Antero Resources (AR) 10-K 13 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 08, 2018	Jun. 30, 2017
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, 2017
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			$ 5
Entity Common Stock, Shares Outstanding		316,524,110
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,017

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 28,441	$ 31,610	$ 23,473	$ 245,979
Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and December 31, 2017, respectively	34,896	29,682
Accrued revenue	300,122	261,960
Derivative instruments	460,685	73,022
Other current assets	8,943	6,313
Total current assets	833,087	402,587
Natural gas properties, at cost (successful efforts method):
Unproved properties	2,266,673	2,331,173
Proved properties	11,096,462	9,549,671
Water handling and treatment systems	946,670	744,682
Gathering systems and facilities	2,050,490	1,723,768
Other property and equipment	57,429	41,231
Property and equipment, gross	16,417,724	14,390,525
Less accumulated depletion, depreciation, and amortization	(3,182,171)	(2,363,778)
Property and equipment, net	13,235,553	12,026,747
Derivative instruments	841,257	1,731,063
Investments in unconsolidated affiliates	303,302	68,299
Other assets	48,291	26,854
Total assets	15,261,490	14,255,550
Current liabilities:
Accounts payable	62,982	38,627
Accrued liabilities	443,225	393,803
Revenue distributions payable	209,617	163,989
Derivative instruments	28,476	203,635
Other current liabilities	17,796	17,334
Total current liabilities	762,096	817,388
Long-term liabilities:
Long-term debt	4,800,090	4,703,973
Deferred income tax liability	779,645	950,217
Derivative instruments	207	234
Other liabilities	43,316	55,160
Total liabilities	6,385,354	6,526,972
Equity:
Common stock, $0.01 par value; authorized - 1,000,000 shares; 314,877 shares and 316,379 shares issued and outstanding at December 31, 2016 and 2017, respectively	3,164	3,149
Additional paid-in capital	6,570,952	5,299,481
Accumulated earnings	1,575,065	959,995
Total stockholders' equity	8,149,181	6,262,625
Noncontrolling interest in consolidated subsidiary	726,955	1,465,953
Total equity	8,876,136	7,728,578	$ 7,286,678	$ 5,473,830
Total liabilities and equity	$ 15,261,490	$ 14,255,550

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets
Allowance for doubtful accounts	$ 1,320	$ 1,195
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	316,379,000	314,877,000
Common stock, shares outstanding	316,379,000	314,877,000
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

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended			24 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
Revenue:
Natural gas sales									$ 1,769,284	$ 1,260,750	$ 1,039,892
Natural gas liquids sales									870,441	432,992	264,483
Oil sales									108,195	61,319	70,753
Gathering, processing, and water handling and treatment									12,720	12,961	22,000
Marketing									258,045	393,049	176,229
Commodity derivative fair value gains (losses)									636,889	(514,181)	2,381,501
Gain on sale of assets										97,635
Total revenue	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 156,216	$ 1,116,503	$ (249,198)	$ 721,004	3,655,574	1,744,525	3,954,858
Operating expenses:
Lease operating									89,057	50,090	36,011
Gathering, compression, processing, and transportation									1,095,639	882,838	659,361
Production and ad valorem taxes									94,521	66,588	78,325
Marketing									366,281	499,343	299,062
Exploration									8,538	6,862	3,846
Impairment of unproved properties									159,598	162,935	104,321
Impairment of gathering systems and facilities									23,431			$ 0
Depletion, depreciation, and amortization									824,610	809,873	709,763
Accretion of asset retirement obligations									2,610	2,473	1,655
General and administrative (including equity-based compensation expense of $97,877, $102,421, and $103,445 in 2015, 2016, and 2017, respectively)									251,196	239,324	233,697
Contract termination and rig stacking									0	0	38,531
Total operating expenses	834,667	719,932	666,646	694,236	788,225	649,171	640,675	642,255	2,915,481	2,720,326	2,164,572
Operating income (loss)	187,059	(72,052)	123,743	501,343	(632,009)	467,332	(889,873)	78,749	740,093	(975,801)	1,790,286
Other income (expenses):
Equity in earnings of unconsolidated affiliate									20,194	485
Interest									(268,701)	(253,552)	(234,400)
Loss on early extinguishment of debt									(1,500)	(16,956)
Total other expenses									(250,007)	(270,023)	(234,400)
Income (loss) before income taxes									490,086	(1,245,824)	1,555,886
Provision for income tax (expense) benefit									295,051	496,376	(575,890)
Net income (loss) and comprehensive income (loss) including noncontrolling interest	529,614	(90,000)	39,965	305,558	(452,804)	268,196	(575,490)	10,650	785,137	(749,448)	979,996
Net income and comprehensive income attributable to noncontrolling interest	42,745	45,063	45,097	37,162	32,968	29,941	20,754	15,705	170,067	99,368	38,632
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	$ (485,772)	$ 238,255	$ (596,244)	$ (5,055)	$ 615,070	$ (848,816)	$ 941,364
Earnings (loss) per common share:
Continuing operations (in dollars per share)									$ 1.95	$ (2.88)	$ 3.43
Earnings (loss) per common share - basic (in dollars per share)	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.55)	$ 0.78	$ (2.12)	$ (0.02)
Earnings (loss) per common share assuming dilution:
Continuing operations (in dollars per share)									$ 1.94	$ (2.88)	$ 3.43
Earnings (loss) per common share—assuming dilution (in dollars per share)	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.55)	$ 0.77	$ (2.12)	$ (0.02)
Weighted average number of shares outstanding
Basic (in shares)									315,426	294,945	274,123
Diluted (in shares)									316,283	294,945	274,143

Consolidated Statements of Ope5

Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Statements of Operations and Comprehensive Income (Loss)
Equity-based compensation expense	$ 103,445	$ 102,421	$ 97,877

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock	Additional paid-in capital	Accumulated earnings	Noncontrolling Interests	Total
Balances at Dec. 31, 2014	$ 2,621	$ 3,513,725	$ 867,447	$ 1,090,037	$ 5,473,830
Shares Issued, Beginning Balance at Dec. 31, 2014	262,072
Increase (Decrease) in Stockholders' Equity
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs	$ 147	537,685			537,832
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs (in shares)	14,700
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings	$ 2	(4,627)			(4,625)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares)	264
Issuance of common units by subsidiary - Antero Midstream Partners LP				240,703	240,703
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings		(17,272)		12,466	(4,806)
Equity-based compensation		93,300		4,577	97,877
Net income (loss) and comprehensive income (loss) including noncontrolling interest			941,364	38,632	979,996
Distributions to non-controlling interests				(34,129)	(34,129)
Balances at Dec. 31, 2015	$ 2,770	4,122,811	1,808,811	1,352,286	7,286,678
Shares Issued, Ending Balance 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)
Balances at Dec. 31, 2016	$ 3,149	5,299,481	959,995	1,465,953	7,728,578
Shares Issued, Ending Balance 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)
Balances at Dec. 31, 2017	$ 3,164	$ 6,570,952	$ 1,575,065	$ 726,955	$ 8,876,136
Shares Issued, Ending Balance at Dec. 31, 2017	316,379

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss) and comprehensive income (loss)	$ 785,137	$ (749,448)	$ 979,996
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	827,220	812,346	711,418
Impairment of unproved properties	159,598	162,935	104,321
Impairment of gathering systems and facilities	23,431
Derivative fair value (gains) losses	(636,889)	514,181	(2,381,501)
Gains on settled derivatives	213,940	1,003,083	856,572
Proceeds from derivative monetizations	749,906
Deferred income tax expense (benefit)	(295,126)	(485,392)	575,890
Equity-based compensation expense	103,445	102,421	97,877
Income Loss From Equity Method Investments	(20,194)	(485)
Distributions from unconsolidated affiliates	20,195	7,702
Gain on sale of assets		(97,635)
Loss on early extinguishment of debt	1,500	16,956
Other	(1,907)	(12,488)	31,741
Changes in current assets and liabilities:
Accounts receivable	(5,214)	39,857	(3,201)
Accrued revenue	(38,162)	(133,718)	63,316
Other current assets	(2,755)	1,774	(2,221)
Accounts payable	9,462	7,365	(8,536)
Accrued liabilities	64,862	18,853	36,377
Revenue distributions payable	45,628	34,040	(52,403)
Other current liabilities	2,214	(1,091)	6,166
Net cash provided by operating activities	2,006,291	1,241,256	1,015,812
Cash flows used in investing activities:
Additions to proved properties	(175,650)	(134,113)
Additions to unproved properties	(204,272)	(611,631)	(198,694)
Drilling and completion costs	(1,281,985)	(1,327,759)	(1,651,282)
Additions to water handling and treatment systems	(194,502)	(188,188)	(131,051)
Additions to gathering systems and facilities	(346,217)	(231,044)	(360,287)
Additions to other property and equipment	(14,127)	(2,694)	(6,595)
Investments in unconsolidated affiliates	(235,004)	(75,516)
Change in other assets	(12,029)	3,977	9,750
Other	2,156	171,830	40,000
Net cash used in investing activities	(2,461,630)	(2,395,138)	(2,298,159)
Cash flows from financing activities:
Issuance of common stock		1,012,431	537,832
Issuance of common units by Antero Midstream Partners LP	248,956	65,395	240,703
Proceeds From Sale Of Interest In Partnership Unit	311,100	178,000
Issuance of senior notes		1,250,000	750,000
Repayment of senior notes		(525,000)
Borrowings (repayments) on bank credit facility, net	90,000	(677,000)	(403,000)
Make-whole premium on debt extinguished		(15,750)
Payments of deferred financing costs	(16,377)	(18,759)	(17,293)
Distributions to noncontrolling interest in consolidated subsidiary	(152,352)	(75,082)	(34,129)
Employee tax withholding for settlement of equity compensation awards	(24,174)	(26,895)	(9,431)
Other	(4,983)	(5,321)	(4,841)
Net cash provided by financing activities	452,170	1,162,019	1,059,841
Net increase in cash and cash equivalents	(3,169)	8,137	(222,506)
Cash and cash equivalents, beginning of period	31,610	23,473	245,979
Cash and cash equivalents, end of period	28,441	31,610	23,473
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	263,919	239,369	219,945
Supplemental disclosure of noncash investing activities:
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$ 547	$ 152,093	$ 169,783

Business and Organization

Business and Organization	12 Months Ended
	Dec. 31, 2017
Business and Organization
Business and Organization	(1) 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” or “the Partnership”), 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, 2017
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, 2016 and 2017, and the results of its operations and its cash flows for the years ended December 31, 2015, 2016, and 2017. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical 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 Resources Corporation, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. We have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are included 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 or right to receive benefits of 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 52.9% of the outstanding limited partner interests in Antero Midstream at December 31, 2017. · Antero Midstream GP LP (“AMGP”) indirectly controls the general partnership interest in Antero Midstream and directly controls Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights in Antero Midstream. However, AMGP has not provided, and is not expected to provide, financial support to Antero Midstream. Antero does not control AMGP and does not have any investment in AMGP. · Antero’s officers and management group also act as management of Antero Midstream and AMGP. · Antero and Antero Midstream have contracts with 20-year initial terms and automatic renewal provisions, whereby Antero has dedicated the rights for gathering and compression, and water delivery and handling, services to Antero Midstream on a fixed-fee basis. Such dedications cover a substantial portion of Antero’s current acreage and future acquired acreage, in each case, except for acreage that was already dedicated to other parties prior to entering into the service contracts or that was acquired subject to a pre-existing dedication. The contracts call for Antero to present, in advance, its drilling and completion plans in order for Antero Midstream to develop gathering and compression and water delivery and handling assets to service Antero’s operations. Consequently, the drilling and completion capital investment decisions made by Antero control the development and operation of all of Antero Midstream’s assets. Because of these contractual obligations and the capital requirements related to these obligations, Antero Midstream has and, for the foreseeable future, will devote substantially all of its resources to servicing Antero’s operations. · Revenues from Antero provide substantially all of Antero Midstream’s financial support and, therefore, its ability to finance its operations. · As a result of the long-term contractual commitment to support Antero’s substantial growth plans, Antero Midstream will be practically and physically constrained from providing any substantive amount of services to third-parties. 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. On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments , which removes diversity in practice for how certain cash receipts and payments are presented and classified in the statement of cash flows, including the presentation of debt extinguishment costs and the presentation of distributions received from equity method investees. The Company elected to early adopt the standard during the fourth quarter of 2017. As permitted by this standard, the Company made an accounting policy election to account 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, expense, 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 Historically, the markets for natural gas, NGLs, and oil have experienced 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 within accounts payable within its condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its condensed consolidated statements of cash flows. (f) Oil and Gas Properties The Company accounts for its natural gas, NGLs, and crude 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, 2015, 2016, and 2017. 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 $104 million, $163 million, and $160 million for the years ended December 31, 2015, 2016, and 2017, 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 year ended December 31, 2017. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2015 and 2016. At December 31, 2017, 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 $615 million, $700 million, and $694 million for the years ended December 31, 2015, 2016, and 2017, 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 20 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 $87 million, $101 million, and $120 million for the years ended December 31, 2015, 2016, and 2017, 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 years ended December 31, 2015 and 2016. During the year ended December 31, 2017, Antero Midstream recorded a $23.4 million impairment charge for the carrying value of property and equipment related to condensate gathering lines which are no longer servicing Antero’s production. (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 $7.7 million, $8.9 million, and $10.0 million for the years ended December 31, 2015, 2016, and 2017, 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, 2017, the Company had $23 million of unamortized deferred financing costs included in other long‑term assets, and $41 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 $10 million, $16 million, and $13 million for the years ended December 31, 2015, 2016, and 2017, 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 position. 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 (“ARO”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. An ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation, 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. If an obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. 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 water treatment facility upon abandonment. Antero Midstream’s gathering pipelines, compressor stations and fresh water delivery pipelines and facilities have an indeterminate life, if properly maintained. Accordingly, the Company is not able to make a reasonable estimate of when future dismantlement and removal dates of the pipelines, compressor stations, and facilities will occur. The Company’s operational management team determined that abandoning all other ancillary equipment, outside of the assets stated above, would require minimal costs. For the reasons stated above, the Company has not recorded any additional asset retirement obligations, beyond well plugging and abandonment costs, at December 31, 2016 or 2017. (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, 2016 and 2017, 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 Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month after the sale has 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, 2016 and 2017, the Company had no production imbalance positions. (o) 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, 2015, 2016, and 2017 are as follows: 2015 2016 2017 Company A 19 % 29 % 22 % Company B — 13 15 Company C 13 3 1 Company D 18 2 3 All others 50 53 59 100 % 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 fourteen different counterparties. The fair value of the Company’s commodity derivative contracts of approximately $1.3 billion (excluding short-term commodity derivatives related to our marketing activities) at December 31, 2017 includes the following values by bank counterparty: JP Morgan—$288 million; Morgan Stanley—$285 million; Citigroup—$245 million; Scotiabank—$171 million; Wells Fargo—$136 million; Canadian Imperial Bank of Commerce—$51 million; Toronto Dominion Bank—$38 million; BNP Paribas—$30 million; Bank of Montreal—$21 million; Fifth Third Bank—$15 million; SunTrust—$9 million; Natixis—$7 million; and Capital One—$6 million. The credit ratings of certain of these banks were downgraded several years ago because of the sovereign debt crisis in Europe or various other economic factors. 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, 2017 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. (p) 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. (q) 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. (r) 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 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. (s) Marketing Revenues and Expenses Marketing revenues and expenses represent activities undertaken by the Company to purchase and sell third-party natural gas and NGLs and to market its excess firm transportation capacity in order to utilize this excess capacity. Marketing revenues include sales of purchased third-party gas and NGLs, as well as revenues from the release of firm transportation capacity to others. 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. (t) Earnings (loss) Per Common Share Earnings (loss) per common share 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, 2015 2016 2017 Basic weighted average number of shares outstanding 274,123 294,945 315,426 Add: Dilutive effect of restricted stock units 20 — 817 Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — 40 Diluted weighted average number of shares outstanding 274,143 294,945 316,283 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1): Non-vested restricted stock and restricted stock units 2,264 6,740 1,521 Outstanding stock options 553 702 676 Performance stock units — 659 1,054 (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 under the treasury stock method .

Antero Midstream Partners LP

Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2017
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 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 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 18). 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 complex 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 176,295,000 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 219,200,000 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 the 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 the Partnership and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. The Partnership is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2017, the Partnership issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $25.5 million after deducting commissions and other offering costs. As of December 31, 2017, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million. 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 (see note 4). 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 owned approximately 60.9% and 52.9% of the limited partner interests of Antero Midstream at December 31, 2016 and December 31, 2017, respectively.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
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 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 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 18). 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 complex 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 176,295,000 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 219,200,000 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 the 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 the Partnership and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. The Partnership is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2017, the Partnership issued and sold 777,262 common units under the Distribution Agreement, resulting in net proceeds of $25.5 million after deducting commissions and other offering costs. As of December 31, 2017, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $157.3 million. 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 (see note 4). 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 owned approximately 60.9% and 52.9% of the limited partner interests of Antero Midstream at December 31, 2016 and December 31, 2017, respectively.
Antero Midstream Partners LP
Equity Method Investments
Equity Method Investments	(4) Equity Method Investments In 2016, Antero Midstream exercised its option to purchase 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. The Joint Venture assets 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 (loss) includes 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, 2016 and 2017 in thousands): Stonewall MarkWest Total Balance at December 31, 2015 $ — — — Investments 75,516 — 75,516 Equity in net income of unconsolidated affiliates 485 — 485 Distributions from unconsolidated affiliates (7,702) — (7,702) Balance at December 31, 2016 68,299 — 68,299 Investments — 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

Sales of Assets

Sales of Assets	12 Months Ended
	Dec. 31, 2017
Appalachian Gathering Assets
Sale of Assets
Sale of Appalachian Gathering Assets	(5) Sales of Assets Sale of Pennsylvania Leasehold Acreage On December 16, 2016, the Company closed the sale of approximately 17,000 net acres primarily located in Washington and Westmoreland Counties, Pennsylvania. The acreage was outside of the Company’s infrastructure build-out and was not expected to be developed in the near future. Included in the sale were several producing wells and a gathering pipeline belonging to Antero Midstream. Total proceeds from the sale were $169.8 million (subject to customary purchase price adjustments), which includes the proceeds received by Antero Midstream. As a result of the sale, the Company recognized a gain on the sale of assets of $99.0 million for the year ended December 31, 2016.

