operating loss carryforwards		734,255	727,522
Equity based compensation		10,633	12,062
Investment in Antero Midstream Partners LP			38,613
Other		15,726	11,236
Total deferred tax assets		760,614	789,433
Valuation allowance		(45,477)	(17,361)
Net deferred tax assets		715,137	772,072
Deferred tax liabilities:
Unrealized gains on derivative instruments		271,747	442,855
Oil and gas properties		1,055,850	1,058,543
Investment in Antero Midstream Partners LP		11,258
Other		27,070	50,319
Total deferred tax liabilities		1,365,925	1,551,717
Net deferred tax liabilities		(650,788)	(779,645)
State
Deferred tax liabilities:
Valuation allowance on net operating loss carryforwards		$ 45,000	$ 17,000

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Unrecognized tax benefits
Unrecognized tax benefits	$ 0	$ 11
U.S Federal
Income Taxes
Net operating loss carryforward	3,000,000
State
Income Taxes
Net operating loss carryforward	$ 2,300,000

Commitments (Detail)

Commitments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Future minimum payments
2,019	$ 1,612
2,020	1,588
2,021	1,497
2,022	1,433
2,023	1,410
Thereafter	10,523
Total	18,063
Firm transportation
Future minimum payments
2,019	1,075
2,020	1,112
2,021	1,089
2,022	1,037
2,023	1,024
Thereafter	8,752
Total	14,089
Gas processing, gathering and compression
Future minimum payments
2,019	389
2,020	399
2,021	390
2,022	387
2,023	379
Thereafter	1,722
Total	3,666
Drilling rigs and completion services
Future minimum payments
2,019	133
2,020	64
2,021	7
Total	204
Office and equipment
Future minimum payments
2,019	15
2,020	13
2,021	11
2,022	9
2,023	7
Thereafter	49
Total	104
Commitments
Rental expense under operating leases	$ 9	$ 7	$ 9

Contingencies (Details)

Contingencies (Details) $ in Millions	Feb. 01, 2018MMBTU / d	Jan. 31, 2018MMBTU / d	Jul. 31, 2017MMBTU / d	Jan. 31, 2018MMBTU / d	Nov. 30, 2017MMBTU / d	Jun. 30, 2017MMBTU / d	Dec. 31, 2018USD ($)MMBTU / dcontractlawsuit	Dec. 31, 2016MMBTU / d	Nov. 30, 2018MMBTU / d	Mar. 31, 2018USD ($)	Mar. 31, 2017USD ($)
SJGC
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day							80,000
WGL
Contingencies
Natural gas long term purchase contract volume after specified events (in MMBtu)/day									530,000
WGL | Pending Litigation
Contingencies
Damages sought | $							$ 109			$ 40
WGL | Pending Litigation | Minimum
Contingencies
Damages sought | $											$ 30
WGL - Braxton, West Virginia
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day	200,000	500,000
WGL - Loudoun County, Virginia
Contingencies
Natural gas long term purchase contract volume increase after specified events (in MMBtu)/day									330,000
Potential Positive Outcome of Litigation | SJGC
Contingencies
Number of lawsuits | lawsuit							2
Number of long term gas contracts | contract							2
Damages sought | $							$ 86
Potential Positive Outcome of Litigation | WGL
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day			500,000	500,000	600,000	500,000		500,000

