Antero Resources (AR) 10-K 24 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 19, 2016	Jun. 30, 2015
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, 2015
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			$ 2.6
Entity Common Stock, Shares Outstanding		277,061,336
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 23,473	$ 245,979	$ 17,487	$ 18,989
Accounts receivable, net of allowance for doubtful accounts of $1,251 in 2014 and $1,195 in 2015	79,404	116,203
Accrued revenue	128,242	191,558
Derivative instruments	1,009,030	692,554
Other current assets	8,087	5,866
Total current assets	1,248,236	1,252,160
Natural gas properties, at cost (successful efforts method):
Unproved properties	1,996,081	2,060,936
Proved properties	8,211,106	6,515,221
Water handling systems	565,616	421,012
Gathering systems and facilities	1,502,396	1,197,239
Other property and equipment	46,415	37,687
Property and equipment, gross	12,321,614	10,232,095
Less accumulated depletion, depreciation, and amortization	(1,589,372)	(879,643)
Property and equipment, net	10,732,242	9,352,452
Derivative instruments	2,108,450	899,997
Other assets	66,296	68,886
Total assets	14,155,224	11,573,495
Current liabilities:
Accounts payable	364,160	531,564
Accrued liabilities	194,076	168,614
Revenue distributions payable	129,949	182,352
Other current liabilities	19,085	12,202
Total current liabilities	707,270	894,732
Long-term liabilities:
Long-term debt	4,708,513	4,362,550
Deferred income tax liability	1,370,686	794,796
Other liabilities	82,077	47,587
Total liabilities	6,868,546	6,099,665
Stockholders' Equity:
Common stock, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 262,071,642 shares and 277,035,558 shares, respectively	2,770	2,621
Additional paid-in capital	4,122,811	3,513,725
Accumulated earnings	1,808,811	867,447
Total stockholders' equity	5,934,392	4,383,793
Noncontrolling interest in consolidated subsidiary	1,352,286	1,090,037
Total equity	7,286,678	5,473,830	$ 3,598,660	$ 1,673,737
Total liabilities and equity	$ 14,155,224	$ 11,573,495