Accrued Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities
Accrued Liabilities	6) Accrued Liabilities Accrued liabilities as of December 31, 2016 and 2017 consisted of the following items (in thousands): 2016 2017 Capital expenditures $ 159,811 155,300 Gathering, compression, processing, and transportation expenses 75,223 88,850 Marketing expenses 52,822 59,049 Interest expense 35,533 40,861 Other 70,414 99,165 $ 393,803 443,225

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Long-Term Debt.
Long-Term Debt	(7) Long‑Term Debt Long‑term debt was as follows at December 31, 2016 and 2017 (in thousands): 2016 2017 Antero: Credit Facility(a) $ 440,000 185,000 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 1,749 1,520 Net unamortized debt issuance costs (37,690) (32,430) Antero Midstream: Midstream Credit Facility(g) 210,000 555,000 5.375% senior notes due 2024(h) 650,000 650,000 Net unamortized debt issuance costs (10,086) (9,000) $ 4,703,973 4,800,090 Antero Resources Corporation (a) Senior Secured Revolving Credit Facility On November 4, 2010, Antero entered into a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2017, Antero entered into an amendment and restatement of the prior credit facility. References in these Notes to Consolidated Financial Statements to the “Credit Facility” when referring to periods prior to October 26, 2017 refer to the prior credit facility. References in these Notes to Consolidated Financial Statements to the “Credit Facility” when referring to periods on or after October 26, 2017 refer to the new credit facility. 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, 2017, the borrowing base was $4.5 billion and lender commitments were $2.5 billion. The next redetermination of the borrowing base is scheduled to occur in April 2018. 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. Interest is payable at a variable rate based on LIBOR or the prime rate, determined by Antero’s election at the time of borrowing. During an Investment Grade Period, the margin applicable to the Credit Facility borrowings is determined with reference to Antero’s credit rating and ranges from 0.125% to 0.50% lower than rates during a period that is not an Investment Grade Period, depending on Antero’s credit rating and utilization under the Credit Facility. During any period that is not an Investment Grade Period, the margin applicable to the Credit Facility borrowings is determined with reference to utilization under the Credit Facility. Antero was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2016 and 2017. 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. As of December 31, 2016, Antero had an outstanding balance under the Credit Facility of $440 million, with a weighted average interest rate of 2.44%, and outstanding letters of credit of $710 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 102.688% 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 103.844% 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 on or after June 1, 2018 at redemption prices ranging from 104.219% on or after June 1, 2018 to 100.00% on or after June 1, 2021. In addition, on or before June 1, 2018, Antero may redeem up to 35% of the aggregate principal amount of the 2023 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.625% of the principal amount of the 2023 notes, plus accrued and unpaid interest. At any time prior to June 1, 2018, Antero may also redeem the 2023 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2023 notes plus a “make-whole” premium and accrued and unpaid interest. 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 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 May 1, 2018. At December 31, 2016 and 2017, there were no outstanding borrowings under this note. Antero Midstream Partners LP (g) Senior Secured Revolving Credit Facility – Antero Midstream On November 10, 2014, Antero Midstream entered into a senior secured revolving credit facility with a consortium of bank lenders. On October 26, 2017, Antero Midstream entered into an amendment and restatement of the prior credit facility. References in these Notes to Consolidated Financial Statements to the “Midstream Credit Facility” when referring to periods prior to October 26, 2017 refer to Antero Midstream’s prior credit facility. References in these Notes to Consolidated Financial Statements to the “Midstream Credit Facility” when referring to periods on or after October 26, 2017 refer to Antero Midstream’s new credit facility. At December 31, 2017, lender commitments under the Midstream Credit Facility were $1.5 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. Interest is payable at a variable rate based on LIBOR or the prime rate, determined by election at the time of borrowing. Interest at the time of borrowing is determined with reference to (i) during any period that is not an Investment Grade Period, the Antero Midstream’s then-current leverage ratio and (ii) during an Investment Grade Period, with reference to the rating given to the Partnership by Moody’s or Standard and Poor’s. During an Investment Grade Period, the applicable margin rates are reduced by 25 basis points. Antero Midstream was in compliance with all of the financial covenants under the Midstream Credit Facility as of December 31, 2016 and 2017. 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%, and no letters of credit outstanding. As of December 31, 2016, Antero Midstream had a total outstanding balance under the Midstream Credit Facility of $210 million with a weighted average interest rate of 2.23%. 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, 2017
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, 2016 and 2017 (in thousands): 2016 2017 Asset retirement obligations—beginning of year $ 30,612 32,736 Obligations settled — (22) Obligations incurred for wells drilled and producing properties acquired 4,487 4,044 Revisions to prior estimates (4,836) (4,758) Accretion expense 2,473 2,610 Asset retirement obligations—end of year $ 32,736 34,610 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. Revisions to prior estimates in 2016 are primarily due to a decrease in the estimated costs to plug and abandon the Company’s horizontal wells. Asset retirement obligations are included in other liabilities on the consolidated balance sheets.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2017
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 8,402,389 shares were available for future grant under the Plan as of December 31, 2017. 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 7,864,621 common units were available for future grant under the Midstream Plan as of December 31, 2017. The Company’s equity‑based compensation expense, by type of award, was as follows for the years ended December 31, 2015, 2016, and 2017 (in thousands): Year Ended December 31, 2015 2016 2017 Profits interests awards $ 37,620 — — Restricted stock unit awards 40,663 73,081 70,866 Stock options 2,155 2,578 2,375 Performance share unit awards — 8,685 10,797 Antero Midstream phantom unit awards 17,126 16,095 17,461 Equity awards issued to directors 313 1,982 1,946 Total expense $ 97,877 102,421 103,445 Profits Interests Awards Certain profits interest awards historically held by certain of the Company’s officers and employees were fully vested as of December 31, 2015. All available profits interest awards were made prior to the date of the Company’s IPO in 2013, and no additional profits interest awards have been made since the Company’s IPO. 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 and restricted stock unit awards activity for the year ended December 31, 2017 is as follows: Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2016 5,353,447 $ 31.77 $ 126,609 Granted 846,023 $ 22.17 Vested (2,301,180) $ 34.35 Forfeited (474,206) $ 25.66 Total awarded and unvested—December 31, 2017 3,424,084 $ 28.51 $ 65,058 Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. As of December 31, 2017, there was $66.3 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 1.7 years. Stock Options Stock options granted under the Plan vest over periods from one to four years and 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 are granted with an exercise price equal to or greater than the market price of the Company’s common stock on the date of grant. A summary of stock option activity for the year ended December 31, 2017 is as follows: Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2016 687,929 $ 50.46 8.12 $ — Granted — $ — Exercised — $ — Forfeited (27,417) $ 50.00 Expired — $ — Outstanding at December 31, 2017 660,512 $ 50.48 7.06 $ — Vested or expected to vest as of December 31, 2017 660,512 $ 50.48 7.06 $ — Exercisable at December 31, 2017 373,772 $ 50.85 6.88 $ — Intrinsic value is 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. The following table presents information regarding the weighted average fair value for options granted during the year ended December 31, 2015 and the assumptions used to determine fair value. No stock options were granted during the years ended December 31, 2016 and 2017. Dividend yield — % Volatility 40 % Risk-free interest rate 1.66 % Expected life (years) 6.25 Weighted average fair value of options granted $ 14.74 As of December 31, 2017, there was $2.7 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 1.3 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 In 2016 and 2017, the Company also granted PSUs to certain of its employees and executive officers which vest based on the total shareholder return (“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. Summary Information for Performance Share Unit Awards A summary of PSU activity for the year ended December 31, 2017 is as follows: Number of Weighted Total awarded and unvested—December 31, 2016 785,301 $ 29.75 Granted 558,021 $ 26.21 Vested (41,666) $ 27.38 Forfeited (17,813) $ 29.74 Total awarded and unvested—December 31, 2017 1,283,843 $ 28.29 The grant-date fair values of 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’ stock prices. 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 following table presents information regarding the weighted average fair value for PSUs granted during the years ended December 31, 2016 and 2017, and the assumptions used to determine the fair values: Year ended December 31, 2016 2017 Dividend yield — % — % Volatility 45 % 42 % Risk-free interest rate 1.01 % 1.40 % Weighted average fair value of awards granted $ 29.77 $ 26.21 As of December 31, 2017, there was $18.0 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. 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, 2017 is as follows: Number of Weighted Aggregate Total awarded and unvested—December 31, 2016 1,331,961 $ 27.31 $ 41,131 Granted 377,660 $ 32.52 Vested (558,525) $ 28.00 Forfeited (108,133) $ 28.63 Total awarded and unvested—December 31, 2017 1,042,963 $ 28.69 $ 30,288 Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. As of December 31, 2017, there was $25.0 million of unamortized equity-based compensation expense related to unvested phantom unit awards. That expense is expected to be recognized over a weighted average period of approximately 2.0 years.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2017
Financial Instruments
Financial Instruments	(10) Financial Instruments The carrying values of accounts receivable and accounts payable at December 31, 2016 and 2017 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, 2016 and 2017 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 at December 31, 2016 and 2017. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $657 million at December 31, 2016 and $670 million at December 31, 2017. See note 11 for information regarding the fair value of derivative financial instruments.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments.
Derivative Instruments	(11) Derivative Instruments (a) Commodity Derivatives 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, 2015, 2016, and 2017. 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. The Company’s derivative swap 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, 2017, the Company’s fixed price natural gas, NGLs, and oil swap positions from January 1, 2018 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; Mont Belvieu-Propane=Mont Belvieu Propane; NYMEX-WTI=West Texas Intermediate): Natural gas Oil Natural Gas Weighted Three months ending March 31, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.60 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending June 30, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.42 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending September 30, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.45 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending December 31, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.53 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Year ending December 31, 2019: NYMEX ($/MMBtu) 2,330,000 $ 3.50 Year ending December 31, 2020: NYMEX ($/MMBtu) 1,417,500 $ 3.25 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 (b) 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, 2016 and 2017. None of the Company’s derivative instruments are designated as hedges for accounting purposes. December 31, 2016 December 31, 2017 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ 73,022 Current assets 460,685 Commodity contracts Long-term assets 1,731,063 Long-term assets 841,257 Total asset derivatives 1,804,085 1,301,942 Liability derivatives not designated as hedges for accounting purposes: Commodity contracts Current liabilities 203,635 Current liabilities 28,476 Commodity contracts Long-term liabilities 234 Long-term liabilities 207 Total liability derivatives 203,869 28,683 Net derivatives $ 1,600,216 1,273,259 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, 2016 December 31, 2017 Gross Gross amounts Net amounts Gross Gross amounts Net amounts of assets (liabilities) on balance sheet Commodity derivative assets $ 1,914,245 (110,160) 1,804,085 $ 1,367,495 (65,553) 1,301,942 Commodity derivative liabilities $ (324,667) 120,798 (203,869) $ (339,825) 311,142 (28,683) The following is a summary of derivative fair value gains (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2015, 2016, and 2017 (in thousands): Statement of Year ended December 31, location 2015 2016 2017 Commodity derivative fair value gains (losses) Revenue $ 2,381,501 (514,181) 636,889 Commodity derivative fair value gains (losses) for the year ended December 31, 2017 includes gains of $750 million related to certain natural gas derivatives that were monetized prior to their 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. The 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 Company’s commodity derivative position presented in note 11(a) reflects the adjusted fixed price indices after the monetization. Due to delay of the in-service date for a pipeline on which the Company is an anchor shipper, the Company expected to be unable to fulfill its delivery obligations under a natural gas sales contract until late 2018. 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 the 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. The Company determined that these purchase and sale agreements are derivatives which must be measured at fair value. The estimated fair value loss on these contracts of $21.4 million at December 31, 2017 is included in current Derivative liabilities on the Company’s consolidated balance sheet. The Company recognized a corresponding loss of $21.4 million for the year ended December 31, 2017, which is included within Commodity derivative fair value gains (losses) in the Company’s consolidated statement of operations and comprehensive income (loss). The fair value of commodity derivative instruments was determined using Level 2 inputs.

Contract Termination and Rig St

Contract Termination and Rig Stacking	12 Months Ended
	Dec. 31, 2017
Contingencies
Contract Termination and Rig Stacking	(12) Contract Termination and Rig Stacking During the year ended December 31, 2015, the Company incurred $38.5 million of costs for the buy-back and termination of a firm sales contract priced at an unfavorable pricing index and the delay or cancelation of drilling contracts with third-party contractors. There were no such costs incurred during the years ended December 31, 2016 and 2017.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes
Income Taxes	(13) Income Taxes For the years ended December 31, 2015, 2016, and 2017, income tax expense (benefit) consisted of the following (in thousands): Year ended December 31, 2015 2016 2017 Current income tax expense (benefit) $ — (10,984) 75 Deferred income tax expense (benefit) 575,890 (485,392) (295,126) Total income tax expense (benefit) $ 575,890 (496,376) (295,051) Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to income or loss before taxes for the years ended December 31, 2015, 2016, and 2017 as a result of the following (in thousands): Year ended December 31, 2015 2016 2017 Federal income tax expense (benefit) $ 544,560 (436,038) 171,530 State income tax expense (benefit), net of federal benefit 26,983 (20,364) 10,779 Change in Federal tax rate, net of state benefit (1) — — (427,962) Nondeductible equity-based compensation 16,441 3,691 12,098 Noncontrolling interest in Antero Midstream (13,521) (34,780) (59,523) Change in valuation allowance 570 (10,852) (2,073) Other 857 1,967 100 Total income tax expense (benefit) $ 575,890 (496,376) (295,051) (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 primarily due to the reduction in the U.S. statutory rate from 35% to 21%. Based on the Company’s current interpretation and subject to the release of the related regulations and any future interpretive guidance, the Company believes the effects of the change in tax law incorporated herein are substantially complete. 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, 2016 and 2017 is as follows (in thousands): 2016 2017 Deferred tax assets: Net operating loss carryforwards $ 495,275 727,522 Equity-based compensation 20,344 12,062 Investment in Antero Midstream 13,028 38,613 Other 16,483 11,236 Total deferred tax assets 545,130 789,433 Valuation allowance (16,357) (17,361) Net deferred tax assets 528,773 772,072 Deferred tax liabilities: Unrealized gains on derivative instruments 605,487 442,855 Oil and gas properties 866,003 1,058,543 Other 7,500 50,319 Total deferred tax liabilities 1,478,990 1,551,717 Net deferred tax liabilities $ (950,217) (779,645) 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 $16 million and $17 million at December 31, 2016 and 2017, respectively related to net operating loss (NOL) carryforwards primarily attributable to states where the Company no longer operates. 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. A reconciliation of the beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2015, 2016, and 2017 is as follows: 2015 2016 2017 Balance at beginning of year $ 11,000 11,000 — Reductions for tax positions of prior years — (11,000) — Balance at end of year $ 11,000 — — As of December 31, 2017, 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 2018 to 2037. The tax years 2014 through 2017 remain open to examination by the U.S. Internal Revenue Service. The Company and its subsidiaries file tax returns with various state taxing authorities; these returns remain open to examination for tax years 2013 through 2017.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2017
Commitments
Commitments	(14) Commitments The table below is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, as well as leases that have remaining lease terms in excess of one year as of December 31, 2017 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (in millions) (a) (b) (c) (d) Total 2018 $ 866 427 81 14 1,388 2019 1,087 357 42 11 1,497 2020 1,106 361 — 10 1,477 2021 1,085 345 — 9 1,439 2022 1,033 341 — 8 1,382 Thereafter 9,544 1,683 — 56 11,283 Total $ 14,721 3,514 123 108 18,466 (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. 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, and Antero Midstream’s commitments for the construction of its advanced wastewater treatment complex. 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 Rig Service 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. (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, $9 million, and $7 million for the years ended December 31, 2015, 2016, and 2017, respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2017
Contingencies
Contingencies	(15) 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, which are currently pending. If the court denies those motions, SJGC will have 30 days from the court’s decision on these post-judgment motions to file an appeal. 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 May of 2017. Through December 31, 2017, the Company estimates that it is owed approximately $76 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, after hearing a week of testimony and evidence, 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 also reaffirmed the arbitration panel’s finding that the delivery point under the Contracts was not the IPP Pool. WGL has appealed this decision to the Colorado Court of Appeals and that appeal remains pending. 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 rejected by the arbitration panel and the Colorado district court. 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 certain amounts of gas received by WGL. Through December 31, 2017, these damages amounted to approximately $101 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. This case is set for trial on September 17, 2018. 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. 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. Upon both (1) the in service of the Dominion Cove Point LNG facility and (2) the earlier of in service of the WB East expansion and January 1, 2019, the aggregate contract volumes to be delivered to WGL will increase by 330,000 MMBtu/day. This increase will be in effect for the remaining term of our gas sale contract with WGL Midstream, which expires in 2038, and these increased volumes will be subject to NYMEX-based pricing. Following the increase of 330,000 MMBtu/day, the aggregate contract volumes to be delivered to WGL will 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, 2017
Related Parties
Related Parties	(16) 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, 2015, 2016, and 2017 were derived from transactions with Antero. See Note 17 for the operating results of the Company’s reportable segments.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Information
Segment Information	(17) Segment Information See note 2(r) 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 are the same as the Company’s accounting policies described in note 2 to the consolidated financial statements. The operating results and assets of the Company’s reportable segments were as follows for the years ended December 31, 2015, 2016, and 2017 (in thousands): Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2015: Sales and revenues: Third-party $ 3,756,629 12,353 9,647 176,229 — 3,954,858 Intersegment 4,795 218,239 147,085 — (370,119) — Total $ 3,761,424 230,592 156,732 176,229 (370,119) 3,954,858 Operating expenses: Lease operating $ 35,552 — 49,859 — (49,400) 36,011 Gathering, compression, processing, and transportation 852,573 25,305 — — (218,517) 659,361 Depletion, depreciation, and amortization 622,379 61,552 25,832 — — 709,763 General and administrative 183,675 40,448 10,758 — (1,184) 233,697 Other 222,990 3,811 3,210 299,062 (3,333) 525,740 Total 1,917,169 131,116 89,659 299,062 (272,434) 2,164,572 Operating income (loss) $ 1,844,255 99,476 67,073 (122,833) (97,685) 1,790,286 Equity in earnings of unconsolidated affiliates $ — — — — — — Segment assets $ 12,426,518 1,470,691 525,004 16,123 (322,843) 14,115,493 Capital expenditures for segment assets $ 1,954,256 360,287 131,051 — (97,685) 2,347,909 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