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Sales and revenues:
Sales and revenues	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 4,139,626	$ 3,655,574	$ 1,744,525
Operating expenses:
Impairment of unproved properties									549,437	159,598	162,935
Impairment of gathering systems and facilities									9,658	23,431	0
Depletion, depreciation, and amortization									972,465	824,610	809,873
General and administrative expense									240,344	251,196	239,324
Total operating expenses	1,092,279	1,071,728	1,022,107	881,607	834,667	719,932	666,646	694,236	4,067,721	2,915,481	2,720,326
Operating income (loss)	(46,630)	$ 4,804	$ (32,763)	$ 146,494	187,059	$ (72,052)	$ 123,743	$ 501,343	71,905	740,093	(975,801)
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Segment assets	15,519,464				15,261,490				15,519,464	15,261,490
Exploration and production
Sales and revenues:
Sales and revenues									3,565,300	3,406,203	1,334,656
Gathering and compression
Sales and revenues:
Sales and revenues									17,817	11,386	16,028
Water handling and treatment
Sales and revenues:
Sales and revenues									3,527	1,334	792
Marketing
Sales and revenues:
Sales and revenues									552,982	236,651	393,049
Operating segments
Sales and revenues:
Sales and revenues									4,139,626	3,655,574	1,744,525
Operating expenses:
Impairment of unproved properties									549,437
Impairment of gathering systems and facilities									9,658
Depletion, depreciation, and amortization									972,465	824,610	809,873
General and administrative expense									240,344	251,196	239,324
Other operating expenses									820,306	654,979	738,201
Total operating expenses									4,067,721	2,915,481	2,720,326
Operating income (loss)									71,905	740,093	(975,801)
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Segment assets	15,519,464				15,261,490				15,519,464	15,261,490	14,255,550
Capital expenditures for segment assets									2,210,586	2,216,753	2,495,429
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues									3,477,828	3,423,561	1,352,980
Operating expenses:
Impairment of unproved properties									549,437
Depletion, depreciation, and amortization									841,645	704,152	709,127
General and administrative expense									181,305	195,153	186,672
Other operating expenses									129,947	261,578	241,755
Total operating expenses									3,637,466	2,695,770	2,334,426
Operating income (loss)									(159,638)	727,791	(981,446)
Segment assets	12,986,945				13,074,027				12,986,945	13,074,027	12,512,973
Capital expenditures for segment assets									1,923,488	1,859,481	2,220,688
Operating segments | Gathering and compression
Sales and revenues:
Sales and revenues									521,149	396,466	307,944
Operating expenses:
Impairment of gathering systems and facilities									9,658
Depletion, depreciation, and amortization									84,057	87,268	70,847
General and administrative expense									46,609	40,337	39,832
Other operating expenses									258	23,535	(809)
Total operating expenses									189,580	190,287	137,968
Operating income (loss)									331,569	206,179	169,976
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Segment assets	2,465,858				2,253,163				2,465,858	2,253,163	1,750,354
Capital expenditures for segment assets									444,413	346,217	231,044
Operating segments | Water handling and treatment
Sales and revenues:
Sales and revenues									507,373	376,031	282,267
Operating expenses:
Depletion, depreciation, and amortization									46,763	33,190	29,899
General and administrative expense									15,020	18,475	14,331
Other operating expenses									(88,973)	17,061	14,401
Total operating expenses									236,066	258,428	195,017
Operating income (loss)									271,307	117,603	87,250
Segment assets	1,077,004				804,296				1,077,004	804,296	615,687
Capital expenditures for segment assets									97,699	194,502	188,188
Operating segments | Marketing
Sales and revenues:
Sales and revenues									552,982	236,651	393,049
Operating expenses:
Other operating expenses									686,055	366,281	499,343
Total operating expenses									686,055	366,281	499,343
Operating income (loss)									(133,073)	(129,630)	(106,294)
Segment assets	34,499				36,701				34,499	36,701	37,890
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues									(919,706)	(777,135)	(591,715)
Operating expenses:
General and administrative expense									(2,590)	(2,769)	(1,511)
Other operating expenses									93,019	(13,476)	(16,489)
Total operating expenses									(681,446)	(595,285)	(446,428)
Operating income (loss)									(238,260)	(181,850)	(145,287)
Segment assets	$ (1,044,842)				$ (906,697)				(1,044,842)	(906,697)	(661,354)
Capital expenditures for segment assets									(255,014)	(183,447)	(144,491)
Elimination of intersegment transaction | Exploration and production
Sales and revenues:
Sales and revenues									(87,472)	17,358	18,324
Elimination of intersegment transaction | Gathering and compression
Sales and revenues:
Sales and revenues									503,332	385,080	291,916
Elimination of intersegment transaction | Water handling and treatment
Sales and revenues:
Sales and revenues									503,846	374,697	281,475
Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									1,339,358	1,095,639	882,838
Gathering, compression, water handling and treatment | Operating segments
Operating expenses:
Cost of goods and services sold									1,339,358	1,095,639	882,838
Gathering, compression, water handling and treatment | Operating segments | Exploration and production
Operating expenses:
Cost of goods and services sold									1,792,898	1,441,129	1,146,221
Gathering, compression, water handling and treatment | Operating segments | Gathering and compression
Operating expenses:
Cost of goods and services sold									48,998	39,147	28,098
Gathering, compression, water handling and treatment | Operating segments | Water handling and treatment
Operating expenses:
Cost of goods and services sold									552
Gathering, compression, water handling and treatment | Elimination of intersegment transaction
Operating expenses:
Cost of goods and services sold									(503,090)	(384,637)	(291,481)
Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									136,153	89,057	50,090
Oil and Gas, Operation and Maintenance | Operating segments
Operating expenses:
Cost of goods and services sold									136,153	89,057	50,090
Oil and Gas, Operation and Maintenance | Operating segments | Exploration and production
Operating expenses:
Cost of goods and services sold									142,234	93,758	50,651
Oil and Gas, Operation and Maintenance | Operating segments | Water handling and treatment
Operating expenses:
Cost of goods and services sold									262,704	189,702	136,386
Oil and Gas, Operation and Maintenance | Elimination of intersegment transaction
Operating expenses:
Cost of goods and services sold									$ (268,785)	$ (194,403)	$ (136,947)