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Condensed Consolidated Balance Sheets
Allowance for doubtful accounts	$ 1,195	$ 1,251
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	277,035,558	262,071,642
Common stock, shares outstanding	277,035,558	262,071,642
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 ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue:
Natural gas sales									$ 1,039,892	$ 1,301,349	$ 689,198
Natural gas liquids sales									264,483	328,323	111,663
Oil sales									70,753	107,080	20,584
Gathering, compression and water distribution									22,000	22,075
Marketing									176,229	53,604
Commodity derivative fair value losses									2,381,501	868,201	491,689
Gain on sale of gathering system										40,000
Total revenue	$ 905,122	$ 1,443,335	$ 376,714	$ 1,229,687	$ 1,481,823	$ 762,490	$ 311,338	$ 164,981	3,954,858	2,720,632	1,313,134
Operating expenses:
Lease operating									36,011	29,341	9,439
Gathering, compression, processing, and transportation									659,361	461,413	218,428
Production and ad valorem taxes									78,325	87,918	50,481
Marketing									299,062	103,435
Exploration									3,846	27,893	22,272
Impairment of unproved properties									104,321	15,198	10,928
Depletion, depreciation, and amortization									709,763	477,896	233,876
Accretion of asset retirement obligations									1,655	1,271	1,065
General and administrative (including equity-based compensation expense of $365,280, $112,252 and $97,877 in 2013, 2014 and 2015, respectively)									233,697	216,533	425,438
Contract termination and rig stacking									38,531
Total operating expenses	591,896	502,220	540,463	529,993	454,106	381,091	316,641	269,060	2,164,572	1,420,898	971,927
Operating income	313,226	941,115	(163,749)	699,694	1,027,717	381,399	(5,303)	(104,079)	1,790,286	1,299,734	341,207
Other expenses:
Interest									(234,400)	(160,051)	(136,617)
Loss on early extinguishment of debt										(20,386)	(42,567)
Total other expenses									(234,400)	(180,437)	(179,184)
Income from continuing operations before income taxes and discontinued operations									1,555,886	1,119,297	162,023
Provision for income tax expense									(575,890)	(445,672)	(186,210)
Income (loss) from continuing operations	175,574	544,734	(139,483)	399,171	608,970	203,909	(44,495)	(94,759)	979,996	673,625	(24,187)
Discontinued Operations:
Income from sale of discontinued operations, net of income tax expense							2,210			2,210	5,257
Net income (loss) and comprehensive income (loss) including noncontrolling interest	175,574	544,734	(139,483)	399,171	608,970	203,909	(42,285)	(94,759)	979,996	675,835	(18,930)
Net income and comprehensive income attributable to noncontrolling interest	17,110	10,892	5,890	4,740	2,248				38,632	2,248
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 158,464	$ 533,842	$ (145,373)	$ 394,431	$ 606,722	$ 203,909	$ (42,285)	$ (94,759)	$ 941,364	$ 673,587	$ (18,930)
Earnings (loss) per common share:
Continuing operations (in dollars per share)					$ 2.31	$ 0.78	$ (0.17)	$ (0.36)	$ 3.43	$ 2.56	$ (0.09)
Discontinued operations (in dollars per share)							0.01			0.01	0.02
Total (in dollars per share)	$ 0.57	$ 1.93	$ (0.52)	$ 1.49	2.31	0.78	(0.16)	(0.36)	3.43	2.57	(0.07)
Earnings (loss) per common share assuming dilution:
Continuing operation (in dollars per share)					2.31	0.78	(0.17)	(0.36)	3.43	2.56	(0.09)
Discontinued operations (in dollars per share)							0.01			0.01	0.02
Total (in dollars per share)	$ 0.57	$ 1.93	$ (0.52)	$ 1.49	$ 2.31	$ 0.78	$ (0.16)	$ (0.36)	$ 3.43	$ 2.57	$ (0.07)
Weighted average number of shares outstanding
Basic (in shares)									274,122,567	262,053,868	262,049,659
Diluted (in shares)									274,143,341	262,068,106	262,049,659

Consolidated Statements of Ope5

Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Equity-based compensation expense	$ 97,877	$ 112,252	$ 365,280
Deferred income tax expense - discontinued operations		$ 1,354	$ 3,249

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands	Members' equity	Common Stock	Additional paid-in capital	Accumulated earnings	Noncontrolling Interests	Total
Balances at Dec. 31, 2012	$ 1,460,947			$ 212,790		$ 1,673,737
Increase (Decrease) in Stockholders' Equity
Merger of Antero Resources LLC and Antero Resources Corporation	$ (1,460,947)	$ 2,244	$ 1,458,703
Merger of Antero Resources LLC and Antero Resources Corporation (in shares)		224,375
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs		$ 376	1,578,197			1,578,573
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs (in shares)		37,675
Equity-based compensation			365,280			365,280
Net income (loss) and including noncontrolling interest				(18,930)		(18,930)
Balances at Dec. 31, 2013		$ 2,620	3,402,180	193,860		3,598,660
Increase (Decrease) in Stockholders' Equity
Balances (in shares)		262,050
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings		$ 1	(142)			(141)
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares)		22
Equity-based compensation			111,687		$ 565	112,252
Issuance of common units in subsidiary - Antero Midstream Partners LP					1,087,224	1,087,224
Net income (loss) and including noncontrolling interest				673,587	2,248	675,835
Balances at Dec. 31, 2014		$ 2,621	3,513,725	867,447	1,090,037	5,473,830
Increase (Decrease) in Stockholders' Equity
Balances (in shares)		262,072
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
Equity-based compensation			93,300		4,577	97,877
Issuance of common units in 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)
Net income (loss) and 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
Increase (Decrease) in Stockholders' Equity
Balances (in shares)		277,036