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information
Subsidiary Guarantors	(18) 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, 2016 and 2017, 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, 2015, 2016, and 2017, 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 (Antero Midstream and its 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. Distributions received from Antero Midstream have been reclassified from investing activities to operating activities on the Condensed Consolidating Statement of Cash Flows for the years ended December 31, 2015 and 2016. The reclassification is a result of the adoption of ASU No. 2016-05, Classification of Certain Cash Receipts and Cash Payments , which provides for an accounting policy election to account for distributions received from equity method investees under the “nature of distribution” approach. Condensed Consolidating Balance Sheet December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 17,568 — 14,042 — 31,610 Accounts receivable, net 28,442 — 1,240 — 29,682 Intercompany receivables 3,193 — 64,139 (67,332) — Accrued revenue 261,960 — — — 261,960 Derivative instruments 73,022 — — — 73,022 Other current assets 5,784 — 529 — 6,313 Total current assets 389,969 — 79,950 (67,332) 402,587 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 2,331,173 — — — 2,331,173 Proved properties 9,726,957 — — (177,286) 9,549,671 Water handling and treatment systems — — 744,682 — 744,682 Gathering systems and facilities 17,929 — 1,705,839 — 1,723,768 Other property and equipment 41,231 — — — 41,231 12,117,290 — 2,450,521 (177,286) 14,390,525 Less accumulated depletion, depreciation, and amortization (2,109,136) — (254,642) — (2,363,778) Property and equipment, net 10,008,154 — 2,195,879 (177,286) 12,026,747 Derivative instruments 1,731,063 — — — 1,731,063 Investments in subsidiaries (420,429) — — 420,429 — Contingent acquisition consideration 194,538 — — (194,538) — Investments in unconsolidated affiliates — — 68,299 — 68,299 Other assets, net 21,087 — 5,767 — 26,854 Total assets $ 11,924,382 — 2,349,895 (18,727) 14,255,550 Liabilities and Equity Current liabilities: Accounts payable $ 21,648 — 16,979 — 38,627 Intercompany payable 64,139 — 3,193 (67,332) — Accrued liabilities 332,162 — 61,641 — 393,803 Revenue distributions payable 163,989 — — — 163,989 Derivative instruments 203,635 — — — 203,635 Other current liabilities 17,134 — 200 — 17,334 Total current liabilities 802,707 — 82,013 (67,332) 817,388 Long-term liabilities: Long-term debt 3,854,059 — 849,914 — 4,703,973 Deferred income tax liability 950,217 — — — 950,217 Contingent acquisition consideration — — 194,538 (194,538) — Derivative instruments 234 — — — 234 Other liabilities 54,540 — 620 — 55,160 Total liabilities 5,661,757 — 1,127,085 (261,870) 6,526,972 Equity: Stockholders' equity: Partners' capital — — 1,222,810 (1,222,810) — Common stock 3,149 — — — 3,149 Additional paid-in capital 5,299,481 — — — 5,299,481 Accumulated earnings 959,995 — — — 959,995 Total stockholders' equity 6,262,625 — 1,222,810 (1,222,810) 6,262,625 Noncontrolling interests in consolidated subsidiary — — — 1,465,953 1,465,953 Total equity 6,262,625 — 1,222,810 243,143 7,728,578 Total liabilities and equity $ 11,924,382 — 2,349,895 (18,727) 14,255,550 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 Investments in subsidiaries (573,926) — — 573,926 — Contingent acquisition consideration 208,014 — — (208,014) — Investments in unconsolidated affiliates — — 303,302 — 303,302 Other assets, net 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 Statement of Operations and Comprehensive Income Year Ended December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,039,892 — — — 1,039,892 Natural gas liquids sales 264,483 — — — 264,483 Oil sales 70,753 — — — 70,753 Gathering, compression, water handling and treatment 6,651 — 299,787 (284,438) 22,000 Marketing 176,229 — — — 176,229 Commodity derivative fair value gains 2,381,501 — — — 2,381,501 Other income 4,594 — — (4,594) — Total revenue and other 3,944,103 — 299,787 (289,032) 3,954,858 Operating expenses: Lease operating 36,132 — 33,283 (33,404) 36,011 Gathering, compression, processing, and transportation 852,573 — 25,305 (218,517) 659,361 Production and ad valorem taxes 77,074 — 1,251 — 78,325 Marketing 299,062 — — — 299,062 Exploration 3,846 — — — 3,846 Impairment of unproved properties 104,321 — — — 104,321 Depletion, depreciation, and amortization 641,860 — 67,903 — 709,763 Accretion of asset retirement obligations 1,655 — — — 1,655 General and administrative 190,712 — 43,968 (983) 233,697 Contract termination and rig stacking 38,531 — — — 38,531 Accretion of contingent acquisition consideration — — 3,333 (3,333) — Total operating expenses 2,245,766 — 175,043 (256,237) 2,164,572 Operating income 1,698,337 — 124,744 (32,795) 1,790,286 Other expenses: Interest (228,568) — (5,832) — (234,400) Equity in net income of subsidiaries 47,485 — — (47,485) — Total other expenses (181,083) — (5,832) (47,485) (234,400) Income before income taxes 1,517,254 — 118,912 (80,280) 1,555,886 Provision for income tax expense (575,890) — — — (575,890) Net income and comprehensive income including noncontrolling interests 941,364 — 118,912 (80,280) 979,996 Net income and comprehensive income attributable to noncontrolling interests — — — 38,632 38,632 Net income and comprehensive income attributable to Antero Resources Corporation $ 941,364 — 118,912 (118,912) 941,364 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) 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 Accretion 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 net income of subsidiaries (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 Gathering, compression, water handling and treatment — — 772,497 (759,777) 12,720 Marketing 258,045 — — — 258,045 Commodity derivative fair value gains 636,889 — — — 636,889 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 Accretion 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 net income of subsidiaries (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 Cash Flows Year Ended December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 917,639 — 195,059 (96,886) 1,015,812 Cash flows used in investing activities: Additions to unproved properties (198,694) — — — (198,694) Drilling and completion costs (1,675,049) — — 23,767 (1,651,282) Additions to water handling and treatment systems (80,064) — (50,987) — (131,051) Additions to gathering systems and facilities (40,285) — (320,002) — (360,287) Additions to other property and equipment (6,595) — — — (6,595) Change in other assets 2,570 — 7,180 — 9,750 Net distributions from guarantor subsidiary (115,000) — — 115,000 — Proceeds from contribution of assets to non-guarantor subsidiary 801,116 — — (801,116) — Proceeds from asset sales 40,000 — — — 40,000 Net cash used in investing activities (1,272,001) — (363,809) (662,349) (2,298,159) Cash flows provided by (used in) financing activities: Issuance of common stock 537,832 — — — 537,832 Issuance of common units by Antero Midstream — — 240,703 — 240,703 Issuance of senior notes 750,000 — — — 750,000 Borrowings (repayments) on bank credit facility, net (908,000) (115,000) 620,000 — (403,000) Payments of deferred financing costs (15,234) — (2,059) — (17,293) Distributions — 115,000 (908,364) 759,235 (34,129) Employee tax withholding for settlement of equity compensation awards (4,625) — (4,806) — (9,431) Other (4,808) — (33) — (4,841) Net cash provided by (used in) financing activities 355,165 — (54,559) 759,235 1,059,841 Net increase (decrease) in cash and cash equivalents 803 — (223,309) — (222,506) Cash and cash equivalents, beginning of period 15,787 — 230,192 — 245,979 Cash and cash equivalents, end of period $ 16,590 — 6,883 — 23,473 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by 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 Accretion of contingent acquisition consideration (16,489) — 16,489 — — Impairment of unproved properties 162,935 — — — 162,935 Derivative fair value (gains) losses 514,181 — — — 514,181 Gains on settled derivatives 1,003,083 — — — 1,003,083 Deferred income tax expense (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 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 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 Resources Corporation 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 operating activities: Net income (loss) including noncontrolling interests $ 615,070 — 307,315 (137,248) 785,137 Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 707,658 — 119,562 — 827,220 Accretion 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 Derivative fair value (gains) losses (636,889) — — — (636,889) Gains on settled derivatives 213,940 — — — 213,940 Proceeds from derivative monetizations 749,906 — — — 749,906 Deferred income tax expense (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 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 (used in) 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

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information (Unaudited)
Quarterly Financial Information (Unaudited)	(19) Quarterly Financial Information (Unaudited) The Company’s quarterly consolidated financial information for the years ended December 31, 2016 and 2017 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, 2016: Total operating revenues $ 721,004 $ (249,198) $ 1,116,503 $ 156,216 Total operating expenses 642,255 640,675 649,171 788,225 Operating income (loss) 78,749 (889,873) 467,332 (632,009) Net income (loss) and comprehensive income (loss) including noncontrolling interest 10,650 (575,490) 268,196 (452,804) Net income attributable to noncontrolling interest 15,705 20,754 29,941 32,968 Net income (loss) attributable to Antero Resources Corporation (5,055) (596,244) 238,255 (485,772) Earnings (loss) per common share—basic $ (0.02) $ (2.12) $ 0.78 $ (1.55) Earnings (loss) per common share—assuming dilution $ (0.02) $ (2.12) $ 0.77 $ (1.55) 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 $ 0.85 $ (0.02) $ (0.43) $ 1.54 Earnings (loss) per common share—diluted $ 0.85 $ (0.02) $ (0.43) $ 1.54

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2017
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	(20) Supplemental Information on Oil and Gas Producing Activities (Unaudited) The following 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) 2016 2017 Proved properties $ 9,549,671 11,096,462 Unproved properties 2,331,173 2,266,673 11,880,844 13,363,135 Accumulated depletion and depreciation (2,089,500) (2,783,832) Net capitalized costs $ 9,791,344 10,579,303 (b) Costs Incurred in Certain Oil and Gas Activities Year ended December 31, (In thousands) 2015 2016 2017 Acquisition costs: Proved property $ — 134,113 175,650 Unproved property 198,694 611,631 204,272 Development costs 1,039,301 1,000,903 897,287 Exploration costs 611,981 326,856 384,698 Total costs incurred $ 1,849,976 2,073,503 1,661,907 (c) Results of Operations for Oil and Gas Producing Activities Year ended December 31, (In thousands) 2015 2016 2017 Revenues $ 1,375,128 1,755,061 2,747,920 Operating expenses: Production expenses 773,697 999,516 1,279,217 Exploration expenses 3,846 6,862 8,538 Depletion and depreciation 614,700 700,274 694,332 Impairment of unproved properties 104,321 162,935 159,598 Results of operations before income tax expense (121,436) (114,526) 606,235 Income tax (expense) benefit 45,497 43,334 (228,096) Results of operations $ (75,939) (71,192) 378,139 (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, 2015, 2016, and 2017 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 crude oil, condensate, 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 oil and gas prices, cash flows from operations, future drilling costs, demand for natural gas, and other economic factors. Natural NGLs Oil and Equivalents Proved reserves: December 31, 2014 10,535 330 28 12,683 Revisions (2,816) 176 (8) (1,801) Extensions, discoveries and other additions 2,253 97 8 2,878 Production (439) (16) (2) (545) 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 677 (7) (4) 613 Extensions, discoveries and other additions 1,309 62 5 1,711 Production (591) (36) (2) (822) Purchases of reserves 289 13 1 373 December 31, 2017 11,098 989 38 17,261 Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2015 3,627 360 8 5,838 December 31, 2016 4,426 401 13 6,914 December 31, 2017 5,587 467 16 8,488 Proved undeveloped reserves: December 31, 2015 5,906 227 18 7,377 December 31, 2016 4,988 556 25 8,472 December 31, 2017 5,511 522 22 8,773 Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2015, 2016, and 2017 in the above table include the following: 2015 Changes in Reserves · Extensions, discoveries, and other additions of 2,878 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales. · Positive revisions of 1,091 Bcfe due to partial ethane recovery is a result of changing from ethane rejection at December 31, 2014 to partial ethane recovery in 2015. In 2015, the Company began ethane recovery and changed its underlying production assumptions to the recovery of approximately 11,500 gross barrels per day of ethane at December 31, 2015. · Negative performance revisions of 358 Bcfe resulted from the revised statistical analysis of reserves based on actual production results. · Negative revisions of 2,332 Bcfe were due to the SEC 5-year development rule because the Company no longer expected certain locations in the eastern portion of its Marcellus acreage containing primarily dry gas to be developed within five years. · Negative revisions of 202 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. 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. · Positive 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. · Positive performance revisions of 762 Bcfe primarily relate to improved well performance. · Negative 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. · Negative revisions of 47 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. · A negative revision of 10 Bcfe was related to our sale of producing and non-producing leasehold in Pennsylvania. 2017 Changes in Reserves · Extensions, discoveries, and other additions of 1,711 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. · Positive revisions of 96 Bcfe related to improved well performance. · Net positive revisions of 498 Bcfe related to revisions to our 5-year development plan. This figure includes positive revisions of 2,778 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 negative revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves. · Positive revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil. · Negative revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery 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) 2015 2016 2017 Future cash inflows $ 35,179 36,800 55,824 Future production costs (17,393) (21,275) (26,375) Future development costs (5,217) (3,902) (3,312) Future net cash flows before income tax 12,569 11,623 26,137 Future income tax expense (1,708) (1,042) (4,104) Future net cash flows 10,861 10,581 22,033 10% annual discount for estimated timing of cash flows (7,628) (7,294) (13,406) Standardized measure of discounted future net cash flows $ 3,233 3,287 8,627 The 12‑month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe): December 31, 2015 $ 2.66 December 31, 2016 $ 2.39 December 31, 2017 $ 3.23 (f) Changes in Standardized Measure of Discounted Future Net Cash Flow Year ended December 31, (in millions) 2015 2016 2017 Sales of oil and gas, net of productions costs $ (601) (756) (1,469) Net changes in prices and production costs (9,416) (1,540) 3,918 Development costs incurred during the period 769 733 627 Net changes in future development costs 671 212 229 Extensions, discoveries and other additions 861 673 1,195 Acquisitions — 66 258 Divestitures — (7) — Revisions of previous quantity estimates (1,167) 461 987 Accretion of discount 1,132 363 368 Net change in income taxes 3,284 12 (1,159) Other changes 65 (163) 386 Net increase (decrease) (4,402) 54 5,340 Beginning of year 7,635 3,233 3,287 End of year $ 3,233 3,287 8,627