Condensed Consolidating Finan_3

Condensed Consolidating Financial Informations - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents		$ 28,441
Accounts receivable, net	$ 51,073	34,896
Accrued revenue	474,827	300,122
Derivative instruments	245,263	460,685
Other current assets	35,450	8,943
Total current assets	806,613	833,087
Unproved properties	1,767,600	2,266,673
Proved properties	12,705,672	11,096,462
Water handling and treatment systems	1,013,818	946,670
Gathering systems and facilities	2,470,708	2,050,490
Other property and equipment	65,842	57,429
Property and equipment, gross	18,023,640	16,417,724
Less accumulated depletion, depreciation, and amortization	(4,153,725)	(3,182,171)
Property and equipment, net	13,869,915	13,235,553
Derivative instruments	362,169	841,257
Investments in unconsolidated affiliates	433,642	303,302
Other assets, net	47,125	48,291
Total assets	15,519,464	15,261,490
Liabilities and Stockholders' Equity
Accounts payable	66,289	62,982
Accrued liabilities	465,070	443,225
Revenue distributions payable	310,827	209,617
Derivative instruments	532	28,476
Other current liabilities	10,822	17,796
Total current liabilities	853,540	762,096
Long-term debt	5,461,688	4,800,090
Deferred income tax liability	650,788	779,645
Derivative instruments		207
Other liabilities	65,971	43,316
Total liabilities	7,031,987	6,385,354
Common stock	3,086	3,164
Additional paid-in capital	6,485,174	6,570,952
Accumulated earnings	1,177,548	1,575,065
Total stockholders' equity	7,665,808	8,149,181
Noncontrolling interest in consolidated subsidiary	821,669	726,955
Total equity	8,487,477	8,876,136	$ 7,728,578	$ 7,286,678
Total liabilities and equity	15,519,464	15,261,490
Reportable legal entity | Parent (Antero)
Current assets:
Cash and cash equivalents		20,078
Accounts receivable, net	49,529	33,726
Intercompany receivables	383	6,459
Accrued revenue	474,827	300,122
Derivative instruments	245,263	460,685
Other current assets	13,937	8,273
Total current assets	783,939	829,343
Unproved properties	1,767,600	2,266,673
Proved properties	13,306,585	11,460,615
Gathering systems and facilities	17,825	17,929
Other property and equipment	65,770	57,429
Property and equipment, gross	15,157,780	13,802,646
Less accumulated depletion, depreciation, and amortization	(3,654,392)	(2,812,851)
Property and equipment, net	11,503,388	10,989,795
Derivative instruments	362,169	841,257
Investment in subsidiaries	(740,031)	(573,926)
Contingent acquisition consideration asset	114,995	208,014
Other assets, net	31,200	35,371
Total assets	12,055,660	12,329,854
Liabilities and Stockholders' Equity
Accounts payable	44,917	54,340
Intercompany payable	111,620	110,182
Accrued liabilities	392,949	338,819
Revenue distributions payable	310,827	209,617
Derivative instruments	532	28,476
Other current liabilities	4,621	17,587
Total current liabilities	865,466	759,021
Long-term debt	3,829,541	3,604,090
Deferred income tax liability	650,788	779,645
Derivative instruments		207
Other liabilities	57,890	42,906
Total liabilities	5,403,685	5,185,869
Common stock	3,086	3,164
Additional paid-in capital	5,471,341	5,565,756
Accumulated earnings	1,177,548	1,575,065
Total stockholders' equity	6,651,975	7,143,985
Total equity	6,651,975	7,143,985
Total liabilities and equity	12,055,660	12,329,854
Reportable legal entity | Non-Guarantor Subsidiaries (Antero Midstream)
Current assets:
Cash and cash equivalents		8,363
Accounts receivable, net	1,544	1,170
Intercompany receivables	115,378	110,182
Other current assets	21,513	670
Total current assets	138,435	120,385
Water handling and treatment systems	1,004,793	942,361
Gathering systems and facilities	2,452,883	2,032,561
Other property and equipment	72
Property and equipment, gross	3,457,748	2,974,922
Less accumulated depletion, depreciation, and amortization	(499,333)	(369,320)
Property and equipment, net	2,958,415	2,605,602
Investments in unconsolidated affiliates	433,642	303,302
Other assets, net	15,925	12,920
Total assets	3,546,417	3,042,209
Liabilities and Stockholders' Equity
Accounts payable	21,372	8,642
Intercompany payable	4,141	6,459
Accrued liabilities	72,121	106,006
Other current liabilities	2,052	209
Total current liabilities	99,686	121,316
Long-term debt	1,632,147	1,196,000
Contingent acquisition consideration	114,995	208,014
Other liabilities	8,081	410
Total liabilities	1,854,909	1,525,740
Partners' capital	1,691,508	1,516,469
Total stockholders' equity	1,691,508	1,516,469
Total equity	1,691,508	1,516,469
Total liabilities and equity	3,546,417	3,042,209
Eliminations
Current assets:
Intercompany receivables	(115,761)	(116,641)
Total current assets	(115,761)	(116,641)
Proved properties	(600,913)	(364,153)
Water handling and treatment systems	9,025	4,309
Property and equipment, gross	(591,888)	(359,844)
Property and equipment, net	(591,888)	(359,844)
Investment in subsidiaries	740,031	573,926
Contingent acquisition consideration asset	(114,995)	(208,014)
Total assets	(82,613)	(110,573)
Liabilities and Stockholders' Equity
Intercompany payable	(115,761)	(116,641)
Accrued liabilities		(1,600)
Other current liabilities	4,149
Total current liabilities	(111,612)	(118,241)
Contingent acquisition consideration	(114,995)	(208,014)
Total liabilities	(226,607)	(326,255)
Partners' capital	(1,691,508)	(1,516,469)
Additional paid-in capital	1,013,833	1,005,196
Total stockholders' equity	(677,675)	(511,273)
Noncontrolling interest in consolidated subsidiary	821,669	726,955
Total equity	143,994	215,682
Total liabilities and equity	$ (82,613)	$ (110,573)