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss) including noncontrolling interest	$ 979,996	$ 675,835	$ (18,930)
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	711,418	479,167	234,941
Impairment of unproved properties	104,321	15,198	10,928
Derivative fair value (gains) losses	(2,381,501)	(868,201)	(491,689)
Gains (losses) on settled derivatives	856,572	135,784	163,570
Deferred income tax expense (benefit)	575,890	445,672	190,210
Gain on sale of assets		(40,000)
Equity-based compensation expense	97,877	112,252	365,280
Loss on early extinguishment of debt		20,386	42,567
Gain on sale of discontinued operations		(3,564)	(8,506)
Deferred income tax expense - discontinued operations		1,354	3,249
Other	31,741	6,433	1,173
Changes in current assets and liabilities:
Accounts receivable	(3,201)	(45,593)	(9,314)
Accrued revenue	63,316	(94,733)	(50,156)
Other current assets	(2,221)	(2,891)	19,543
Accounts payable	5,200	(11,710)	1,039
Accrued liabilities	13,210	85,953	26,803
Revenue distributions payable	(52,403)	85,763	50,552
Other current liabilities	6,166	1,016	3,447
Net cash provided by operating activities	1,006,381	998,121	534,707
Cash flows used in investing activities:
Additions to proved properties		(64,066)	(15,300)
Additions to unproved properties	(198,694)	(777,422)	(440,825)
Drilling and completion costs	(1,651,282)	(2,477,150)	(1,615,965)
Additions to water handling and treatment systems	(131,051)	(196,675)	(203,790)
Additions to gathering systems and facilities	(360,287)	(558,037)	(389,453)
Additions to other property and equipment	(6,595)	(13,218)	(6,240)
Change in other assets	9,750	(3,082)	(2,019)
Proceeds from asset sales	40,000
Net cash used in investing activities	(2,298,159)	(4,089,650)	(2,673,592)
Cash flows from financing activities:
Issuance of common stock	537,832		1,578,573
Issuance of common units in Antero Midstream Partners LP	240,703	1,087,224
Issuance of senior notes	750,000	1,102,500	1,231,750
Repayment of senior notes		(260,000)	(690,000)
Borrowings (repayments) on bank credit facility, net	(403,000)	1,442,000	71,000
Make-whole premium on debt extinguished		(17,383)	(33,041)
Payments of deferred financing costs	(17,293)	(31,543)	(20,899)
Distributions to noncontrolling interest in consolidated subsidiary	(34,129)
Other	(4,841)	(2,777)
Net cash provided by financing activities	1,069,272	3,320,021	2,137,383
Net increase (decrease) in cash and cash equivalents	(222,506)	228,492	(1,502)
Cash and cash equivalents, beginning of period	245,979	17,487	18,989
Cash and cash equivalents, end of period	23,473	245,979	17,487
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	219,945	163,055	117,832
Supplemental disclosure of noncash investing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment	$ (169,783)	$ 181,591	$ 188,123