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies
Basis of Presentation	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, 2016 and 2017, and the results of its operations and its cash flows for the years ended December 31, 2015, 2016, and 2017. The Company has no items of other comprehensive income or loss; therefore, its net income or loss is identical 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 Resources Corporation, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. We have determined that Antero Midstream is a VIE for which Antero is the primary beneficiary. Therefore, Antero Midstream’s accounts are included 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 or right to receive benefits of 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 52.9% of the outstanding limited partner interests in Antero Midstream at December 31, 2017. · Antero Midstream GP LP (“AMGP”) indirectly controls the general partnership interest in Antero Midstream and directly controls Antero IDR Holdings LLC (“IDR LLC”), which owns the incentive distribution rights in Antero Midstream. However, AMGP has not provided, and is not expected to provide, financial support to Antero Midstream. Antero does not control AMGP and does not have any investment in AMGP. · Antero’s officers and management group also act as management of Antero Midstream and AMGP. · Antero and Antero Midstream have contracts with 20-year initial terms and automatic renewal provisions, whereby Antero has dedicated the rights for gathering and compression, and water delivery and handling, services to Antero Midstream on a fixed-fee basis. Such dedications cover a substantial portion of Antero’s current acreage and future acquired acreage, in each case, except for acreage that was already dedicated to other parties prior to entering into the service contracts or that was acquired subject to a pre-existing dedication. The contracts call for Antero to present, in advance, its drilling and completion plans in order for Antero Midstream to develop gathering and compression and water delivery and handling assets to service Antero’s operations. Consequently, the drilling and completion capital investment decisions made by Antero control the development and operation of all of Antero Midstream’s assets. Because of these contractual obligations and the capital requirements related to these obligations, Antero Midstream has and, for the foreseeable future, will devote substantially all of its resources to servicing Antero’s operations. · Revenues from Antero provide substantially all of Antero Midstream’s financial support and, therefore, its ability to finance its operations. · As a result of the long-term contractual commitment to support Antero’s substantial growth plans, Antero Midstream will be practically and physically constrained from providing any substantive amount of services to third-parties. 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. On August 26, 2016, the FASB issued ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments , which removes diversity in practice for how certain cash receipts and payments are presented and classified in the statement of cash flows, including the presentation of debt extinguishment costs and the presentation of distributions received from equity method investees. The Company elected to early adopt the standard during the fourth quarter of 2017. As permitted by this standard, the Company made an accounting policy election to account 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, expense, 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	Risks and Uncertainties Historically, the markets for natural gas, NGLs, and oil have experienced 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.
Oil and Gas Properties	Oil and Gas Properties The Company accounts for its natural gas, NGLs, and crude 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, 2015, 2016, and 2017. 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 $104 million, $163 million, and $160 million for the years ended December 31, 2015, 2016, and 2017, 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 year ended December 31, 2017. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2015 and 2016. At December 31, 2017, 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 $615 million, $700 million, and $694 million for the years ended December 31, 2015, 2016, and 2017, respectively.
Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems	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 20 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 $87 million, $101 million, and $120 million for the years ended December 31, 2015, 2016, and 2017, 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 years ended December 31, 2015 and 2016. During the year ended December 31, 2017, Antero Midstream recorded a $23.4 million impairment charge for the carrying value of property and equipment related to condensate gathering lines which are no longer servicing Antero’s production.
Other Property and Equipment	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 $7.7 million, $8.9 million, and $10.0 million for the years ended December 31, 2015, 2016, and 2017, respectively. A gain or loss is recognized upon the sale or disposal of other property and equipment.
Deferred Financing Costs	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, 2017, the Company had $23 million of unamortized deferred financing costs included in other long‑term assets, and $41 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 $10 million, $16 million, and $13 million for the years ended December 31, 2015, 2016, and 2017, respectively.
Derivative Financial Instruments	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 position. 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 (“ARO”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. An ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation, 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. If an obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. 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 water treatment facility upon abandonment. Antero Midstream’s gathering pipelines, compressor stations and fresh water delivery pipelines and facilities have an indeterminate life, if properly maintained. Accordingly, the Company is not able to make a reasonable estimate of when future dismantlement and removal dates of the pipelines, compressor stations, and facilities will occur. The Company’s operational management team determined that abandoning all other ancillary equipment, outside of the assets stated above, would require minimal costs. For the reasons stated above, the Company has not recorded any additional asset retirement obligations, beyond well plugging and abandonment costs, at December 31, 2016 or 2017.
Environmental Liabilities	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, 2016 and 2017, 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	Natural Gas, NGLs, and Oil Revenues Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month after the sale has 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, 2016 and 2017, the Company had no production imbalance positions.
Concentrations of Credit Risk	(o) 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, 2015, 2016, and 2017 are as follows: 2015 2016 2017 Company A 19 % 29 % 22 % Company B — 13 15 Company C 13 3 1 Company D 18 2 3 All others 50 53 59 100 % 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 fourteen different counterparties. The fair value of the Company’s commodity derivative contracts of approximately $1.3 billion (excluding short-term commodity derivatives related to our marketing activities) at December 31, 2017 includes the following values by bank counterparty: JP Morgan—$288 million; Morgan Stanley—$285 million; Citigroup—$245 million; Scotiabank—$171 million; Wells Fargo—$136 million; Canadian Imperial Bank of Commerce—$51 million; Toronto Dominion Bank—$38 million; BNP Paribas—$30 million; Bank of Montreal—$21 million; Fifth Third Bank—$15 million; SunTrust—$9 million; Natixis—$7 million; and Capital One—$6 million. The credit ratings of certain of these banks were downgraded several years ago because of the sovereign debt crisis in Europe or various other economic factors. 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, 2017 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.
Fair Value Measurements	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	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 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.
Marketing Revenues and Expenses	Marketing Revenues and Expenses Marketing revenues and expenses represent activities undertaken by the Company to purchase and sell third-party natural gas and NGLs and to market its excess firm transportation capacity in order to utilize this excess capacity. Marketing revenues include sales of purchased third-party gas and NGLs, as well as revenues from the release of firm transportation capacity to others. 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.
Earnings (loss) per common share	(t) Earnings (loss) Per Common Share Earnings (loss) per common share 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, 2015 2016 2017 Basic weighted average number of shares outstanding 274,123 294,945 315,426 Add: Dilutive effect of restricted stock units 20 — 817 Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — 40 Diluted weighted average number of shares outstanding 274,143 294,945 316,283 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1): Non-vested restricted stock and restricted stock units 2,264 6,740 1,521 Outstanding stock options 553 702 676 Performance stock units — 659 1,054 (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 under the treasury stock method
Cash and Cash Equivalents	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 within accounts payable within its condensed consolidated balance sheets, and classifies the change in accounts payable associated with book overdrafts as an operating activity within its condensed consolidated statements of cash flows.
Income Taxes	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.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of Significant Accounting Policies
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales)	2015 2016 2017 Company A 19 % 29 % 22 % Company B — 13 15 Company C 13 3 1 Company D 18 2 3 All others 50 53 59 100 % 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, 2015 2016 2017 Basic weighted average number of shares outstanding 274,123 294,945 315,426 Add: Dilutive effect of restricted stock units 20 — 817 Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — 40 Diluted weighted average number of shares outstanding 274,143 294,945 316,283 Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1): Non-vested restricted stock and restricted stock units 2,264 6,740 1,521 Outstanding stock options 553 702 676 Performance stock units — 659 1,054 (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 under the treasury stock method .

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2016 and 2017 in thousands): Stonewall MarkWest Total Balance at December 31, 2015 $ — — — Investments 75,516 — 75,516 Equity in net income of unconsolidated affiliates 485 — 485 Distributions from unconsolidated affiliates (7,702) — (7,702) Balance at December 31, 2016 68,299 — 68,299 Investments — 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

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities
Schedule of accrued liabilities	Accrued liabilities as of December 31, 2016 and 2017 consisted of the following items (in thousands): 2016 2017 Capital expenditures $ 159,811 155,300 Gathering, compression, processing, and transportation expenses 75,223 88,850 Marketing expenses 52,822 59,049 Interest expense 35,533 40,861 Other 70,414 99,165 $ 393,803 443,225

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Long-Term Debt.
Schedule of long-term debt	Long‑term debt was as follows at December 31, 2016 and 2017 (in thousands): 2016 2017 Antero: Credit Facility(a) $ 440,000 185,000 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 1,749 1,520 Net unamortized debt issuance costs (37,690) (32,430) Antero Midstream: Midstream Credit Facility(g) 210,000 555,000 5.375% senior notes due 2024(h) 650,000 650,000 Net unamortized debt issuance costs (10,086) (9,000) $ 4,703,973 4,800,090

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2016 and 2017 (in thousands): 2016 2017 Asset retirement obligations—beginning of year $ 30,612 32,736 Obligations settled — (22) Obligations incurred for wells drilled and producing properties acquired 4,487 4,044 Revisions to prior estimates (4,836) (4,758) Accretion expense 2,473 2,610 Asset retirement obligations—end of year $ 32,736 34,610

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2015, 2016, and 2017 (in thousands): Year Ended December 31, 2015 2016 2017 Profits interests awards $ 37,620 — — Restricted stock unit awards 40,663 73,081 70,866 Stock options 2,155 2,578 2,375 Performance share unit awards — 8,685 10,797 Antero Midstream phantom unit awards 17,126 16,095 17,461 Equity awards issued to directors 313 1,982 1,946 Total expense $ 97,877 102,421 103,445
Summary of restricted stock and restricted stock unit awards activity	Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2016 5,353,447 $ 31.77 $ 126,609 Granted 846,023 $ 22.17 Vested (2,301,180) $ 34.35 Forfeited (474,206) $ 25.66 Total awarded and unvested—December 31, 2017 3,424,084 $ 28.51 $ 65,058
Summary of stock option activity	Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2016 687,929 $ 50.46 8.12 $ — Granted — $ — Exercised — $ — Forfeited (27,417) $ 50.00 Expired — $ — Outstanding at December 31, 2017 660,512 $ 50.48 7.06 $ — Vested or expected to vest as of December 31, 2017 660,512 $ 50.48 7.06 $ — Exercisable at December 31, 2017 373,772 $ 50.85 6.88 $ —
Schedule of weighted average fair value assumptions used for stock options	Dividend yield — % Volatility 40 % Risk-free interest rate 1.66 % Expected life (years) 6.25 Weighted average fair value of options granted $ 14.74
Summary of Performance Stock Unit activity	A summary of PSU activity for the year ended December 31, 2017 is as follows: Number of Weighted Total awarded and unvested—December 31, 2016 785,301 $ 29.75 Granted 558,021 $ 26.21 Vested (41,666) $ 27.38 Forfeited (17,813) $ 29.74 Total awarded and unvested—December 31, 2017 1,283,843 $ 28.29
Schedule of weighted average fair value assumptions used for PSUs granted	Year ended December 31, 2016 2017 Dividend yield — % — % Volatility 45 % 42 % Risk-free interest rate 1.01 % 1.40 % Weighted average fair value of awards granted $ 29.77 $ 26.21
Schedule of outstanding unvested restricted stock awards vesting schedule	Number of Weighted Aggregate Total awarded and unvested—December 31, 2016 1,331,961 $ 27.31 $ 41,131 Granted 377,660 $ 32.52 Vested (558,525) $ 28.00 Forfeited (108,133) $ 28.63 Total awarded and unvested—December 31, 2017 1,042,963 $ 28.69 $ 30,288

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments.
Schedule of outstanding commodity derivatives	Natural gas Oil Natural Gas Weighted Three months ending March 31, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.60 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending June 30, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.42 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending September 30, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.45 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Three months ending December 31, 2018: NYMEX ($/MMBtu) 2,002,500 — — $ 3.53 NYMEX-WTI ($/Bbl) — 4,000 — $ 55.97 Mont Belvieu-Propane ($/Gallon) — — 19,000 $ 0.75 Total 2,002,500 4,000 19,000 Year ending December 31, 2019: NYMEX ($/MMBtu) 2,330,000 $ 3.50 Year ending December 31, 2020: NYMEX ($/MMBtu) 1,417,500 $ 3.25 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
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	December 31, 2016 December 31, 2017 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ 73,022 Current assets 460,685 Commodity contracts Long-term assets 1,731,063 Long-term assets 841,257 Total asset derivatives 1,804,085 1,301,942 Liability derivatives not designated as hedges for accounting purposes: Commodity contracts Current liabilities 203,635 Current liabilities 28,476 Commodity contracts Long-term liabilities 234 Long-term liabilities 207 Total liability derivatives 203,869 28,683 Net derivatives $ 1,600,216 1,273,259
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, 2016 December 31, 2017 Gross Gross amounts Net amounts Gross Gross amounts Net amounts of assets (liabilities) on balance sheet Commodity derivative assets $ 1,914,245 (110,160) 1,804,085 $ 1,367,495 (65,553) 1,301,942 Commodity derivative liabilities $ (324,667) 120,798 (203,869) $ (339,825) 311,142 (28,683)
Summary of derivative fair value gains (losses)	The following is a summary of derivative fair value gains (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2015, 2016, and 2017 (in thousands): Statement of Year ended December 31, location 2015 2016 2017 Commodity derivative fair value gains (losses) Revenue $ 2,381,501 (514,181) 636,889

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes
Schedule of income tax expense from continuing operations	For the years ended December 31, 2015, 2016, and 2017, income tax expense (benefit) consisted of the following (in thousands): Year ended December 31, 2015 2016 2017 Current income tax expense (benefit) $ — (10,984) 75 Deferred income tax expense (benefit) 575,890 (485,392) (295,126) Total income tax expense (benefit) $ 575,890 (496,376) (295,051)
Schedule of reconciliation of income tax expense from continuing operations	Income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to income or loss before taxes for the years ended December 31, 2015, 2016, and 2017 as a result of the following (in thousands): Year ended December 31, 2015 2016 2017 Federal income tax expense (benefit) $ 544,560 (436,038) 171,530 State income tax expense (benefit), net of federal benefit 26,983 (20,364) 10,779 Change in Federal tax rate, net of state benefit (1) — — (427,962) Nondeductible equity-based compensation 16,441 3,691 12,098 Noncontrolling interest in Antero Midstream (13,521) (34,780) (59,523) Change in valuation allowance 570 (10,852) (2,073) Other 857 1,967 100 Total income tax expense (benefit) $ 575,890 (496,376) (295,051)
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, 2016 and 2017 is as follows (in thousands): 2016 2017 Deferred tax assets: Net operating loss carryforwards $ 495,275 727,522 Equity-based compensation 20,344 12,062 Investment in Antero Midstream 13,028 38,613 Other 16,483 11,236 Total deferred tax assets 545,130 789,433 Valuation allowance (16,357) (17,361) Net deferred tax assets 528,773 772,072 Deferred tax liabilities: Unrealized gains on derivative instruments 605,487 442,855 Oil and gas properties 866,003 1,058,543 Other 7,500 50,319 Total deferred tax liabilities 1,478,990 1,551,717 Net deferred tax liabilities $ (950,217) (779,645)
Schedule of reconciliation of beginning and ending amount of unrecognized tax benefits	2015 2016 2017 Balance at beginning of year $ 11,000 11,000 — Reductions for tax positions of prior years — (11,000) — Balance at end of year $ 11,000 — —

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2017
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, as well as leases that have remaining lease terms in excess of one year as of December 31, 2017 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (in millions) (a) (b) (c) (d) Total 2018 $ 866 427 81 14 1,388 2019 1,087 357 42 11 1,497 2020 1,106 361 — 10 1,477 2021 1,085 345 — 9 1,439 2022 1,033 341 — 8 1,382 Thereafter 9,544 1,683 — 56 11,283 Total $ 14,721 3,514 123 108 18,466

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2015, 2016, and 2017 (in thousands): Exploration Gathering and Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2015: Sales and revenues: Third-party $ 3,756,629 12,353 9,647 176,229 — 3,954,858 Intersegment 4,795 218,239 147,085 — (370,119) — Total $ 3,761,424 230,592 156,732 176,229 (370,119) 3,954,858 Operating expenses: Lease operating $ 35,552 — 49,859 — (49,400) 36,011 Gathering, compression, processing, and transportation 852,573 25,305 — — (218,517) 659,361 Depletion, depreciation, and amortization 622,379 61,552 25,832 — — 709,763 General and administrative 183,675 40,448 10,758 — (1,184) 233,697 Other 222,990 3,811 3,210 299,062 (3,333) 525,740 Total 1,917,169 131,116 89,659 299,062 (272,434) 2,164,572 Operating income (loss) $ 1,844,255 99,476 67,073 (122,833) (97,685) 1,790,286 Equity in earnings of unconsolidated affiliates $ — — — — — — Segment assets $ 12,426,518 1,470,691 525,004 16,123 (322,843) 14,115,493 Capital expenditures for segment assets $ 1,954,256 360,287 131,051 — (97,685) 2,347,909 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