Condensed Consolidating Finan_4

Condensed Consolidating Financial Information - Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenue:
Revenues from contracts with customers									$ 4,133,139	$ 3,018,685	$ 2,161,071
Commodity derivative fair value gains (losses)									(87,594)	658,283	(514,181)
Marketing derivative gains									94,081	(21,394)
Gain on sale of assets											97,635
Total revenue and other	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	4,139,626	3,655,574	1,744,525
Operating expenses:
Production and ad valorem taxes									126,474	94,521	66,588
Impairment of unproved properties									549,437	159,598	162,935
Impairment of gathering systems and facilities									9,658	23,431	0
Depletion, depreciation, and amortization									972,465	824,610	809,873
Accretion of asset retirement obligations									2,819	2,610	2,473
General and administrative									240,344	251,196	239,324
Total operating expenses	1,092,279	1,071,728	1,022,107	881,607	834,667	719,932	666,646	694,236	4,067,721	2,915,481	2,720,326
Operating income (loss)	(46,630)	4,804	(32,763)	146,494	187,059	(72,052)	123,743	501,343	71,905	740,093	(975,801)
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Interest									(286,743)	(268,701)	(253,552)
Loss on early extinguishment of debt										(1,500)	(16,956)
Total other expenses									(246,463)	(250,007)	(270,023)
Income (loss) before income taxes									(174,558)	490,086	(1,245,824)
Provision for income tax benefit									128,857	295,051	496,376
Net income (loss) and comprehensive income (loss) including noncontrolling interest	18,736	(77,972)	(67,275)	80,810	529,614	(90,000)	39,965	305,558	(45,701)	785,137	(749,448)
Net income and comprehensive income attributable to noncontrolling interest	140,282	76,447	69,110	65,977	42,745	45,063	45,097	37,162	351,816	170,067	99,368
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	(397,517)	615,070	(848,816)
Natural gas sales
Revenue:
Revenues from contracts with customers									2,287,939	1,769,284	1,260,750
Natural gas liquids sales
Revenue:
Revenues from contracts with customers									1,177,777	870,441	432,992
Oil sales
Revenue:
Revenues from contracts with customers									187,178	108,195	61,319
Gathering, compression, water handling and treatment
Revenue:
Revenues from contracts with customers									21,344	12,720	12,961
Operating expenses:
Cost of goods and services sold									1,339,358	1,095,639	882,838
Marketing
Revenue:
Revenues from contracts with customers									458,901	258,045	393,049
Operating expenses:
Cost of goods and services sold									686,055	366,281	499,343
Exploration
Operating expenses:
Cost of goods and services sold									4,958	8,538	6,862
Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									136,153	89,057	50,090
Reportable legal entity | Parent (Antero)
Revenue:
Commodity derivative fair value gains (losses)									(87,594)	658,283	(514,181)
Marketing derivative gains									94,081	(21,394)
Gain on sale of assets											93,776
Total revenue and other									4,031,065	3,660,212	1,746,029
Operating expenses:
Production and ad valorem taxes									122,305	90,832	69,485
Impairment of unproved properties									549,437	159,598	162,935
Impairment of gathering systems and facilities									4,470
Depletion, depreciation, and amortization									842,452	705,048	710,012
Accretion of asset retirement obligations									2,684	2,610	2,473
General and administrative									181,305	195,153	186,672
Change in fair value of contingent acquisition consideration									93,019	(13,476)	(16,489)
Total operating expenses									4,328,798	3,062,947	2,834,654
Operating income (loss)									(297,733)	597,265	(1,088,625)
Interest									(224,977)	(232,331)	(232,455)
Loss on early extinguishment of debt										(1,205)	(16,956)
Equity in earnings (loss) of consolidated subsidiaries									(3,664)	(43,710)	(7,156)
Total other expenses									(228,641)	(277,246)	(256,567)
Income (loss) before income taxes									(526,374)	320,019	(1,345,192)
Provision for income tax benefit									128,857	295,051	496,376
Net income (loss) and comprehensive income (loss) including noncontrolling interest									(397,517)	615,070	(848,816)
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(397,517)	615,070	(848,816)
Reportable legal entity | Parent (Antero) | Natural gas sales
Revenue:
Revenues from contracts with customers									2,287,939	1,769,975	1,260,750
Reportable legal entity | Parent (Antero) | Natural gas liquids sales
Revenue:
Revenues from contracts with customers									1,177,777	870,441	432,992
Reportable legal entity | Parent (Antero) | Oil sales
Revenue:
Revenues from contracts with customers									187,178	108,195	61,319
Reportable legal entity | Parent (Antero) | Gathering, compression, water handling and treatment
Operating expenses:
Cost of goods and services sold									1,792,898	1,441,129	1,146,221
Reportable legal entity | Parent (Antero) | Marketing
Revenue:
Revenues from contracts with customers									458,901	258,045	393,049
Operating expenses:
Cost of goods and services sold									686,055	366,281	499,343
Reportable legal entity | Parent (Antero) | Exploration
Operating expenses:
Cost of goods and services sold									4,958	8,538	6,862
Reportable legal entity | Parent (Antero) | Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									142,234	93,758	50,651
Reportable legal entity | Parent (Antero) | Other
Revenue:
Revenues from contracts with customers									(87,217)	16,667	18,324
Reportable legal entity | Non-Guarantor Subsidiaries (Antero Midstream)
Revenue:
Gain on sale of assets									583		3,859
Total revenue and other									1,028,522	772,497	590,211
Operating expenses:
Production and ad valorem taxes									4,169	3,689	(2,897)
Impairment of gathering systems and facilities									5,771	23,431
Depletion, depreciation, and amortization									130,013	119,562	99,861
Accretion of asset retirement obligations									135
General and administrative									61,629	58,812	54,163
Change in fair value of contingent acquisition consideration									(93,019)	13,476	16,489
Total operating expenses									420,952	447,819	332,100
Operating income (loss)									607,570	324,678	258,111
Equity in earnings of unconsolidated affiliates									40,280	20,194	485
Interest									(61,906)	(37,262)	(21,893)
Loss on early extinguishment of debt										(295)
Total other expenses									(21,626)	(17,363)	(21,408)
Income (loss) before income taxes									585,944	307,315	236,703
Net income (loss) and comprehensive income (loss) including noncontrolling interest									585,944	307,315	236,703
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									585,944	307,315	236,703
Reportable legal entity | Non-Guarantor Subsidiaries (Antero Midstream) | Gathering, compression, water handling and treatment
Revenue:
Revenues from contracts with customers									1,027,939	772,497	586,352
Operating expenses:
Cost of goods and services sold									49,550	39,147	28,097
Reportable legal entity | Non-Guarantor Subsidiaries (Antero Midstream) | Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									262,704	189,702	136,387
Eliminations
Revenue:
Gain on sale of assets									(583)
Total revenue and other									(919,961)	(777,135)	(591,715)
Operating expenses:
Impairment of gathering systems and facilities									(583)
General and administrative									(2,590)	(2,769)	(1,511)
Change in fair value of contingent acquisition consideration									93,019	(13,476)	(16,489)
Total operating expenses									(682,029)	(595,285)	(446,428)
Operating income (loss)									(237,932)	(181,850)	(145,287)
Interest									140	892	796
Equity in earnings (loss) of consolidated subsidiaries									3,664	43,710	7,156
Total other expenses									3,804	44,602	7,952
Income (loss) before income taxes									(234,128)	(137,248)	(137,335)
Net income (loss) and comprehensive income (loss) including noncontrolling interest									(234,128)	(137,248)	(137,335)
Net income and comprehensive income attributable to noncontrolling interest									351,816	170,067	99,368
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(585,944)	(307,315)	(236,703)
Eliminations | Natural gas sales
Revenue:
Revenues from contracts with customers										(691)
Eliminations | Gathering, compression, water handling and treatment
Revenue:
Revenues from contracts with customers									(1,006,595)	(759,777)	(573,391)
Operating expenses:
Cost of goods and services sold									(503,090)	(384,637)	(291,480)
Eliminations | Oil and Gas, Operation and Maintenance
Operating expenses:
Cost of goods and services sold									(268,785)	(194,403)	(136,948)
Eliminations | Other
Revenue:
Revenues from contracts with customers									$ 87,217	$ (16,667)	$ (18,324)