Business and Organization

Business and Organization	12 Months Ended
	Dec. 31, 2015
Organization
Organization	(1) Business and Organization Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as the “Company”) are engaged in the exploration, development, and acquisition of natural gas, natural gas liquids (“NGLs”), and oil properties in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs, and oil from unconventional formations. Through its consolidated subsidiary, Antero Midstream Partners LP, a publicly-traded limited partnership (“Antero Midstream”), the Company has water handling and treatment operations and gathering and compression 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, 2015
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, 2014 and 2015 , and the results of its operations and its cash flows for the years ended December 31, 2013 , 2014 , and 2015 . 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 Securities and Exchange Commission, 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 in which the Company is the primary beneficiary. 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 third-party individuals or entities, or Antero Midstream’s general partner. An affiliate of the Company owns the general partner interest in Antero Midstream. Noncontrolling interest is included as a component of equity in the Company’s consolidated balance sheets. (c)  Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses during the reporting period. 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 in the region, availability of transportation capacity to other regions of the country, 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. (f)  Oil and Gas Properties The Company accounts for its natural gas 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, 2013, 2014, and 2015. 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 with significant acquisition costs 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. Other unproved properties are assessed for impairment on an aggregate basis. 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 $10.9 million, $15.2 million, and $104.3 million for the years ended December 31, 2013 , 2014 , and 2015 , 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 determine 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 determine 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 properties during the year ended December 31, 2015. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2013 and 2014. At December 31, 2015 , the Company did not have significant capitalized costs related to exploratory wells ‑in ‑progress which were pending determination of proved reserves. The Company also had no significant costs which have been deferred for longer than one year pending determination of proved reserves at December 31, 2015 . The provision for depletion, depreciation, and amortization of oil and gas properties is calculated on a geological reservoir basis using the units ‑of ‑production method. Depletion, depreciation, and amortization expense for oil and gas properties was $219.8 million, $418.7 million, and $614.7 million for the years ended December 31, 2013 , 2014 , and 2015 , 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 $11.9 million, $53.2 million, and $87.4 million for the years ended December 31, 2013 , 2014 , and 2015 , 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 unit being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair value, which is based on discounted future cash flows or other techniques, as appropria te. There were no impairments for such assets during the years ended December 31, 2013 , 2014 , and 2015 . (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 $2.2 million, $5.9 million, and $7.7 million for the years ended December 31, 2013 , 2014 , and 2015 , respectively. A gain or loss is recognized upon the sale or disposal of property and equipment. (j)  Deferred Financing Costs Deferred financing costs represent loan origination fees, initial purchasers’ discounts, and other borrowing costs, and are included in noncurrent other assets on the consolidated balance sheets. These costs are amortized over the term of the related debt instrument using the effective interest method. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2015 , the Company had $59 million of unamortized deferred financing costs included in other long ‑term assets. The amounts amortized and the write ‑off of previously deferred debt issuance costs were $15.8 million, $11.0 million, and $10.1 million for the years ended December 31, 2013 , 2014 , and 2015 , 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, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its 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 an asset or liability 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 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. The 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 ARO can result from changes in retirement cost estimates and 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 the obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. The Company delivers natural gas through its gathering assets and delivers water through its water handling and treatment assets and may become obligated by regulatory or other requirements to remove certain facilities or perform other remediation upon retirement of these assets. However, the Company cannot reasonably predict when production from existing reserves of the fields in which it operates will cease. In the absence of such information, management is not able to make a reasonable estimate of when future dismantlement and removal dates will occur; therefore, the Company has not recorded asset retirement obligations related to its gathering and water handling and treatment assets. (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, 2014 and 2015 , the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that are likely to have a material adverse effect on future capital expenditures or operating results of the Company. (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 natural gas revenues. At December 31, 2014 and 2015 , the Company had no significant 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. The concentration of credit risk in a single industry 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, 2013 , 2014 , and 2015 are as follows: 2013 2014 2015 Company A — % 5 % 19 % Company B 30 29 18 Company C 14 16 13 Company D 8 12 9 All others 48 38 41 100 % 100 % 100 % Although a substantial portion of the Company’s production is purchased by these major customers, the Company does not believe the loss of any one or several customers would have a material adverse effect on its business, as other customers or markets would be accessible. 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, all of which are a lender under Antero’s Credit Facility. The fair value of the Company’s commodity derivative contracts of approximately $ 3.1 billion at December 31, 2015 includes the following values by bank counterparty: Morgan Stanley— $691 million; Barclays— $593 million; JP Morgan— $575 million; Citigroup— $362 million; Wells Fargo— $285 million; Scotiabank— $214 million; BNP Paribas— $188 million; Toronto Dominion Bank— $76 million; Fifth Third Bank— $41 million; Canadian Imperial Bank of Commerce— $37 million; Bank of Montreal— $29 million; SunTrust— $17 million; Capital One— $8 million; and Natixis— $1 million. The credit ratings of certain of these banks were downgraded in recent years because of the sovereign debt crisis in Europe. 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, 2015 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 the tax laws or tax rates is recognized in income in 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). The 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 and basis 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 compression; (3) water handling and treatment; and ( 4 ) marketing of excess firm transportation capacity. The Company identified marketing of excess firm transportation capacity as a new operating segment in 2014. 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. (s)  Marketing Revenues and Expenses In 2014, the Company commenced activities 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. The costs of unutilized capacity are 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) from continuing operations attributable to Antero or income from discontinued operations, as applicable, by the basic weighted average number of shares outstanding during such period. Earnings per common share—assuming dilution for each period is computed giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. 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: Year ended December 31, 2013 2014 2015 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock and restricted stock units — Add: Dilutive effect of outstanding stock options — — — Diluted weighted average number of shares outstanding 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 — Outstanding stock options — (1) The potential dilutive effects of these awards were excluded from the computation of earnings per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive. (u)  New Accounting Principle On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes–Balance Sheet Classification of Deferred Taxes , which requires that deferred income tax liabilities and assets be presented in the balance sheet as noncurrent. The new standard becomes effective for the Company on January 1, 2017. However, the Company has elected to early-adopt the standard as of December 31, 2015. The Company has also elected to apply this standard retrospectively; as such, deferred taxes have been recast as noncurrent for all prior periods presented in this Form 10-K. The Company does not believe that this standard has a material impact on its ongoing financial reporting. The retrospective adjustment to the December 31, 2014 consolidated balance sheet is as follows: As Previously Reported Adjustment As Adjusted December 31, 2014 Effect December 31, 2014 Net deferred income tax liability - current $ — Net deferred income tax liability - long-term Total net deferred tax liabilities $ —