Condensed Consolidating Finan39

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information
Schedule of condensed consolidated balance sheets	Condensed Consolidating Balance Sheet December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 17,568 — 14,042 — 31,610 Accounts receivable, net 28,442 — 1,240 — 29,682 Intercompany receivables 3,193 — 64,139 (67,332) — Accrued revenue 261,960 — — — 261,960 Derivative instruments 73,022 — — — 73,022 Other current assets 5,784 — 529 — 6,313 Total current assets 389,969 — 79,950 (67,332) 402,587 Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties 2,331,173 — — — 2,331,173 Proved properties 9,726,957 — — (177,286) 9,549,671 Water handling and treatment systems — — 744,682 — 744,682 Gathering systems and facilities 17,929 — 1,705,839 — 1,723,768 Other property and equipment 41,231 — — — 41,231 12,117,290 — 2,450,521 (177,286) 14,390,525 Less accumulated depletion, depreciation, and amortization (2,109,136) — (254,642) — (2,363,778) Property and equipment, net 10,008,154 — 2,195,879 (177,286) 12,026,747 Derivative instruments 1,731,063 — — — 1,731,063 Investments in subsidiaries (420,429) — — 420,429 — Contingent acquisition consideration 194,538 — — (194,538) — Investments in unconsolidated affiliates — — 68,299 — 68,299 Other assets, net 21,087 — 5,767 — 26,854 Total assets $ 11,924,382 — 2,349,895 (18,727) 14,255,550 Liabilities and Equity Current liabilities: Accounts payable $ 21,648 — 16,979 — 38,627 Intercompany payable 64,139 — 3,193 (67,332) — Accrued liabilities 332,162 — 61,641 — 393,803 Revenue distributions payable 163,989 — — — 163,989 Derivative instruments 203,635 — — — 203,635 Other current liabilities 17,134 — 200 — 17,334 Total current liabilities 802,707 — 82,013 (67,332) 817,388 Long-term liabilities: Long-term debt 3,854,059 — 849,914 — 4,703,973 Deferred income tax liability 950,217 — — — 950,217 Contingent acquisition consideration — — 194,538 (194,538) — Derivative instruments 234 — — — 234 Other liabilities 54,540 — 620 — 55,160 Total liabilities 5,661,757 — 1,127,085 (261,870) 6,526,972 Equity: Stockholders' equity: Partners' capital — — 1,222,810 (1,222,810) — Common stock 3,149 — — — 3,149 Additional paid-in capital 5,299,481 — — — 5,299,481 Accumulated earnings 959,995 — — — 959,995 Total stockholders' equity 6,262,625 — 1,222,810 (1,222,810) 6,262,625 Noncontrolling interests in consolidated subsidiary — — — 1,465,953 1,465,953 Total equity 6,262,625 — 1,222,810 243,143 7,728,578 Total liabilities and equity $ 11,924,382 — 2,349,895 (18,727) 14,255,550 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 Investments in subsidiaries (573,926) — — 573,926 — Contingent acquisition consideration 208,014 — — (208,014) — Investments in unconsolidated affiliates — — 303,302 — 303,302 Other assets, net 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
Schedule of condensed consolidated statement of operations and comprehensive income (loss)	Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ 1,039,892 — — — 1,039,892 Natural gas liquids sales 264,483 — — — 264,483 Oil sales 70,753 — — — 70,753 Gathering, compression, water handling and treatment 6,651 — 299,787 (284,438) 22,000 Marketing 176,229 — — — 176,229 Commodity derivative fair value gains 2,381,501 — — — 2,381,501 Other income 4,594 — — (4,594) — Total revenue and other 3,944,103 — 299,787 (289,032) 3,954,858 Operating expenses: Lease operating 36,132 — 33,283 (33,404) 36,011 Gathering, compression, processing, and transportation 852,573 — 25,305 (218,517) 659,361 Production and ad valorem taxes 77,074 — 1,251 — 78,325 Marketing 299,062 — — — 299,062 Exploration 3,846 — — — 3,846 Impairment of unproved properties 104,321 — — — 104,321 Depletion, depreciation, and amortization 641,860 — 67,903 — 709,763 Accretion of asset retirement obligations 1,655 — — — 1,655 General and administrative 190,712 — 43,968 (983) 233,697 Contract termination and rig stacking 38,531 — — — 38,531 Accretion of contingent acquisition consideration — — 3,333 (3,333) — Total operating expenses 2,245,766 — 175,043 (256,237) 2,164,572 Operating income 1,698,337 — 124,744 (32,795) 1,790,286 Other expenses: Interest (228,568) — (5,832) — (234,400) Equity in net income of subsidiaries 47,485 — — (47,485) — Total other expenses (181,083) — (5,832) (47,485) (234,400) Income before income taxes 1,517,254 — 118,912 (80,280) 1,555,886 Provision for income tax expense (575,890) — — — (575,890) Net income and comprehensive income including noncontrolling interests 941,364 — 118,912 (80,280) 979,996 Net income and comprehensive income attributable to noncontrolling interests — — — 38,632 38,632 Net income and comprehensive income attributable to Antero Resources Corporation $ 941,364 — 118,912 (118,912) 941,364 Condensed Consolidating Statement of Operations and Comprehensive Income (Loss) 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 Accretion 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 net income of subsidiaries (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 Gathering, compression, water handling and treatment — — 772,497 (759,777) 12,720 Marketing 258,045 — — — 258,045 Commodity derivative fair value gains 636,889 — — — 636,889 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 Accretion 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 net income of subsidiaries (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
Schedule of condensed consolidated statement of cash flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Net cash provided by operating activities $ 917,639 — 195,059 (96,886) 1,015,812 Cash flows used in investing activities: Additions to unproved properties (198,694) — — — (198,694) Drilling and completion costs (1,675,049) — — 23,767 (1,651,282) Additions to water handling and treatment systems (80,064) — (50,987) — (131,051) Additions to gathering systems and facilities (40,285) — (320,002) — (360,287) Additions to other property and equipment (6,595) — — — (6,595) Change in other assets 2,570 — 7,180 — 9,750 Net distributions from guarantor subsidiary (115,000) — — 115,000 — Proceeds from contribution of assets to non-guarantor subsidiary 801,116 — — (801,116) — Proceeds from asset sales 40,000 — — — 40,000 Net cash used in investing activities (1,272,001) — (363,809) (662,349) (2,298,159) Cash flows provided by (used in) financing activities: Issuance of common stock 537,832 — — — 537,832 Issuance of common units by Antero Midstream — — 240,703 — 240,703 Issuance of senior notes 750,000 — — — 750,000 Borrowings (repayments) on bank credit facility, net (908,000) (115,000) 620,000 — (403,000) Payments of deferred financing costs (15,234) — (2,059) — (17,293) Distributions — 115,000 (908,364) 759,235 (34,129) Employee tax withholding for settlement of equity compensation awards (4,625) — (4,806) — (9,431) Other (4,808) — (33) — (4,841) Net cash provided by (used in) financing activities 355,165 — (54,559) 759,235 1,059,841 Net increase (decrease) in cash and cash equivalents 803 — (223,309) — (222,506) Cash and cash equivalents, beginning of period 15,787 — 230,192 — 245,979 Cash and cash equivalents, end of period $ 16,590 — 6,883 — 23,473 Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Cash flows provided by 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 Accretion of contingent acquisition consideration (16,489) — 16,489 — — Impairment of unproved properties 162,935 — — — 162,935 Derivative fair value (gains) losses 514,181 — — — 514,181 Gains on settled derivatives 1,003,083 — — — 1,003,083 Deferred income tax expense (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 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 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 Resources Corporation 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 operating activities: Net income (loss) including noncontrolling interests $ 615,070 — 307,315 (137,248) 785,137 Adjustment to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation, amortization, and accretion 707,658 — 119,562 — 827,220 Accretion 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 Derivative fair value (gains) losses (636,889) — — — (636,889) Gains on settled derivatives 213,940 — — — 213,940 Proceeds from derivative monetizations 749,906 — — — 749,906 Deferred income tax expense (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 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 (used in) 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

Quarterly Financial Informati40

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information (Unaudited)
Schedule of quarterly financial information	The Company’s quarterly consolidated financial information for the years ended December 31, 2016 and 2017 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, 2016: Total operating revenues $ 721,004 $ (249,198) $ 1,116,503 $ 156,216 Total operating expenses 642,255 640,675 649,171 788,225 Operating income (loss) 78,749 (889,873) 467,332 (632,009) Net income (loss) and comprehensive income (loss) including noncontrolling interest 10,650 (575,490) 268,196 (452,804) Net income attributable to noncontrolling interest 15,705 20,754 29,941 32,968 Net income (loss) attributable to Antero Resources Corporation (5,055) (596,244) 238,255 (485,772) Earnings (loss) per common share—basic $ (0.02) $ (2.12) $ 0.78 $ (1.55) Earnings (loss) per common share—assuming dilution $ (0.02) $ (2.12) $ 0.77 $ (1.55) 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 $ 0.85 $ (0.02) $ (0.43) $ 1.54 Earnings (loss) per common share—diluted $ 0.85 $ (0.02) $ (0.43) $ 1.54

Supplemental Information on O41

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2016 2017 Proved properties $ 9,549,671 11,096,462 Unproved properties 2,331,173 2,266,673 11,880,844 13,363,135 Accumulated depletion and depreciation (2,089,500) (2,783,832) Net capitalized costs $ 9,791,344 10,579,303
Schedule of costs incurred in certain oil and gas activities	Year ended December 31, (In thousands) 2015 2016 2017 Acquisition costs: Proved property $ — 134,113 175,650 Unproved property 198,694 611,631 204,272 Development costs 1,039,301 1,000,903 897,287 Exploration costs 611,981 326,856 384,698 Total costs incurred $ 1,849,976 2,073,503 1,661,907
Schedule of results of operations (including discontinued operations) for oil and gas producing activities	Year ended December 31, (In thousands) 2015 2016 2017 Revenues $ 1,375,128 1,755,061 2,747,920 Operating expenses: Production expenses 773,697 999,516 1,279,217 Exploration expenses 3,846 6,862 8,538 Depletion and depreciation 614,700 700,274 694,332 Impairment of unproved properties 104,321 162,935 159,598 Results of operations before income tax expense (121,436) (114,526) 606,235 Income tax (expense) benefit 45,497 43,334 (228,096) Results of operations $ (75,939) (71,192) 378,139
Schedule of proved developed and undeveloped reserves	Natural NGLs Oil and Equivalents Proved reserves: December 31, 2014 10,535 330 28 12,683 Revisions (2,816) 176 (8) (1,801) Extensions, discoveries and other additions 2,253 97 8 2,878 Production (439) (16) (2) (545) 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 677 (7) (4) 613 Extensions, discoveries and other additions 1,309 62 5 1,711 Production (591) (36) (2) (822) Purchases of reserves 289 13 1 373 December 31, 2017 11,098 989 38 17,261 Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2015 3,627 360 8 5,838 December 31, 2016 4,426 401 13 6,914 December 31, 2017 5,587 467 16 8,488 Proved undeveloped reserves: December 31, 2015 5,906 227 18 7,377 December 31, 2016 4,988 556 25 8,472 December 31, 2017 5,511 522 22 8,773
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	Year ended December 31, (in millions) 2015 2016 2017 Future cash inflows $ 35,179 36,800 55,824 Future production costs (17,393) (21,275) (26,375) Future development costs (5,217) (3,902) (3,312) Future net cash flows before income tax 12,569 11,623 26,137 Future income tax expense (1,708) (1,042) (4,104) Future net cash flows 10,861 10,581 22,033 10% annual discount for estimated timing of cash flows (7,628) (7,294) (13,406) Standardized measure of discounted future net cash flows $ 3,233 3,287 8,627
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	December 31, 2015 $ 2.66 December 31, 2016 $ 2.39 December 31, 2017 $ 3.23
Schedule of changes in standardized measure of discounted future net cash flow	Year ended December 31, (in millions) 2015 2016 2017 Sales of oil and gas, net of productions costs $ (601) (756) (1,469) Net changes in prices and production costs (9,416) (1,540) 3,918 Development costs incurred during the period 769 733 627 Net changes in future development costs 671 212 229 Extensions, discoveries and other additions 861 673 1,195 Acquisitions — 66 258 Divestitures — (7) — Revisions of previous quantity estimates (1,167) 461 987 Accretion of discount 1,132 363 368 Net change in income taxes 3,284 12 (1,159) Other changes 65 (163) 386 Net increase (decrease) (4,402) 54 5,340 Beginning of year 7,635 3,233 3,287 End of year $ 3,233 3,287 8,627

Summary of Significant Accoun42

Summary of Significant Accounting Policies - Principles of Consolidation (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)segmentCounterparty	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 1,300,000
Number of counterparties | Counterparty	14
Industry Segment and Geographic Information
Number of operating segments | segment	4
Basis of Presentation
Proceeds from issuance of stock		$ 1,012,431	$ 537,832
Term of contract with Antero Midstream	20 years
Morgan Stanley
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 285,000
JP Morgan
Derivative Financial Instruments
Fair value of commodity derivative contracts	288,000
Citigroup
Derivative Financial Instruments
Fair value of commodity derivative contracts	245,000
Wells Fargo
Derivative Financial Instruments
Fair value of commodity derivative contracts	136,000
Scotiabank
Derivative Financial Instruments
Fair value of commodity derivative contracts	171,000
BNP Paribas
Derivative Financial Instruments
Fair value of commodity derivative contracts	30,000
Toronto Dominion Bank
Derivative Financial Instruments
Fair value of commodity derivative contracts	38,000
Canadian Imperial Bank of Commerce
Derivative Financial Instruments
Fair value of commodity derivative contracts	51,000
Fifth Third Bank
Derivative Financial Instruments
Fair value of commodity derivative contracts	15,000
Bank of Montreal
Derivative Financial Instruments
Fair value of commodity derivative contracts	21,000
SunTrust
Derivative Financial Instruments
Fair value of commodity derivative contracts	9,000
Capital One
Derivative Financial Instruments
Fair value of commodity derivative contracts	6,000
Natixis
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 7,000
Antero Midstream Partners LP
Basis of Presentation
Antero Resources ownership in Antero Midstream	52.90%	60.90%
Antero Midstream Partners LP
Basis of Presentation
Antero Resources ownership in Antero Midstream	52.90%

Summary of Significant Accoun43

Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings per share
Basic weighted average number of shares outstanding	315,426	294,945	274,123
Diluted weighted average number of shares outstanding	316,283	294,945	274,143
U.S. Statutory federal income tax rate (as a percent)	35.00%	35.00%	35.00%
Employee tax withholding for settlement of equity compensation awards	$ (24,174)	$ (26,895)	$ (9,431)
Restricted stock and restricted stock unit
Earnings per share
Add: Dilutive effect of non-vested restricted stock units	817		20
Weighted Average Anti-dilutive Awards	1,521	6,740	2,264
Stock options
Earnings per share
Weighted Average Anti-dilutive Awards	676	702	553
Performance share unit awards
Earnings per share
Add: Dilutive effect of non-vested restricted stock units	40
Weighted Average Anti-dilutive Awards	1,054	659

Summary of Significant Accoun44

Summary of Significant Accounting Policies - Property and equipment (Details)	12 Months Ended			24 Months Ended
	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2016USD ($)
Property and Equipment
Depreciation expense	$ 824,610,000	$ 809,873,000	$ 709,763,000
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	160,000,000	163,000,000	104,000,000
Impairment of proved properties	0			$ 0
Depreciation, depletion, and amortization expense for oil and gas properties	694,000,000	700,000,000	615,000,000
Asset Impairment Charges	$ 23,431,000			$ 0
Time period that payment is generally received after sale has occurred	1 month
Number of imbalance positions | item	0
Deferred Financing Costs
Unamortized deferred financing costs included in long-term debt	$ 41,000,000
Unamortized deferred financing costs included in other assets	23,000,000
Amounts amortized and the write-off of previously deferred debt issuance costs	$ 13,000,000	16,000,000	10,000,000
Gathering Systems and Facilities
Property and Equipment
Estimated useful life	P20Y
Other property and equipment
Property and Equipment
Depreciation expense	$ 10,000,000	8,900,000	7,700,000
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	$ 120,000,000	$ 101,000,000	$ 87,000,000
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 Accoun45

Summary of Significant Accounting Policies - Credit Risk (Details) - Sales - Customer concentration	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Concentrations of Credit Risk
Sales to major customers (as a percent)	100.00%	100.00%	100.00%
Company A
Concentrations of Credit Risk
Sales to major customers (as a percent)	22.00%	29.00%	19.00%
Company B
Concentrations of Credit Risk
Sales to major customers (as a percent)	15.00%	13.00%
Company C
Concentrations of Credit Risk
Sales to major customers (as a percent)	3.00%	2.00%	18.00%
Company D
Concentrations of Credit Risk
Sales to major customers (as a percent)	1.00%	3.00%	13.00%
All others
Concentrations of Credit Risk
Sales to major customers (as a percent)	59.00%	53.00%	50.00%

Antero Midstream Partners LP (D

Antero Midstream Partners LP (Details) $ in Thousands	Sep. 11, 2017USD ($)shares	Feb. 06, 2017USD ($)shares	Mar. 30, 2016USD ($)shares	Sep. 23, 2015USD ($)sharesbbl	Dec. 31, 2017USD ($)shares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Antero Midstream Partners LP
Investments in unconsolidated affiliates					$ 303,302	$ 68,299
Equity in earnings of unconsolidated affiliate					20,194	485
Issuance of common stock						1,012,431	$ 537,832
Consideration:
Amount borrowed on bank credit facility					90,000	(677,000)	$ (403,000)
Equity Transactions
Proceeds From Sale Of Interest In Partnership Unit					311,100	178,000
Antero Midstream Partners LP
Antero Midstream Partners LP
Equity in earnings of unconsolidated affiliate					$ 20,194	$ 485
Antero Resources ownership in Antero Midstream					52.90%
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				176,295,000
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				219,200,000
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					$ 25,500
Aggregate dollar amount of common units available for issuance and sale under equity distribution agreement					250,000
Remaining capacity under equity distribution agreement					$ 157,300
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
Antero Resources ownership in Antero Midstream					52.90%	60.90%
Equity Transactions
Number of Antero Midstream common units sold by Antero Resources (in units) | shares	10,000,000		8,000,000
Proceeds From Sale Of Interest In Partnership Unit	$ 311,000		$ 178,000