Condensed Consolidating Finan_5

Condensed Consolidating Financial Information - Cash Flows (Details) - USD ($) $ in Thousands	Sep. 11, 2017	Feb. 06, 2017	Mar. 30, 2016	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests				$ 18,736	$ (77,972)	$ (67,275)	$ 80,810	$ 529,614	$ (90,000)	$ 39,965	$ 305,558	$ (45,701)	$ 785,137	$ (749,448)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion												975,284	827,220	812,346
Impairment of unproved properties												549,437	159,598	162,935
Impairment of gathering systems and facilities												9,658	23,431	0
Commodity derivative fair value (gains) losses												87,594	(658,283)	514,181
Gains on settled commodity derivatives												243,112	213,940	1,003,083
Premium paid on derivative contracts												(13,318)
Proceeds from derivative monetizations												370,365	749,906
Marketing derivative fair value (gains) losses												(94,081)	21,394
Gains on settled marketing derivatives												72,687
Deferred income tax expense (benefit)												(128,857)	(295,126)	(485,392)
Gain on sale of assets														(97,635)
Equity-based compensation expense												70,414	103,445	102,421
Loss on early extinguishment of debt													1,500	16,956
Equity in earnings of unconsolidated affiliates												(40,280)	(20,194)	(485)
Distributions from unconsolidated affiliates												46,415	20,195	7,702
Other												4,681	(1,907)	(12,488)
Changes in current assets and liabilities												(25,423)	76,035	(32,920)
Net cash provided by operating activities												2,081,987	2,006,291	1,241,256
Cash flows used in investing activities:
Additions to proved properties													(175,650)	(134,113)
Additions to unproved properties												(172,387)	(204,272)	(611,631)
Drilling and completion costs												(1,488,573)	(1,281,985)	(1,327,759)
Additions to water handling and treatment systems												(97,699)	(194,502)	(188,188)
Additions to gathering systems and facilities												(444,413)	(346,217)	(231,044)
Additions to other property and equipment												(7,514)	(14,127)	(2,694)
Investments in unconsolidated affiliates												(136,475)	(235,004)	(75,516)
Change in other assets												(3,663)	(12,029)	3,977
Proceeds from asset sales													2,156	171,830
Other													2,156
Net cash used in investing activities												(2,350,724)	(2,461,630)	(2,395,138)
Cash flows provided by (used in) financing activities:
Issuance of common stock														1,012,431
Issuance of common units by Antero Midstream													248,956	65,395
Repurchases of common stock												(129,084)
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation													311,100	178,000
Issuance of senior notes														1,250,000
Repayment of senior notes														(525,000)
Borrowings (repayments) on bank credit facilities, net												660,379	90,000	(677,000)
Make-whole premium on debt extinguished														(15,750)
Payments of deferred financing costs												(2,169)	(16,377)	(18,759)
Distributions to noncontrolling interest in consolidated subsidiary												(267,271)	(152,352)	(75,082)
Employee tax withholding for settlement of equity compensation awards												(17,020)	(24,174)	(26,895)
Other												(4,539)	(4,983)	(5,321)
Net cash provided by financing activities												240,296	452,170	1,162,019
Net increase (decrease) in cash and cash equivalents												(28,441)	(3,169)	8,137
Cash and cash equivalents, beginning of period							28,441				31,610	28,441	31,610	23,473
Cash and cash equivalents, end of period								28,441					28,441	31,610
Antero Midstream Partners LP
Cash flows provided by (used in) financing activities:
Issuance of common stock		$ 223,000
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation	$ 311,000		$ 178,000
Reportable legal entity | Parent (Antero)
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests												(397,517)	615,070	(848,816)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion												845,136	707,658	712,485
Change in fair value of contingent acquisition consideration												93,019	(13,476)	(16,489)
Impairment of unproved properties												549,437	159,598	162,935
Impairment of gathering systems and facilities												4,470
Commodity derivative fair value (gains) losses												87,594	(658,283)	514,181
Gains on settled commodity derivatives												243,112	213,940	1,003,083
Premium paid on derivative contracts												(13,318)
Proceeds from derivative monetizations												370,365	749,906
Marketing derivative fair value (gains) losses												(94,081)	21,394
Gains on settled marketing derivatives												72,687
Deferred income tax expense (benefit)												(128,857)	(295,126)	(485,392)
Gain on sale of assets														(93,776)
Equity-based compensation expense												49,341	76,162	76,372
Loss on early extinguishment of debt													1,205	16,956
Equity in earnings (loss) of consolidated subsidiaries												3,664	43,710	7,156
Other												4,681	(4,500)	(14,302)
Distributions from subsidiaries												159,181	131,598	107,364
Changes in current assets and liabilities												(26,059)	87,466	(36,519)
Net cash provided by operating activities												1,822,855	1,836,322	1,105,238
Cash flows used in investing activities:
Additions to proved properties													(175,650)	(134,113)