Antero Midstream Partners LP

Antero Midstream Partners LP	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Antero Midstream Partners LP	(3) Antero Midstream Partners LP In 2014, the Company formed Antero Midstream to own, operate, and develop midstream energy assets to service Antero’s production. Antero Midstream’s assets consist of gathering pipelines and compressor stations, and water handling and treatment facilities, through which it provides services to Antero under long-term, fixed-fee contracts. Antero Resources Midstream Management LLC (“Midstream Management”), a wholly-owned subsidiary of Antero Investment LLC (“Antero Investment”), owns the general partnership interest in Antero Midstream, which allows Midstream Management to manage the business and affairs of Antero Midstream. Midstream Management also holds the incentive distribution rights in Antero Midstream. Antero Midstream is an unrestricted subsidiary as defined by Antero’s bank credit facility and, as such, Antero Midstream is not a guarantor of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see note 16). 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 to be constructed in Doddridge County, West Virginia, to Antero Treatment LLC, 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 borrowed $525 million on its bank credit facility in connection with this transaction. The transaction was accounted for as a transaction between entities under common control. As a result, the Contributed Assets have been recorded by Antero Midstream at their historical cost. The difference between the historical cost and the consideration transferred to Antero was recorded as an adjustment to partners’ capital on the balance sheet of Antero Midstream. At December 31, 2014 and December 31, 2015, Antero owned approximately 69.7% and 66.3% of the limited partner interests of Antero Midstream, respectively.

Sale of Piceance and Arkoma Pro

Sale of Piceance and Arkoma Properties - Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Piceance Basin and Arkoma Basin
Sale of Assets
Sale of Piceance and Arkoma Properties - Discontinued Operations	(4) Sale of Piceance and Arkoma Properties—Discontinued Operations In 2012, the Company sold its Piceance Basin assets in Colorado and its Arkoma Basin assets in Oklahoma. Pre-tax losses recognized in discontinued operations at the time of the transactions were adjusted downward in 2013 and 2014 by $8.5 million and $3.6 million, respectively, for the resolution of certain liabilities recorded at the time of the sales and settlement of final contractual purchase price adjustments. Income from discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) is comprised of the following (in thousands): Year ended December 31, 2013 2014 2015 Income from discontinued operations before income taxes — Income tax expense — Net income from discontinued operations $ —