Equity Method Investments (Deta

Equity Method Investments (Details) - USD ($) $ in Thousands	Feb. 06, 2017	Dec. 31, 2017	Dec. 31, 2016
Investments in unconsolidated affiliates
Equity in earnings of unconsolidated affiliate		$ 20,194	$ 485
Distributions from unconsolidated affiliates		(20,195)	(7,702)
Antero Midstream Partners LP
Investments in unconsolidated affiliates
Balance at beginning of period		68,299
Investments		235,004	75,516
Equity in earnings of unconsolidated affiliate		20,194	485
Distributions from unconsolidated affiliates		(20,195)	(7,702)
Balance at end of period		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		68,299
Investments			$ 75,516
Equity in earnings of unconsolidated affiliate		10,304	485
Distributions from unconsolidated affiliates		(11,475)	(7,702)
Balance at end of period		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
Investments		235,004
Equity in earnings of unconsolidated affiliate		9,890
Distributions from unconsolidated affiliates		(8,720)
Balance at end of period		$ 236,174
Antero Midstream Partners LP | MarkWest | Appalachia joint venture
Equity Method Investments
Ownership percentage	50.00%

Sales of Assets (Details)

Sales of Assets (Details) a in Thousands, $ in Thousands	Dec. 16, 2016USD ($)a	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Proceeds from asset sales		$ 2,156	$ 171,830	$ 40,000
Gain Loss On Sale Of Other Assets			$ 97,635
Pennsylvania Leasehold Acreage
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Proceeds from asset sales	$ 169,800
Gain Loss On Sale Of Other Assets	$ 99,000
Area of land sold | a	17

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accrued Liabilities
Accrued capital expenditures	$ 155,300	$ 159,811
Accrued gathering, compression, processing, and transportation expenses	88,850	75,223
Accrued marketing expenses	59,049	52,822
Accrued interest expense	40,861	35,533
Other accrued liabilities	99,165	70,414
Total accrued liabilities	$ 443,225	$ 393,803

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	12 Months Ended
	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	$ 1,520	$ 1,749
Net unamortized debt issuance costs	(32,430)	(37,690)
Long-term debt	4,800,090	4,703,973
Loss on Early Extinguishment of Debt	(1,500)	(16,956)
Antero Midstream Partners LP
Long- term Debt
Net unamortized debt issuance costs	(9,000)	(10,086)
Midstream Credit Facility | Antero Midstream Partners LP
Long- term Debt
Bank credit facility long-term debt	555,000	$ 210,000
Maximum amount of the Credit Facility	$ 1,500,000
Amount of reduction in applicable margin rates during an investment grade period	0.25%
Weighted average interest rate (as a percent)	2.81%	2.23%
Midstream Credit Facility | Minimum | Antero Midstream Partners LP
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%
Midstream Credit Facility | Maximum | Antero Midstream Partners LP
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%
Credit Facility
Long- term Debt
Bank credit facility long-term debt	$ 185,000	$ 440,000
Current borrowing base	4,500,000
Lender commitments	$ 2,500,000
Time period prior to maturity date of senior notes as one option for maturity date of Credit Facility	91 days
Weighted average interest rate (as a percent)	2.96%	2.44%
Outstanding letters of credit	$ 705,000	$ 710,000
Credit Facility | Minimum
Long- term Debt
Rate percentage during an Investment Grade Period lower than rates during a period that is not an Investment Grade Period	0.125%
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 | Maximum
Long- term Debt
Rate percentage during an Investment Grade Period lower than rates during a period that is not an Investment Grade Period	0.50%
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%
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	102.688%
Redemption price at which notes may be required to be repurchased in event of change of control	101.00%
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
Outstanding balance	$ 0	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	103.844%
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 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 Before June 1, 2018
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)	105.625%
5.625% senior notes due 2023 | On or after June 1, 2018
Long- term Debt
Redemption price	104.219%
5.625% senior notes due 2023 | On Or After June 1, 2021
Long- term Debt
Redemption price	100.00%
5.625% senior notes due 2023 | Prior to June 1, 2018
Long- term Debt
Redemption price	100.00%
5.375% senior notes due 2024 | Antero Midstream Partners LP
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%
5.375% senior notes due 2024 | On or after September 15, 2019 | Antero Midstream Partners LP
Long- term Debt
Redemption price	104.031%
5.375% senior notes due 2024 | On or after September 15, 2022 | Antero Midstream Partners LP
Long- term Debt
Redemption price	100.00%
5.375% senior notes due 2024 | Prior to September 15, 2019 | Antero Midstream Partners LP
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%
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%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 32,736	$ 30,612
Obligations settled	(22)
Obligations incurred for wells drilled and producing properties acquired	4,044	4,487
Revisions to prior estimates	(4,758)	(4,836)
Accretion expense	2,610	2,473	$ 1,655
Asset retirement obligations - end of period	$ 34,610	$ 32,736	$ 30,612

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock-based compensation expense
Number of stock-based compensation awards authorized	16,906,500
Number of shares available for future grant under the Plan	8,402,389
Equity based compensation expense recognized	$ 103,445	$ 102,421	$ 97,877
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	7,864,621
Profits interests awards
Stock-based compensation expense
Equity based compensation expense recognized			37,620
Restricted stock awards
Stock-based compensation expense
Equity based compensation expense recognized	$ 70,866	73,081	40,663
Performance share unit awards
Stock-based compensation expense
Equity based compensation expense recognized	10,797	8,685
Stock options
Stock-based compensation expense
Equity based compensation expense recognized	2,375	2,578	2,155
Antero Midstream Partners Phantom Unit Awards
Stock-based compensation expense
Equity based compensation expense recognized	17,461	16,095	17,126
Equity awards issued to directors
Stock-based compensation expense
Equity based compensation expense recognized	$ 1,946	$ 1,982	$ 313

Equity-Based Compensation - Res

Equity-Based Compensation - Restricted Stock and RSU Awards (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Weighted average grant date fair value
Granted (in dollars per share)	$ 26.21
Restricted stock awards
Number of shares
Total granted and unvested at the beginning of the period (in shares) | shares	5,353,447
Granted (in shares) | shares	846,023
Vested (in shares) | shares	(2,301,180)
Forfeited (in shares) | shares	(474,206)
Total awarded and unvested at the end of the period (in shares) | shares	3,424,084
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share)	$ 31.77
Granted (in dollars per share)	22.17
Vested (in dollars per share)	34.35
Forfeited (in dollars per share)	25.66
Total awarded and unvested at the end of the period (in dollars per share)	$ 28.51
Aggregate intrinsic value
Total awarded and unvested at the beginning of the period | $	$ 126,609
Total awarded and unvested at the end of the period | $	65,058
Additional equity compensation to be recognized over the remaining period | $	$ 66,300
Weighted average period for recognizing unrecognized stock-based compensation expense	1 year 8 months 12 days

Equity-Based Compensation - Sto

Equity-Based Compensation - Stock Options (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted-average assumptions used to calculate fair value of stock options granted
Volatility (as a percent)	42.00%
Risk-free interest rate (as a percent)	1.40%
Stock options
Stock options
Outstanding at the beginning of the period (in shares)	687,929
Options forfeited (in shares)	(27,417)
Outstanding at the end of the period (in shares)	660,512	687,929
Vested or expected to vest (in shares)	660,512
Exercisable (in shares)	373,772
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 50.46
Options forfeited (in dollars per share)	50
Outstanding at the end of the period (in dollars per share)	50.48	$ 50.46
Vested or expected to vest (in dollars per share)	50.48
Exercisable (in dollars per share)	$ 50.85
Weighted average remaining contractual life
Outstanding	7 years 22 days	8 years 1 month 13 days
Vested or expected to vest	7 years 22 days
Exercisable	6 years 10 months 17 days
Weighted-average assumptions used to calculate fair value of stock options granted
Dividend yield (as a percent)	0.00%
Volatility (as a percent)			40.00%
Risk-free interest rate (as a percent)			1.66%
Expected life			6 years 3 months
Weighted average fair value of options granted (in dollars per share)			$ 14.74
Additional disclosures
Unrecognized stock-based compensation expense	$ 2.7
Weighted average period for recognizing unrecognized stock-based compensation expense	1 year 3 months 18 days
Stock options | Minimum
Stock-based compensation
Vesting period	1 year
Stock options | Maximum
Stock-based compensation
Vesting period	4 years
Contractual life	10 years

Equity-Based Compensation - PSU

Equity-Based Compensation - PSU awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Weighted average grant date fair value
Granted (in dollars per share)	$ 26.21
Weighted-average assumptions used to calculate fair value of performance share units granted
Volatility (as a percent)	42.00%
Risk-free interest rate (as a percent)	1.40%
Weighted average fair value of awards granted (in dollars per share)	$ 26.21
Performance share unit awards
Number of units
Total granted and unvested at the beginning of the period (in shares)	785,301
Granted (in shares)	558,021
Vested (in shares)	(41,666)
Forfeited (in shares)	(17,813)
Total awarded and unvested at the end of the period (in shares)	1,283,843	785,301
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share)	$ 29.75
Granted (in dollars per share)	26.21	$ 29.77
Vested (in dollars per share)	27.38
Forfeited (in dollars per share)	29.74
Total awarded and unvested at the end of the period (in dollars per share)	$ 28.29	$ 29.75
Additional disclosures
Additional equity compensation to be recognized over the remaining period	$ 18
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)		45.00%
Risk-free interest rate (as a percent)		1.01%
Weighted average fair value of awards granted (in dollars per share)	$ 26.21	$ 29.77
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
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%
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%

Equity-Based Compensation - Pha

Equity-Based Compensation - Phantom Unit Awards (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Weighted average grant date fair value
Granted (in dollars per share)	$ 26.21
Antero Midstream Partners Phantom Unit Awards
Number of units
Total granted and unvested at the beginning of the period (in shares) | shares	1,331,961
Granted (in shares) | shares	377,660
Vested (in shares) | shares	(558,525)
Forfeited (in shares) | shares	(108,133)
Total awarded and unvested at the end of the period (in shares) | shares	1,042,963
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share)	$ 27.31
Granted (in dollars per share)	32.52
Vested (in dollars per share)	28
Forfeited (in dollars per share)	28.63
Total awarded and unvested at the end of the period (in dollars per share)	$ 28.69
Aggregate intrinsic value
Outstanding at the beginning of the period | $	$ 41,131
Outstanding at the end of the period | $	30,288
Additional equity compensation to be recognized over the remaining period | $	$ 25,000
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years

Financial Instruments (Details)

Financial Instruments (Details) - Recurring - Level 2 market data - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Financial Instruments
Fair value of senior notes	$ 3,500
Antero Midstream Partners LP
Financial Instruments
Fair value of senior notes	$ 670	$ 657

Derivative Instruments - Commod

Derivative Instruments - Commodity derivatives (Details) - Swaps	Dec. 31, 2017bbl / dMMBTU / d$ / bbl$ / gal$ / MMBTU
Natural gas | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Natural gas | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Natural gas | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Natural gas | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Natural gas | NYMEX | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Weighted average index price | $ / MMBTU	3.60
Natural gas | NYMEX | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Weighted average index price | $ / MMBTU	3.42
Natural gas | NYMEX | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Weighted average index price | $ / MMBTU	3.45
Natural gas | NYMEX | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,002,500
Weighted average index price | $ / MMBTU	3.53
Natural gas | NYMEX | Year ending December 31, 2019
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	2,330,000
Weighted average index price | $ / MMBTU	3.50
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 | $ / MMBTU	3.25
Natural gas | NYMEX | Year Ending December 31, 2021
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	710,000
Weighted average index price | $ / MMBTU	3
Natural gas | NYMEX | Year ending December 31, 2022
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	850,000
Weighted average index price | $ / MMBTU	3
Natural gas | NYMEX | Year ending December 31, 2023
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | MMBTU / d	90,000
Weighted average index price | $ / MMBTU	2.91
Natural gas liquids | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Natural gas liquids | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Natural gas liquids | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Natural gas liquids | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Propane | Mont Belvieu-Propane | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Weighted average index price | $ / gal	0.75
Propane | Mont Belvieu-Propane | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Weighted average index price | $ / gal	0.75
Propane | Mont Belvieu-Propane | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Weighted average index price | $ / gal	0.75
Propane | Mont Belvieu-Propane | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	19,000
Weighted average index price | $ / gal	0.75
Oil | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Oil | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Oil | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Oil | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Oil | WTI-NYMEX member | Three months ending March 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Weighted average index price | $ / bbl	55.97
Oil | WTI-NYMEX member | Three months ended June 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Weighted average index price | $ / bbl	55.97
Oil | WTI-NYMEX member | Three months ending September 30, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Weighted average index price | $ / bbl	55.97
Oil | WTI-NYMEX member | Three months ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	4,000
Weighted average index price | $ / bbl	55.97

Derivative Instruments - Fair v

Derivative Instruments - Fair value (Details) $ in Thousands	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 460,685	$ 73,022
Noncurrent portion of fair value of derivative assets	841,257	1,731,063
Total asset derivatives	1,301,942	1,804,085
Current portion of fair value of derivative liabilities	28,476	203,635
Noncurrent portion of fair value of derivative liabilities	207	234
Total liability derivatives	28,683	203,869
Net derivatives	$ 1,273,259	$ 1,600,216
Derivatives designated as hedges for accounting purposes
Fair value of derivative instruments
Number of derivative instruments held designated as hedges | item	0

Derivative Instruments - Assets

Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity derivative assets
Gross amounts on balance sheet	$ 1,367,495	$ 1,914,245
Gross amounts offset on balance sheet	(65,553)	(110,160)
Total asset derivatives	1,301,942	1,804,085
Commodity derivative liabilities
Gross amounts on balance sheet	(339,825)	(324,667)
Gross amounts offset on balance sheet	311,142	120,798
Total liability derivatives	$ (28,683)	$ (203,869)

Derivative Instruments - Fair61

Derivative Instruments - Fair value gains (losses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)	$ 636,889	$ (514,181)	$ 2,381,501
Commodity derivative fair value gains (losses) on derivatives monetized prior to settlement dates	750,000
Derivative liabilities
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)	(21,400)
Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)	636,889	$ (514,181)	$ 2,381,501
Commodity derivative fair value gains (losses)
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains (losses)	$ (21,400)

Contract Termination and Rig 62

Contract Termination and Rig Stacking (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Contract Termination and Idle Equip
Contract Termination And Rig Stacking	$ 0	$ 0	$ 38,531

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income tax expense from continuing operations
Current income tax expense (benefit)		$ 75	$ (10,984)
Deferred income tax expense (benefit)		(295,126)	(485,392)	$ 575,890
Total income tax expense from continuing operations		$ (295,051)	$ (496,376)	$ 575,890
U.S. Statutory federal income tax rate (as a percent)		35.00%	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		$ 171,530	$ (436,038)	$ 544,560
State income tax expense , net of federal benefit		10,779	(20,364)	26,983
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		(427,962)
Nondeductible stock compensation		12,098	3,691	16,441
Noncontrolling interest in Antero Midstream Partners LP		(59,523)	(34,780)	(13,521)
Change in valuation allowance		(2,073)	(10,852)	570
Other		100	1,967	857
Total income tax expense from continuing operations		(295,051)	(496,376)	575,890
Income tax expense (benefit) allocated to continuing and discontinued operations
Total income tax expense from continuing operations		(295,051)	(496,376)	$ 575,890
Deferred tax assets:
Net operating loss carryforwards		727,522	495,275
Equity based compensation		12,062	20,344
Investment in Antero Midstream Partners LP		38,613	13,028
Other		11,236	16,483
Total deferred tax assets		789,433	545,130
Valuation allowance		(17,361)	(16,357)
Net deferred tax assets		772,072	528,773
Deferred tax liabilities:
Unrealized gains on derivative instruments		442,855	605,487
Oil and gas properties		1,058,543	866,003
Other		50,319	7,500
Total deferred tax liabilities		1,551,717	1,478,990
Net deferred tax liabilities		$ (779,645)	$ (950,217)
Scenario Forecast
Income tax expense from continuing operations
U.S. Statutory federal income tax rate (as a percent)	21.00%

Income Taxes - Unrecognized tax

Income Taxes - Unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unrecognized tax benefits
Balance at beginning of year	$ 0	$ 11,000	$ 11,000
Reductions for tax positions of prior years	0	(11,000)	0
Balance at end of year	0	$ 0	$ 11,000
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, 2017	Dec. 31, 2016	Dec. 31, 2015
Future minimum payments
2,018	$ 1,388
2,019	1,497
2,020	1,477
2,021	1,439
2,022	1,382
Thereafter	11,283
Total	18,466
Firm transportation
Future minimum payments
2,018	866
2,019	1,087
2,020	1,106
2,021	1,085
2,022	1,033
Thereafter	9,544
Total	14,721
Gas processing, gathering and compression
Future minimum payments
2,018	427
2,019	357
2,020	361
2,021	345
2,022	341
Thereafter	1,683
Total	3,514
Drilling rigs and completion services
Future minimum payments
2,018	81
2,019	42
Total	123
Office and equipment
Future minimum payments
2,018	14
2,019	11
2,020	10
2,021	9
2,022	8
Thereafter	56
Total	108
Commitments
Rental expense under operating leases	$ 7	$ 9	$ 9

Contingencies (Details)