Additions to unproved properties												(172,387)	(204,272)	(611,631)
Drilling and completion costs												(1,743,587)	(1,455,554)	(1,462,984)
Additions to water handling and treatment systems														32
Additions to gathering systems and facilities												103		(2,944)
Additions to other property and equipment												(7,441)	(14,127)	(2,694)
Change in other assets												(72)	(8,594)	304
Proceeds from asset sales														161,830
Other													2,156
Net cash used in investing activities												(1,923,384)	(1,856,041)	(2,052,200)
Cash flows provided by (used in) financing activities:
Issuance of common stock														1,012,431
Repurchases of common stock												(129,084)
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation													311,100	178,000
Issuance of senior notes														600,000
Repayment of senior notes														(525,000)
Borrowings (repayments) on bank credit facilities, net												225,379	(255,000)	(267,000)
Make-whole premium on debt extinguished														(15,750)
Payments of deferred financing costs													(10,857)	(8,324)
Employee tax withholding for settlement of equity compensation awards												(11,491)	(18,229)	(21,260)
Other												(4,353)	(4,785)	(5,157)
Net cash provided by financing activities												80,451	22,229	947,940
Net increase (decrease) in cash and cash equivalents												(20,078)	2,510	978
Cash and cash equivalents, beginning of period							20,078				17,568	20,078	17,568	16,590
Cash and cash equivalents, end of period								20,078					20,078	17,568
Reportable legal entity | Non-Guarantor Subsidiaries (Antero Midstream)
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests												585,944	307,315	236,703
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, amortization, and accretion												130,148	119,562	99,861
Change in fair value of contingent acquisition consideration												(93,019)	13,476	16,489
Impairment of gathering systems and facilities												5,771	23,431
Gain on sale of assets												(583)		(3,859)
Equity-based compensation expense												21,073	27,283	26,049
Loss on early extinguishment of debt													295
Equity in earnings of unconsolidated affiliates												(40,280)	(20,194)	(485)
Distributions from unconsolidated affiliates												46,415	20,195	7,702
Other												2,879	2,593	1,814
Changes in current assets and liabilities												(788)	(18,160)	(5,667)
Net cash provided by operating activities												657,560	475,796	378,607
Cash flows used in investing activities:
Additions to water handling and treatment systems												(88,674)	(195,162)	(188,220)
Additions to gathering systems and facilities												(446,270)	(346,217)	(228,100)
Investments in unconsolidated affiliates												(136,475)	(235,004)	(75,516)
Change in other assets												(3,591)	(3,435)	3,673
Change in other liabilities												2,273
Proceeds from asset sales														10,000
Other												6,150
Net cash used in investing activities												(666,587)	(779,818)	(478,163)
Cash flows provided by (used in) financing activities:
Issuance of common units by Antero Midstream													248,956	65,395
Issuance of senior notes														650,000
Borrowings (repayments) on bank credit facilities, net												435,000	345,000	(410,000)
Payments of deferred financing costs												(2,169)	(5,520)	(10,435)
Distributions to noncontrolling interest in consolidated subsidiary												(426,452)	(283,950)	(182,446)
Employee tax withholding for settlement of equity compensation awards												(5,529)	(5,945)	(5,635)
Other												(186)	(198)	(164)
Net cash provided by financing activities												664	298,343	106,715
Net increase (decrease) in cash and cash equivalents												(8,363)	(5,679)	7,159
Cash and cash equivalents, beginning of period							$ 8,363				$ 14,042	8,363	14,042	6,883
Cash and cash equivalents, end of period								$ 8,363					8,363	14,042
Eliminations
Cash flows provided by (used in) operating activities:
Net income (loss) including noncontrolling interests												(234,128)	(137,248)	(137,335)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Change in fair value of contingent acquisition consideration												93,019	(13,476)	(16,489)
Impairment of gathering systems and facilities												(583)
Gain on sale of assets												583
Equity in earnings (loss) of consolidated subsidiaries												(3,664)	(43,710)	(7,156)
Other												(2,879)
Distributions from subsidiaries												(159,181)	(131,598)	(107,364)
Changes in current assets and liabilities												1,424	6,729	9,266
Net cash provided by operating activities												(398,428)	(305,827)	(242,589)
Cash flows used in investing activities:
Drilling and completion costs												255,014	173,569	135,225
Additions to water handling and treatment systems												(9,025)	660
Additions to gathering systems and facilities												1,754
Additions to other property and equipment												(73)
Change in other liabilities												(2,273)
Other												(6,150)
Net cash used in investing activities												239,247	174,229	135,225
Cash flows provided by (used in) financing activities:
Distributions to noncontrolling interest in consolidated subsidiary												159,181	131,598	107,364
Net cash provided by financing activities												$ 159,181	$ 131,598	$ 107,364