Sale of Appalachian Gathering A

Sale of Appalachian Gathering Assets	12 Months Ended
	Dec. 31, 2015
Appalachian Gathering Assets
Sale of Assets
Sale of Appalachian Gathering Assets	(5) Sale of Appalachian Gathering Assets On March 26, 2012, the Company closed the sale of a portion of its Marcellus Shale gathering system assets in West Virginia along with exclusive rights to gather the Company’s gas for a 20 year period within an area of dedication to a joint venture owned by Crestwood Midstream Partners and Crestwood Holdings Partners LLC (together “Crestwood”). During the first seven years of the contract, the Company is committed to deliver minimum annual volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies. Under the terms of the agreement, the Company earned additional proceeds of $40 million by meeting certain volume thresholds by December 31, 2014. The Company recognized the $40 million gain on the sale of assets in 2014. The amount was paid by Crestwood in 2015.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Long-Term Debt	(6) Long ‑Term Debt Long ‑term debt was follows at December 31, 2014 and 2015 (in thousands): 2014 2015 Antero: Bank credit facility(a) $ 6.00% senior notes due 2020(c) 5.375% senior notes due 2021(d) 5.125% senior notes due 2022(e) 5.625% senior notes due 2023(f) — Net unamortized premium Antero Midstream: Bank credit facility(b) — $ (a) Senior Secured Revolving Credit Facility Antero has a senior secured revolving bank credit facility (the “Credit Facility”) with a consortium of bank lenders. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of Antero’s proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. At December 31, 2015 , the borrowing base was $4.5 billion and lender commitments were $4.0 billion. The next redetermination of the borrowing base is scheduled to occur in April 2016. The maturity date of the Credit Facility is May 5, 2019 The Credit Facility is ratably secured by mortgages on substantially all of Antero’s properties and guarantees from Antero’s restricted subsidiaries, as applicable. 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. Antero was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2014 and 2015 . As of December 31, 2015 , Antero had a n outstanding balance under the Credit Facility of $ 707 million, with a weighted average interest rate of 2.32 % , and outstanding letters of credit of $702 million. As of December 31, 2014 , Antero had an outstanding balance under the Credit Facility of $ 1.7 billion, with a weighted average interest rate of 2.06 % , and outstanding letters of credit of approximately $387 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused portion based on utilization. (b) Senior Secured Revolving Credit Facility – Antero Midstream On November 10, 2014, Antero Midstream entered into a senior secured revolving bank credit facility (the “Midstream Facility”) with a consortium of bank lenders. At December 31, 2015 , the maximum amount of the facility was $1.5 billion. The maturity date of the Midstream Facility is November 10, 2019. The Midstream Facility is ratably secured by mortgages on substantially all of the properties of Antero Midstream and guarantees from its restricted subsidiaries, as applicable. The Midstream 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. Antero Midstream was in compliance with all of the financial covenants under the Midstream Facility as of December 31, 2014 and 2015 . As of December 31, 2015 , Antero Midstream had an outstanding balance under the Midstream Facility of $620 million, with a weighted average interest rate of 1.92% . As of December 31, 2014, Antero Midstream did not have a balance outstanding under the Midstream Facility. Commitment fees on the unused portion of the Midstream Facility are due quarterly at rates ranging from 0.25% to 0.375% of the unused facility based on utilization. (c) 6.00% Senior Notes Due 2020 On November 19, 2012, Antero issued $300 million of 6.00% senior notes due December 1, 2020 (the “2020 notes”) at par. On February 4, 2013, Antero issued an additional $225 million of the 2020 notes at 103% of par. The 2020 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2020 notes rank pari passu to Antero’s other outstanding senior notes. The 2020 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 2020 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2020 notes at any time at redemption prices ranging from 104.50% currently to 100.00% on or after December 1, 2018. If Antero undergoes a change of control, the holders of the 2020 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 2020 notes, plus accrued interest. (d) 5.375% Senior Notes Due 2021 On November 5, 2013, Antero issued $1 billion of 5.375% senior notes due November 21, 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 on or after November 1, 2016 at redemption prices ranging from 104.031% on or after November 1, 2016 to 100.00% on or after November 1, 2019. In addition, on or before November 1, 2016, Antero may redeem up to 35% of the aggregate principal amount of the 2021 notes with 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 2021 notes, plus accrued interest. At any time prior to November 1, 2016, Antero may also redeem the 2021 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2021 notes, plus a “make ‑whole” premium and accrued interest. 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 interest. (e) 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 on or after June 1, 2017 at redemption prices ranging from 103.844% on or after June 1, 2017 to 100.00% on or after June 1, 2020. In addition, on or before June 1, 2017, Antero may redeem up to 35% of the aggregate principal amount of the 2022 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.125% of the principal amount of the 2022 notes, plus accrued interest. At any time prior to June 1, 2017, Antero may also redeem the 2022 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2022 notes plus a “make-whole” premium and accrued interest. 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 interest. (f) 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 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 interest. If Antero undergoes a change of control prior to June 1, 2016, it may redeem all, but not less than all, of the 2023 notes at a redemption price equal to 110% of the principal amount of the 2023 notes. 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 interest. (g) Treasury Management Facility Antero has a stand ‑alone revolving note with a lender under the Credit Facility 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 facility bear interest at the lender’s prime rate plus 1.0% . The note matures on May 1, 2016 . At December 31, 2014 and 2015 , there were no outstanding borrowings under this facility.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligations
Asset Retirement Obligations	(7) Asset Retirement Obligations The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2014 and 2015 (in thousands). 2014 2015 Asset retirement obligations—beginning of year $ $ Obligations incurred for wells drilled Revisions to prior estimates — Accretion expense Asset retirement obligations—end of year $ $ Revisions to prior estimates in 2015 are primarily due to a decrease in the estimated economic lives of our wells as a result of the decrease in commodity prices during 2015. Asset retirement obligations are included in other liabilities on the consolidated balance sheets.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2015
Equity-Based Compensation
Equity-Based Compensation	(8) 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 9,377,755 shares were available for future grant under the Plan as of December 31, 2015 . In connection with the Antero Midstream IPO, Antero Midstream’s general partner adopted the Antero Midstream Partners LP Long-Term Incentive Plan (the “Midstream Plan”), pursuant to which non-employee directors of Antero Midstream’s general partner and certain officers, employees, and consultants of Antero Midstream’s general partner and its affiliates (which include Antero) are eligible to receive awards representing ownership interests in Antero Midstream. An aggregate of 10,000,000 common units may be delivered pursuant to awards under the Midstream Plan, subject to customary adjustments. A total of 7,947,771 common units are available for future grant under the Midstream Plan as of December 31, 2015 . The Company’s equity ‑based compensation expense is as follows for the years ended December 31, 2013 , 2014 , and 2015 (in thousands): Year ended December 31, 2013 2014 2015 Profits interests awards $ Restricted stock awards Stock options Antero Midstream phantom and restricted unit awards — Common stock issued to directors in lieu of cash compensation — Total expense $ Profits Interests Awards In connection with its formation in October 2009, Antero Resources LLC issued profits interests to Antero Resources Employee Holdings LLC (“Employee Holdings”), which is owned solely by certain of the Company’s officers and employees. These profits interests provided for the participation in distributions upon liquidation events meeting certain requisite financial return thresholds. In turn, Employee Holdings issued membership interests to certain of the Company’s officers and employees. The Employee Holdings interests in Antero Resources LLC were exchanged for similar interests in Antero Investment in connection with the Company’s initial public offering on October 16, 2013. The limited liability company agreement of Antero Investment provided a mechanism that demonstrated how the shares of the Company’s common stock held by Antero Investment would be allocated among its members, including Employee Holdings. As a result of the adoption of the Antero Investment Limited Liability Company Agreement, the satisfaction of all performance and service conditions relative to the profits interest awards held by Employee Holdings in Antero Investment became probable. Accordingly, the Company recognized approximately $486 million of equity-based compensation expense for the vested profits interests from the fourth quarter of 2013 through the fourth quarter of 2015. The profits interest awards were fully vested as of December 31, 2015, and no expense will be recognized for these awards in the future. Because consideration for the profits interest awards was deemed given by Antero Investment, the charge to equity-based compensation expense was accounted for as a capital contribution by Antero Investment to the Company and credited to additional paid-in capital. All available profits interest awards were made prior to the date of the IPO, and no additional profits interest awards were made since such date. Restricted Stock and Restricted Stock Unit Awards Restricted stock and restricted stock unit awards vest subject to the satisfaction of service requirements. Expense related to each restricted stock and restricted stock unit award is recognized on a straight-line basis over the requisite service period of the entire award, less awards expected to be forfeited. 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 during the year ended December 31, 2015 is as follows: Weighted average Aggregate Number of shares grant date fair value intrinsic value (in thousands) Total awarded and unvested—December 31, 2014 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2015 $ $ Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. Unamortized expense of $177.6 million at December 31, 2015 is expected to be recognized over a weighted average period of approximately 2.7 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, less awards expected to be forfeited. 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, 2015 is as follows: Weighted Weighted average average remaining Intrinsic Stock options exercise price contractual life value (in thousands) Outstanding at December 31, 2014 $ $ — Granted $ Exercised — — Forfeited $ Expired — — Outstanding at December 31, 2015 $ $ — Vested or expected to vest as of December 31, 2015 $ $ — Exercisable at December 31, 2015 $ $ — 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. 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 years ended December 31, 2013, 2014, and 2015 and the assumptions used to determine fair value. Year ended December 31, 2013 2014 2015 Dividend yield — % — % — % Volatility % % % Risk-free interest rate % % % Expected life (years) Weighted average fair value of options granted $ $ $ As of December 31, 2015 , there was $8.3 million of unrecognized equity ‑based compensation expense related to nonvested stock options. That expense is expected to be recognized over a weighted average period of approximately 3.2 years. Antero Midstream Partners Phantom and Restricted Unit Awards Restricted units and 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 restricted units or phantom units. These restricted and 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 employees, and a portion of the expense is allocated to Antero Midstream. Expense related to each restricted unit and phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award, less awards expected to be forfeited. 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 restricted unit and phantom unit awards activity during the year ended December 31, 2015 is as follows: Number of units Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested—December 31, 2014 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2015 $ $ Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. Unamortized expense of $46.1 million at December 31, 2015 is expected to be recognized over a weighted average period of approximately 2.9 years.