Contingencies (Details) $ in Millions	Feb. 01, 2018MMBTU / d	Jan. 31, 2018MMBTU / d	Nov. 30, 2017MMBTU / d	Dec. 31, 2017USD ($)MMBTU / dcontractlawsuit	Jan. 31, 2018MMBTU / d	Mar. 31, 2017USD ($)
SJGC
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day				80,000
WGL
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day	200,000	500,000
Natural gas long term purchase contract volume increase after specified events (in MMBtu)/day	330,000
Natural gas long term purchase contract volume after specified events (in MMBtu)/day	530,000
WGL | Pending Litigation | Minimum
Contingencies
Damages sought | $						$ 30
Potential Positive Outcome of Litigation | SJGC
Contingencies
Number of lawsuits | lawsuit				2
Number of long term gas contracts | contract				2
Additional accounts receivable | $				$ 76
Time period from the entry of final judgment to file an appeal				30 days
Potential Positive Outcome of Litigation | WGL
Contingencies
Natural gas long term purchase contract volume (in MMBtu)/day			600,000		500,000
Additional accounts receivable | $				$ 101

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sales and revenues:
Sales and revenues	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 156,216	$ 1,116,503	$ (249,198)	$ 721,004	$ 3,655,574	$ 1,744,525	$ 3,954,858
Operating expenses:
Lease operating									89,057	50,090	36,011
Gathering, compression, processing, and transportation									1,095,639	882,838	659,361
Depletion, depreciation, and amortization									824,610	809,873	709,763
General and administrative expense									251,196	239,324	233,697
Total operating expenses	834,667	719,932	666,646	694,236	788,225	649,171	640,675	642,255	2,915,481	2,720,326	2,164,572
Operating income (loss)	187,059	$ (72,052)	$ 123,743	$ 501,343	(632,009)	$ 467,332	$ (889,873)	$ 78,749	740,093	(975,801)	1,790,286
Equity in earnings of unconsolidated affiliate									20,194	485
Segment assets	15,261,490				14,255,550				15,261,490	14,255,550
Exploration and production
Sales and revenues:
Sales and revenues									3,423,561	1,352,980	3,761,424
Gathering and compression
Sales and revenues:
Sales and revenues									396,466	307,944	230,592
Operating expenses:
Equity in earnings of unconsolidated affiliate									20,194	485
Water handling and treatment
Sales and revenues:
Sales and revenues									376,031	282,267	156,732
Marketing
Sales and revenues:
Sales and revenues									236,651	393,049	176,229
Operating segments
Sales and revenues:
Sales and revenues									3,655,574	1,744,525	3,954,858
Operating expenses:
Lease operating									89,057	50,090	36,011
Gathering, compression, processing, and transportation									1,095,639	882,838	659,361
Depletion, depreciation, and amortization									824,610	809,873	709,763
General and administrative expense									251,196	239,324	233,697
Other operating expenses									654,979	738,201	525,740
Total operating expenses									2,915,481	2,720,326	2,164,572
Operating income (loss)									740,093	(975,801)	1,790,286
Segment assets	15,261,490				14,255,550				15,261,490	14,255,550	14,115,493
Capital expenditures for segment assets									2,216,753	2,495,429	2,347,909
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues									3,406,203	1,334,656	3,756,629
Operating expenses:
Lease operating									93,758	50,651	35,552
Gathering, compression, processing, and transportation									1,441,129	1,146,221	852,573
Depletion, depreciation, and amortization									704,152	709,127	622,379
General and administrative expense									195,153	186,672	183,675
Other operating expenses									261,578	241,755	222,990
Total operating expenses									2,695,770	2,334,426	1,917,169
Operating income (loss)									727,791	(981,446)	1,844,255
Segment assets	13,074,027				12,512,973				13,074,027	12,512,973	12,426,518
Capital expenditures for segment assets									1,859,481	2,220,688	1,954,256
Operating segments | Gathering and compression
Sales and revenues:
Sales and revenues									11,386	16,028	12,353
Operating expenses:
Gathering, compression, processing, and transportation									39,147	28,098	25,305
Depletion, depreciation, and amortization									87,268	70,847	61,552
General and administrative expense									40,337	39,832	40,448
Other operating expenses									23,535	(809)	3,811
Total operating expenses									190,287	137,968	131,116
Operating income (loss)									206,179	169,976	99,476
Segment assets	2,253,163				1,750,354				2,253,163	1,750,354	1,470,691
Capital expenditures for segment assets									346,217	231,044	360,287
Operating segments | Water handling and treatment
Sales and revenues:
Sales and revenues									1,334	792	9,647
Operating expenses:
Lease operating									189,702	136,386	49,859
Depletion, depreciation, and amortization									33,190	29,899	25,832
General and administrative expense									18,475	14,331	10,758
Other operating expenses									17,061	14,401	3,210
Total operating expenses									258,428	195,017	89,659
Operating income (loss)									117,603	87,250	67,073
Segment assets	804,296				615,687				804,296	615,687	525,004
Capital expenditures for segment assets									194,502	188,188	131,051
Operating segments | Marketing
Sales and revenues:
Sales and revenues									236,651	393,049	176,229
Operating expenses:
Other operating expenses									366,281	499,343	299,062
Total operating expenses									366,281	499,343	299,062
Operating income (loss)									(129,630)	(106,294)	(122,833)
Segment assets	36,701				37,890				36,701	37,890	16,123
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues									(777,135)	(591,715)	(370,119)
Operating expenses:
Lease operating									(194,403)	(136,947)	(49,400)
Gathering, compression, processing, and transportation									(384,637)	(291,481)	(218,517)
General and administrative expense									(2,769)	(1,511)	(1,184)
Other operating expenses									(13,476)	(16,489)	(3,333)
Total operating expenses									(595,285)	(446,428)	(272,434)
Operating income (loss)									(181,850)	(145,287)	(97,685)
Segment assets	$ (906,697)				$ (661,354)				(906,697)	(661,354)	(322,843)
Capital expenditures for segment assets									(183,447)	(144,491)	(97,685)
Elimination of intersegment transaction | Exploration and production
Sales and revenues:
Sales and revenues									17,358	18,324	4,795
Elimination of intersegment transaction | Gathering and compression
Sales and revenues:
Sales and revenues									385,080	291,916	218,239
Elimination of intersegment transaction | Water handling and treatment
Sales and revenues:
Sales and revenues									$ 374,697	$ 281,475	$ 147,085

Condensed Consolidating Finan68

Condensed Consolidating Financial Information - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 28,441	$ 31,610	$ 23,473	$ 245,979
Accounts receivable, net	34,896	29,682
Accrued revenue	300,122	261,960
Derivative instruments	460,685	73,022
Other current assets	8,943	6,313
Total current assets	833,087	402,587
Unproved properties	2,266,673	2,331,173
Proved properties	11,096,462	9,549,671
Water handling and treatment systems	946,670	744,682
Gathering systems and facilities	2,050,490	1,723,768
Other property and equipment	57,429	41,231
Property and equipment, gross	16,417,724	14,390,525
Less accumulated depletion, depreciation, and amortization	(3,182,171)	(2,363,778)
Property and equipment, net	13,235,553	12,026,747
Derivative instruments	841,257	1,731,063
Investments in unconsolidated affiliates	303,302	68,299
Other assets, net	48,291	26,854
Total assets	15,261,490	14,255,550
Liabilities and Stockholders' Equity
Accounts payable	62,982	38,627
Accrued liabilities	443,225	393,803
Revenue distributions payable	209,617	163,989
Derivative Liability, Current	28,476	203,635
Other current liabilities	17,796	17,334
Total current liabilities	762,096	817,388
Long-term debt	4,800,090	4,703,973
Deferred income tax liability	779,645	950,217
Derivative instruments	207	234
Other liabilities	43,316	55,160
Total liabilities	6,385,354	6,526,972
Common stock	3,164	3,149
Additional paid-in capital	6,570,952	5,299,481
Accumulated earnings	1,575,065	959,995
Total stockholders' equity	8,149,181	6,262,625
Noncontrolling interest in consolidated subsidiary	726,955	1,465,953
Total equity	8,876,136	7,728,578	7,286,678	5,473,830
Total liabilities and equity	15,261,490	14,255,550
Reportable legal entity | Parent
Current assets:
Cash and cash equivalents	20,078	17,568	16,590	15,787
Accounts receivable, net	33,726	28,442
Intercompany receivables	6,459	3,193
Accrued revenue	300,122	261,960
Derivative instruments	460,685	73,022
Other current assets	8,273	5,784
Total current assets	829,343	389,969
Unproved properties	2,266,673	2,331,173
Proved properties	11,460,615	9,726,957
Gathering systems and facilities	17,929	17,929
Other property and equipment	57,429	41,231
Property and equipment, gross	13,802,646	12,117,290
Less accumulated depletion, depreciation, and amortization	(2,812,851)	(2,109,136)
Property and equipment, net	10,989,795	10,008,154
Derivative instruments	841,257	1,731,063
Investment in subsidiaries	(573,926)	(420,429)
Contingent acquisition consideration asset	208,014	194,538
Other assets, net	35,371	21,087
Total assets	12,329,854	11,924,382
Liabilities and Stockholders' Equity
Accounts payable	54,340	21,648
Intercompany payable	110,182	64,139
Accrued liabilities	338,819	332,162
Revenue distributions payable	209,617	163,989
Derivative Liability, Current	28,476	203,635
Other current liabilities	17,587	17,134
Total current liabilities	759,021	802,707
Long-term debt	3,604,090	3,854,059
Deferred income tax liability	779,645	950,217
Derivative instruments	207	234
Other liabilities	42,906	54,540
Total liabilities	5,185,869	5,661,757
Common stock	3,164	3,149
Additional paid-in capital	5,565,756	5,299,481
Accumulated earnings	1,575,065	959,995
Total stockholders' equity	7,143,985	6,262,625
Total equity	7,143,985	6,262,625
Total liabilities and equity	12,329,854	11,924,382
Reportable legal entity | Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	8,363	14,042	$ 6,883	$ 230,192
Accounts receivable, net	1,170	1,240
Intercompany receivables	110,182	64,139
Other current assets	670	529
Total current assets	120,385	79,950
Water handling and treatment systems	942,361	744,682
Gathering systems and facilities	2,032,561	1,705,839
Property and equipment, gross	2,974,922	2,450,521
Less accumulated depletion, depreciation, and amortization	(369,320)	(254,642)
Property and equipment, net	2,605,602	2,195,879
Investments in unconsolidated affiliates	303,302	68,299
Other assets, net	12,920	5,767
Total assets	3,042,209	2,349,895
Liabilities and Stockholders' Equity
Accounts payable	8,642	16,979
Intercompany payable	6,459	3,193
Accrued liabilities	106,006	61,641
Other current liabilities	209	200
Total current liabilities	121,316	82,013
Long-term debt	1,196,000	849,914
Contingent acquisition consideration liability	208,014	194,538
Other liabilities	410	620
Total liabilities	1,525,740	1,127,085
Partners' capital	1,516,469	1,222,810
Total stockholders' equity	1,516,469	1,222,810
Total equity	1,516,469	1,222,810
Total liabilities and equity	3,042,209	2,349,895
Eliminations
Current assets:
Intercompany receivables	(116,641)	(67,332)
Total current assets	(116,641)	(67,332)
Proved properties	(364,153)	(177,286)
Water handling and treatment systems	4,309
Property and equipment, gross	(359,844)	(177,286)
Property and equipment, net	(359,844)	(177,286)
Investment in subsidiaries	573,926	420,429
Contingent acquisition consideration asset	(208,014)	(194,538)
Total assets	(110,573)	(18,727)
Liabilities and Stockholders' Equity
Intercompany payable	(116,641)	(67,332)
Accrued liabilities	(1,600)
Total current liabilities	(118,241)	(67,332)
Contingent acquisition consideration liability	(208,014)	(194,538)
Total liabilities	(326,255)	(261,870)
Partners' capital	(1,516,469)	(1,222,810)
Additional paid-in capital	1,005,196
Total stockholders' equity	(511,273)	(1,222,810)
Noncontrolling interest in consolidated subsidiary	726,955	1,465,953
Total equity	215,682	243,143
Total liabilities and equity	$ (110,573)	$ (18,727)

Condensed Consolidating Finan69

Condensed Consolidating Financial Information - Statements of Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended			24 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
Revenue:
Natural gas sales									$ 1,769,284	$ 1,260,750	$ 1,039,892
Natural gas liquids sales									870,441	432,992	264,483
Oil And Condensate Revenue									108,195	61,319	70,753
Gathering, processing, and water handling and treatment									12,720	12,961	22,000
Marketing Revenue									258,045	393,049	176,229
Commodity derivative fair value gains (losses)									636,889	(514,181)	2,381,501
Gain on sale of assets										97,635
Total revenue	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 156,216	$ 1,116,503	$ (249,198)	$ 721,004	3,655,574	1,744,525	3,954,858
Operating expenses:
Lease operating									89,057	50,090	36,011
Gathering, compression, processing, and transportation									1,095,639	882,838	659,361
Production and ad valorem taxes									94,521	66,588	78,325
Marketing									366,281	499,343	299,062
Exploration									8,538	6,862	3,846
Impairment of unproved properties									159,598	162,935	104,321
Asset Impairment Charges									23,431			$ 0
Depletion, depreciation, and amortization									824,610	809,873	709,763
Accretion of asset retirement obligations									2,610	2,473	1,655
General and administrative									251,196	239,324	233,697
Contract Termination And Rig Stacking									0	0	38,531
Total operating expenses	834,667	719,932	666,646	694,236	788,225	649,171	640,675	642,255	2,915,481	2,720,326	2,164,572
Operating income (loss)	187,059	(72,052)	123,743	501,343	(632,009)	467,332	(889,873)	78,749	740,093	(975,801)	1,790,286
Equity in earnings of unconsolidated affiliate									20,194	485
Interest									(268,701)	(253,552)	(234,400)
Gains Losses On Extinguishment Of Debt									(1,500)	(16,956)
Total other expenses									(250,007)	(270,023)	(234,400)
Income (loss) before income taxes									490,086	(1,245,824)	1,555,886
Provision for income tax (expense) benefit									295,051	496,376	(575,890)
Net income (loss) and comprehensive income (loss) including noncontrolling interest	529,614	(90,000)	39,965	305,558	(452,804)	268,196	(575,490)	10,650	785,137	(749,448)	979,996
Net income and comprehensive income attributable to noncontrolling interest	42,745	45,063	45,097	37,162	32,968	29,941	20,754	15,705	170,067	99,368	38,632
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	$ (485,772)	$ 238,255	$ (596,244)	$ (5,055)	615,070	(848,816)	941,364
Eliminations
Revenue:
Natural gas sales									(691)
Gathering, processing, and water handling and treatment									(759,777)	(573,391)	(284,438)
Other income									(16,667)	(18,324)	(4,594)
Total revenue									(777,135)	(591,715)	(289,032)
Operating expenses:
Lease operating									(194,403)	(136,948)	(33,404)
Gathering, compression, processing, and transportation									(384,637)	(291,480)	(218,517)
General and administrative									(2,769)	(1,511)	(983)
Accretion of contingent acquisition consideration									(13,476)	(16,489)	(3,333)
Total operating expenses									(595,285)	(446,428)	(256,237)
Operating income (loss)									(181,850)	(145,287)	(32,795)
Interest									892	796
Equity in net income of subsidiaries									43,710	7,156	(47,485)
Total other expenses									44,602	7,952	(47,485)
Income (loss) before income taxes									(137,248)	(137,335)	(80,280)
Net income (loss) and comprehensive income (loss) including noncontrolling interest									(137,248)	(137,335)	(80,280)
Net income and comprehensive income attributable to noncontrolling interest									170,067	99,368	38,632
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									(307,315)	(236,703)	(118,912)
Parent | Reportable legal entity
Revenue:
Natural gas sales									1,769,975	1,260,750	1,039,892
Natural gas liquids sales									870,441	432,992	264,483
Oil And Condensate Revenue									108,195	61,319	70,753
Gathering, processing, and water handling and treatment											6,651
Marketing Revenue									258,045	393,049	176,229
Commodity derivative fair value gains (losses)									636,889	(514,181)	2,381,501
Gain on sale of assets										93,776
Other income									16,667	18,324	4,594
Total revenue									3,660,212	1,746,029	3,944,103
Operating expenses:
Lease operating									93,758	50,651	36,132
Gathering, compression, processing, and transportation									1,441,129	1,146,221	852,573
Production and ad valorem taxes									90,832	69,485	77,074
Marketing									366,281	499,343	299,062
Exploration									8,538	6,862	3,846
Impairment of unproved properties									159,598	162,935	104,321
Depletion, depreciation, and amortization									705,048	710,012	641,860
Accretion of asset retirement obligations									2,610	2,473	1,655
General and administrative									195,153	186,672	190,712
Contract Termination And Rig Stacking											38,531
Accretion of contingent acquisition consideration									(13,476)	(16,489)
Total operating expenses									3,062,947	2,834,654	2,245,766
Operating income (loss)									597,265	(1,088,625)	1,698,337
Interest									(232,331)	(232,455)	(228,568)
Gains Losses On Extinguishment Of Debt									(1,205)	(16,956)
Equity in net income of subsidiaries									(43,710)	(7,156)	47,485
Total other expenses									(277,246)	(256,567)	(181,083)
Income (loss) before income taxes									320,019	(1,345,192)	1,517,254
Provision for income tax (expense) benefit									295,051	496,376	(575,890)
Net income (loss) and comprehensive income (loss) including noncontrolling interest									615,070	(848,816)	941,364
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									615,070	(848,816)	941,364
Non-Guarantor Subsidiaries | Reportable legal entity
Revenue:
Gathering, processing, and water handling and treatment									772,497	586,352	299,787
Gain on sale of assets										3,859
Total revenue									772,497	590,211	299,787
Operating expenses:
Lease operating									189,702	136,387	33,283
Gathering, compression, processing, and transportation									39,147	28,097	25,305
Production and ad valorem taxes									3,689	(2,897)	1,251
Asset Impairment Charges									23,431
Depletion, depreciation, and amortization									119,562	99,861	67,903
General and administrative									58,812	54,163	43,968
Accretion of contingent acquisition consideration									13,476	16,489	3,333
Total operating expenses									447,819	332,100	175,043
Operating income (loss)									324,678	258,111	124,744
Equity in earnings of unconsolidated affiliate									20,194	485
Interest									(37,262)	(21,893)	(5,832)
Gains Losses On Extinguishment Of Debt									(295)
Total other expenses									(17,363)	(21,408)	(5,832)
Income (loss) before income taxes									307,315	236,703	118,912
Net income (loss) and comprehensive income (loss) including noncontrolling interest									307,315	236,703	118,912
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									$ 307,315	$ 236,703	$ 118,912