Quarterly Financial Informati_3

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Abstract]
Total revenue	$ 1,045,649	$ 1,076,532	$ 989,344	$ 1,028,101	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 4,139,626	$ 3,655,574	$ 1,744,525
Total operating expenses	1,092,279	1,071,728	1,022,107	881,607	834,667	719,932	666,646	694,236	4,067,721	2,915,481	2,720,326
Operating income (loss)	(46,630)	4,804	(32,763)	146,494	187,059	(72,052)	123,743	501,343	71,905	740,093	(975,801)
Net income (loss) including noncontrolling interests	18,736	(77,972)	(67,275)	80,810	529,614	(90,000)	39,965	305,558	(45,701)	785,137	(749,448)
Net Income (Loss) Attributable to Noncontrolling Interest	140,282	76,447	69,110	65,977	42,745	45,063	45,097	37,162	351,816	170,067	99,368
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ (121,546)	$ (154,419)	$ (136,385)	$ 14,833	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	$ (397,517)	$ 615,070	$ (848,816)
Earnings (loss) per common share - basic:
Earnings (loss) per common share - basic	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.26)	$ 1.95	$ (2.88)
Earnings (loss) per share - diluted:
Earnings (loss) per common share - diluted	$ (0.39)	$ (0.49)	$ (0.43)	$ 0.05	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.26)	$ 1.94	$ (2.88)

Supplemental Information on O_3

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 12,705,672	$ 11,096,462
Unproved properties	1,767,600	2,266,673
Total	14,473,272	13,363,135
Accumulated depletion and depreciation	(3,615,680)	(2,783,832)
Net capitalized costs	10,857,592	10,579,303
Costs Incurred in Certain Oil and Gas Activities
Proved property		175,650	$ 134,113
Unproved property	172,387	204,272	611,631
Development costs	1,164,800	897,287	1,000,903
Exploration costs	323,773	384,698	326,856
Total costs incurred	1,660,960	1,661,907	2,073,503
Results of Operations for Oil and Gas Producing Activities
Revenues	3,652,894	2,747,920	1,755,061
Operating expenses:
Production expenses	1,601,985	1,279,217	999,516
Exploration expenses	4,958	8,538	6,862
Depletion and depreciation	832,326	694,332	700,274
Impairment of unproved properties	549,437	159,598	162,935
Results of operations before income tax expense (benefit)	664,188	606,235	(114,526)
Income tax expense	(156,350)	(228,096)	43,334
Results of operations	$ 507,838	$ 378,139	$ (71,192)

Supplemental Information on O_4

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details) Bcfe in Thousands	12 Months Ended
	Dec. 31, 2018BcfeMMcfeBcfMMBbls	Dec. 31, 2017MMcfeBcfMMBbls	Dec. 31, 2016MMcfeBcfMMBbls
Proved developed and undeveloped reserves:
Balance at the beginning of the period | MMcfe	17,261,000	15,386,000	13,215,000
Revisions | MMcfe	(1,042,000)	176,000	(404,000)
Extensions, discoveries and other additions | MMcfe	2,781,000	2,148,000	2,637,000
Increase (decrease) in proved reserves resulting from price revisions	18		(47,000)
Production | MMcfe	(989,000)	(822,000)	(676,000)
Purchase of reserves | MMcfe		373,000	624,000
Sales of reserves in place | MMcfe			(10,000)
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MMcfe	18,011,000	17,261,000	15,386,000
Oil and Gas Reserves
Proved developed reserves | MMcfe	10,389	8,488	6,914
Proved undeveloped reserves | MMcfe	7,622	8,773	8,472
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	11,098	9,414	9,533
Revisions | Bcf	(1,087)	342	(2,069)
Extensions, discoveries and other additions | Bcf	2,125	1,644	1,990
Production | Bcf	(711)	(591)	(505)
Purchase of reserves | Bcf		289	475
Sales of reserves in place | Bcf			(10)
Balance at the end of the period | Bcf	11,425	11,098	9,414
Oil and Gas Reserves
Proved developed reserves | Bcf	6,669	5,587	4,426
Proved undeveloped reserves | Bcf	4,756	5,511	4,988
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	989	957	587
Revisions	8	(22)	275
Extensions, discoveries and other additions	98	77	99
Production	(43)	(36)	(27)
Purchase of reserves		13	23
Balance at the end of the period	1,052	989	957
Oil and Gas Reserves
Proved developed reserves	600	467	401
Proved undeveloped reserves	452	522	556
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	38	38	26
Revisions	(1)	(6)	3
Extensions, discoveries and other additions	12	7	9
Production	(3)	(2)	(2)
Purchase of reserves		1	2
Balance at the end of the period	46	38	38
Oil and Gas Reserves
Proved developed reserves	20	16	13
Proved undeveloped reserves	26	22	25

Supplemental Information on O_5

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Discounted future cash flows (Detail) MMcfe in Thousands, Bcfe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)Bcfe	Dec. 31, 2017USD ($)Bcfe	Dec. 31, 2016USD ($)MMcfe	Dec. 31, 2015USD ($)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Increase in proved reserves due to ethane recovery		345	1,359
Increase (decrease) in proved reserves due to development plan revisions | Bcfe	742	188
Increase in proved reserves due to additions to development plan | Bcfe	1,722	2,092
Decrease in proved reserves due to reclassifications related to five-year rule	2,464	2,280	(2,478)
Increase (decrease) in proved reserves resulting from price revisions	18		(47)
Increase (decrease) in proved reserves due to performance revisions	115	132	762
Future cash inflows computation period	12 months
Percentage of net cash inflows that were discounted at annual rate	10.00%
Annual net cash inflows
Period of unweighted first day of the month average prices used to compute future cash inflows	12 months
Future cash inflows	$ 64,199	$ 55,824	$ 36,800
Future production costs	(30,007)	(26,375)	(21,275)
Future development costs	(3,453)	(3,312)	(3,902)
Future net cash flows before income tax	30,739	26,137	11,623
Future income tax expense	(5,505)	(4,104)	(1,042)
Future net cash flows	25,234	22,033	10,581
10% annual discount for estimated timing of cash flows	(14,756)	(13,406)	(7,294)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 10,478	$ 8,627	$ 3,287	$ 3,233

Supplemental Information on O_6

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes in standardized measure of discounted future net cash flow (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)$ / MMcfe	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)$ / MMcfe	Dec. 31, 2016USD ($)$ / MMcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe	3.56		3.23	2.39
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs		$ (2,051)	$ (1,469)	$ (756)
Net changes in prices and production costs		707	3,918	(1,540)
Development costs incurred during the period		755	627	733
Net changes in future development costs		37	229	212
Extensions, discoveries and other additions		1,925	1,448	673
Acquisitions			258	66
Divestitures				(7)
Revisions of previous quantity estimates		(53)	734	461
Accretion of discount		1,018	368	363
Net change in income taxes		(563)	(1,159)	12
Other changes		76	386	(163)
Net increase (decrease)		1,851	5,340	54
Beginning of period	$ 10,478	8,627	3,287	3,233
End of period		$ 10,478	$ 8,627	$ 3,287