Condensed Consolidating Finan70

Condensed Consolidating Financial Information - Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended			24 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2016
Cash flows from operating activities:
Profit Loss	$ 529,614	$ (90,000)	$ 39,965	$ 305,558	$ (452,804)	$ 268,196	$ (575,490)	$ 10,650	$ 785,137	$ (749,448)	$ 979,996
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion Depreciation Amortization And Accretion									827,220	812,346	711,418
Impairment of unproved properties									159,598	162,935	104,321
Asset Impairment Charges									23,431			$ 0
Derivative fair value (gains) losses									(636,889)	514,181	(2,381,501)
Payments For Proceeds From Settled Derivative Instruments Operating Activities									213,940	1,003,083	856,572
Proceeds From Derivative Monetizations									749,906
Deferred income tax expense (benefit)									(295,126)	(485,392)	575,890
Gain on Disposition of Assets										97,635
Equity-based compensation expense									103,445	102,421	97,877
Loss on early extinguishment of debt									1,500	16,956
Income Loss From Equity Method Investments									(20,194)	(485)
Equity Method Investment Dividends Or Distributions									20,195	7,702
Other									(1,907)	(12,488)	31,741
Increase (Decrease) in Operating Capital									76,035	(32,920)
Net cash provided by operating activities									2,006,291	1,241,256	1,015,812
Cash flows used in investing activities:
Additions to proved properties									(175,650)	(134,113)
Additions to unproved properties									(204,272)	(611,631)	(198,694)
Drilling and completion costs									(1,281,985)	(1,327,759)	(1,651,282)
Additions to water handling and treatment systems									(194,502)	(188,188)	(131,051)
Additions to gathering systems and facilities									(346,217)	(231,044)	(360,287)
Additions to other property and equipment									(14,127)	(2,694)	(6,595)
Investments in unconsolidated affiliates									(235,004)	(75,516)
Change in other assets									(12,029)	3,977	9,750
Proceeds from asset sales									2,156	171,830	40,000
Net cash used in investing activities									(2,461,630)	(2,395,138)	(2,298,159)
Cash flows from financing activities:
Issuance of common stock										1,012,431	537,832
Issuance of common units by Antero Midstream Partners LP									248,956	65,395	240,703
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation									311,100	178,000
Issuance of senior notes										1,250,000	750,000
Repayment of senior notes										(525,000)
Borrowings (repayments) on bank credit facility, net									90,000	(677,000)	(403,000)
Make-whole premium on debt extinguished										(15,750)
Payments of deferred financing costs									(16,377)	(18,759)	(17,293)
Distributions to noncontrolling interest in consolidated subsidiary									(152,352)	(75,082)	(34,129)
Employee tax withholding for settlement of equity compensation awards									(24,174)	(26,895)	(9,431)
Other									(4,983)	(5,321)	(4,841)
Net cash provided by financing activities									452,170	1,162,019	1,059,841
Net increase (decrease) in cash and cash equivalents									(3,169)	8,137	(222,506)
Cash and cash equivalents, beginning of period				31,610				23,473	31,610	23,473	245,979	245,979
Cash and cash equivalents, end of period	28,441				31,610				28,441	31,610	23,473	31,610
Eliminations
Cash flows from operating activities:
Profit Loss									(137,248)	(137,335)	(80,280)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Change In Value Of Contingent Consideration									(13,476)	(16,489)	(3,333)
Equity in net income of subsidiaries									(43,710)	(7,156)	47,485
Distributions from non-guarantor subsidiary									(131,598)	(107,364)
Increase (Decrease) in Operating Capital									6,729	9,266
Net cash provided by operating activities									(305,827)	(242,589)	(96,886)
Cash flows used in investing activities:
Drilling and completion costs									173,569	135,225	23,767
Additions to water handling and treatment systems									660
Net distributions (to) from guarantor subsidiary											115,000
Proceeds from contribution of assets to non-guarantor subsidiary											(801,116)
Net cash used in investing activities									174,229	135,225	(662,349)
Cash flows from financing activities:
Distributions to noncontrolling interest in consolidated subsidiary									131,598	107,364	759,235
Net cash provided by financing activities									131,598	107,364	759,235
Parent | Reportable legal entity
Cash flows from operating activities:
Profit Loss									615,070	(848,816)	941,364
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion Depreciation Amortization And Accretion									707,658	712,485
Change In Value Of Contingent Consideration									(13,476)	(16,489)
Impairment of unproved properties									159,598	162,935	104,321
Derivative fair value (gains) losses									(636,889)	514,181	(2,381,501)
Payments For Proceeds From Settled Derivative Instruments Operating Activities									213,940	1,003,083
Proceeds From Derivative Monetizations									749,906
Deferred income tax expense (benefit)									(295,126)	(485,392)
Gain on Disposition of Assets										93,776
Equity-based compensation expense									76,162	76,372
Loss on early extinguishment of debt									1,205	16,956
Equity in net income of subsidiaries									43,710	7,156	(47,485)
Other									(4,500)	(14,302)
Distributions from non-guarantor subsidiary									131,598	107,364
Increase (Decrease) in Operating Capital									87,466	(36,519)
Net cash provided by operating activities									1,836,322	1,105,238	917,639
Cash flows used in investing activities:
Additions to proved properties									(175,650)	(134,113)
Additions to unproved properties									(204,272)	(611,631)	(198,694)
Drilling and completion costs									(1,455,554)	(1,462,984)	(1,675,049)
Additions to water handling and treatment systems										32	(80,064)
Additions to gathering systems and facilities										(2,944)	(40,285)
Additions to other property and equipment									(14,127)	(2,694)	(6,595)
Change in other assets									(8,594)	304	2,570
Net distributions (to) from guarantor subsidiary											(115,000)
Proceeds from contribution of assets to non-guarantor subsidiary											801,116
Proceeds from asset sales									2,156	161,830	40,000
Net cash used in investing activities									(1,856,041)	(2,052,200)	(1,272,001)
Cash flows from financing activities:
Issuance of common stock										1,012,431	537,832
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation									311,100	178,000
Issuance of senior notes										600,000	750,000
Repayment of senior notes										(525,000)
Borrowings (repayments) on bank credit facility, net									(255,000)	(267,000)	(908,000)
Make-whole premium on debt extinguished										(15,750)
Payments of deferred financing costs									(10,857)	(8,324)	(15,234)
Employee tax withholding for settlement of equity compensation awards									(18,229)	(21,260)	(4,625)
Other									(4,785)	(5,157)	(4,808)
Net cash provided by financing activities									22,229	947,940	355,165
Net increase (decrease) in cash and cash equivalents									2,510	978	803
Cash and cash equivalents, beginning of period				17,568				16,590	17,568	16,590	15,787	15,787
Cash and cash equivalents, end of period	20,078				17,568				20,078	17,568	16,590	17,568
Guarantor Subsidiaries | Reportable legal entity
Cash flows from financing activities:
Borrowings (repayments) on bank credit facility, net											(115,000)
Distributions to noncontrolling interest in consolidated subsidiary											115,000
Non-Guarantor Subsidiaries | Reportable legal entity
Cash flows from operating activities:
Profit Loss									307,315	236,703	118,912
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion Depreciation Amortization And Accretion									119,562	99,861
Change In Value Of Contingent Consideration									13,476	16,489	3,333
Asset Impairment Charges									23,431
Gain on Disposition of Assets										3,859
Equity-based compensation expense									27,283	26,049
Loss on early extinguishment of debt									295
Income Loss From Equity Method Investments									(20,194)	(485)
Equity Method Investment Dividends Or Distributions									20,195	7,702
Other									2,593	1,814
Increase (Decrease) in Operating Capital									(18,160)	(5,667)
Net cash provided by operating activities									475,796	378,607	195,059
Cash flows used in investing activities:
Additions to water handling and treatment systems									(195,162)	(188,220)	(50,987)
Additions to gathering systems and facilities									(346,217)	(228,100)	(320,002)
Investments in unconsolidated affiliates									(235,004)	(75,516)
Change in other assets									(3,435)	3,673	7,180
Proceeds from asset sales										10,000
Net cash used in investing activities									(779,818)	(478,163)	(363,809)
Cash flows from financing activities:
Issuance of common units by Antero Midstream Partners LP									248,956	65,395	240,703
Issuance of senior notes										650,000
Borrowings (repayments) on bank credit facility, net									345,000	(410,000)	620,000
Payments of deferred financing costs									(5,520)	(10,435)	(2,059)
Distributions to noncontrolling interest in consolidated subsidiary									(283,950)	(182,446)	(908,364)
Employee tax withholding for settlement of equity compensation awards									(5,945)	(5,635)	(4,806)
Other									(198)	(164)	(33)
Net cash provided by financing activities									298,343	106,715	(54,559)
Net increase (decrease) in cash and cash equivalents									(5,679)	7,159	(223,309)
Cash and cash equivalents, beginning of period				$ 14,042				$ 6,883	14,042	6,883	230,192	230,192
Cash and cash equivalents, end of period	$ 8,363				$ 14,042				$ 8,363	$ 14,042	$ 6,883	$ 14,042

Quarterly Financial Informati71

Quarterly Financial Information (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Total revenue	$ 1,021,726	$ 647,880	$ 790,389	$ 1,195,579	$ 156,216	$ 1,116,503	$ (249,198)	$ 721,004	$ 3,655,574	$ 1,744,525	$ 3,954,858
Total operating expenses	834,667	719,932	666,646	694,236	788,225	649,171	640,675	642,255	2,915,481	2,720,326	2,164,572
Operating income (loss)	187,059	(72,052)	123,743	501,343	(632,009)	467,332	(889,873)	78,749	740,093	(975,801)	1,790,286
Net income (loss) and comprehensive income (loss)	529,614	(90,000)	39,965	305,558	(452,804)	268,196	(575,490)	10,650	785,137	(749,448)	979,996
Net Income (Loss) Attributable to Noncontrolling Interest	42,745	45,063	45,097	37,162	32,968	29,941	20,754	15,705	170,067	99,368	38,632
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 486,869	$ (135,063)	$ (5,132)	$ 268,396	$ (485,772)	$ 238,255	$ (596,244)	$ (5,055)	$ 615,070	$ (848,816)	$ 941,364
Earnings (loss) per common share - basic:
Continuing operations - basic									$ 1.95	$ (2.88)	$ 3.43
Earnings (loss) per common share - basic	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.55)	$ 0.78	$ (2.12)	$ (0.02)
Earnings (loss) per share - diluted:
Continuing operations - diluted									$ 1.94	$ (2.88)	$ 3.43
Earnings (loss) per common share - diluted	$ 1.54	$ (0.43)	$ (0.02)	$ 0.85	$ (1.55)	$ 0.77	$ (2.12)	$ (0.02)

Supplemental Information on O72

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 11,096,462	$ 9,549,671
Unproved properties	2,266,673	2,331,173
Total	13,363,135	11,880,844
Accumulated depletion and depreciation	(2,783,832)	(2,089,500)
Net capitalized costs	10,579,303	9,791,344
Costs Incurred in Certain Oil and Gas Activities
Proved property	175,650	134,113
Unproved property	204,272	611,631	$ 198,694
Development costs	897,287	1,000,903	1,039,301
Exploration costs	384,698	326,856	611,981
Total costs incurred	1,661,907	2,073,503	1,849,976
Results of Operations for Oil and Gas Producing Activities
Revenues	2,747,920	1,755,061	1,375,128
Operating expenses:
Production expenses	1,279,217	999,516	773,697
Exploration expenses	8,538	6,862	3,846
Depletion and depreciation	694,332	700,274	614,700
Impairment of unproved properties	159,598	162,935	104,321
Results of operations before income tax expense (benefit)	606,235	(114,526)	(121,436)
Income tax expense	(228,096)	43,334	45,497
Results of operations	$ 378,139	$ (71,192)	$ (75,939)

Supplemental Information on O73

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details) MMcfe in Thousands	12 Months Ended
	Dec. 31, 2017MMcfeBcfMMBbls	Dec. 31, 2016MMcfeBcfMMBbls	Dec. 31, 2015MMcfeBcfMMBbls
Proved developed and undeveloped reserves:
Balance at the beginning of the period | MMcfe	15,386	13,215	12,683
Revisions | MMcfe	613	(404)	(1,801)
Extensions, discoveries and other additions | MMcfe	1,711	2,637	2,878
Increase (decrease) in proved reserves resulting from price revisions | MMcfe	132	(47)	(202)
Production | MMcfe	(822)	(676)	(545)
Purchase of reserves | MMcfe	373	624
Sales of reserves in place | MMcfe		(10)
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MMcfe	17,261	15,386	13,215
Oil and Gas Reserves
Proved developed reserves | MMcfe	8,488	6,914	5,838
Proved undeveloped reserves | MMcfe	8,773	8,472	7,377
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	9,414	9,533	10,535
Revisions | Bcf	677	(2,069)	(2,816)
Extensions, discoveries and other additions | Bcf	1,309	1,990	2,253
Production | Bcf	(591)	(505)	(439)
Purchase of reserves | Bcf	289	475
Sales of reserves in place | Bcf		(10)
Balance at the end of the period | Bcf	11,098	9,414	9,533
Oil and Gas Reserves
Proved developed reserves | Bcf	5,587	4,426	3,627
Proved undeveloped reserves | Bcf	5,511	4,988	5,906
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	957	587	330
Revisions	(7)	275	176
Extensions, discoveries and other additions	62	99	97
Production	(36)	(27)	(16)
Purchase of reserves	13	23
Balance at the end of the period	989	957	587
Oil and Gas Reserves
Proved developed reserves	467	401	360
Proved undeveloped reserves	522	556	227
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	38	26	28
Revisions	(4)	3	(8)
Extensions, discoveries and other additions	5	9	8
Production	(2)	(2)	(2)
Purchase of reserves	1	2
Balance at the end of the period	38	38	26
Oil and Gas Reserves
Proved developed reserves	16	13	8
Proved undeveloped reserves	22	25	18

Supplemental Information on O74

Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Discounted future cash flows (Detail) MMcfe in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMcfe	Dec. 31, 2016USD ($)MMcfe	Dec. 31, 2015USD ($)MMcfebbl	Dec. 31, 2014USD ($)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Increase in proved reserves due to ethane recovery | MMcfe	(113)	1,359	1,091
Ethane recovery quantity assumption | bbl			11,500
Increase (decrease) in proved reserves due to development plan revisions | MMcfe	498
Increase in proved reserves due to additions to development plan | MMcfe	2,778
Decrease in proved reserves due to reclassifications related to five-year rule | MMcfe	(2,280)	(2,478)	(2,332)
Increase (decrease) in proved reserves resulting from price revisions | MMcfe	132	(47)	(202)
Increase (decrease) in proved reserves due to performance revisions | MMcfe	96	762	(358)
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	$ 55,824	$ 36,800	$ 35,179
Future production costs	(26,375)	(21,275)	(17,393)
Future development costs	(3,312)	(3,902)	(5,217)
Future net cash flows before income tax	26,137	11,623	12,569
Future income tax expense	(4,104)	(1,042)	(1,708)
Future net cash flows	22,033	10,581	10,861
10% annual discount for estimated timing of cash flows	(13,406)	(7,294)	(7,628)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 8,627	$ 3,287	$ 3,233	$ 7,635

Supplemental Information on O75

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, 2017USD ($)$ / MMcfe	Dec. 31, 2016USD ($)$ / MMcfe	Dec. 31, 2015USD ($)$ / MMcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe	3.23	2.39	2.66
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales of oil and gas, net of productions costs	$ (1,469)	$ (756)	$ (601)
Net changes in prices and production costs	3,918	(1,540)	(9,416)
Development costs incurred during the period	627	733	769
Net changes in future development costs	229	212	671
Extensions, discoveries and other additions	1,195	673	861
Acquisitions	258	66
Divestitures		(7)
Revisions of previous quantity estimates	987	461	(1,167)
Accretion of discount	368	363	1,132
Net change in income taxes	(1,159)	12	3,284
Other changes	386	(163)	65
Net increase (decrease)	5,340	54	(4,402)
Beginning of period	3,287	3,233	7,635
End of period	$ 8,627	$ 3,287	$ 3,233