Financial Instruments

Financial Instruments	12 Months Ended
	Dec. 31, 2015
Financial Instruments
Financial Instruments	(9) Financial Instruments The carrying values of accounts receivable and accounts payable at December 31, 2014 and 2015 approximated market value because of their short ‑term nature. The carrying values of the amounts outstanding under the Credit Facility and Midstream Facility at December 31, 2014 and 2015 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 Company’s senior notes was approximately $2.5 billion at December 31, 2014 and $2.6 billion at December 31, 2015 . See note 10 for information regarding the fair value of derivative financial instruments.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments
Derivative Instruments	(10) 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 a portion of its production. These derivatives are not held 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. During the years ended December 31, 2013 , 2014 , and 2015 , the Company was party to various natural gas, NGLs, and oil fixed price swap contracts. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty. When actual commodity prices are below the contractually provided fixed price, the Company receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts in order to hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price. The Company’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, 2015 , the Company’s fixed price natural gas and NGLs swap positions from January 1, 2016 through December 31, 2022 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: TCO=Columbia Gas Transmission; NYMEX=Henry Hub; CGTLA=Columbia Gas Louisiana Onshore; CCG=Chicago City Gate; Mont Belvieu-TET=Mont Belvieu Propane): Natural gas MMbtu/day Propane Bbls/day Weighted average index price Three months ending March 31, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending June 30, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending September 30, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending December 31, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2017: NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ CCG ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2018: NYMEX ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2019: NYMEX ($/MMBtu) $ Year ending December 31, 2020: NYMEX ($/MMBtu) $ Year ending December 31, 2021: NYMEX ($/MMBtu) $ Year ending December 31, 2022: NYMEX ($/MMBtu) $ As of December 31, 2015 , the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of TCO to the NYMEX Henry Hub natural gas price, are as follows: Natural gas MMbtu/day Hedged Differential Year ending December 31, 2016: $ Year ending December 31, 2017: $ As of December 31, 2015 , the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of NYMEX Henry Hub to the TCO natural gas price, are as follows: Natural gas MMbtu/day Hedged Differential Year ending December 31, 2016: $ Year ending December 31, 2017: $ (b) Summary The following is 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, 2014 and 2015 . None of the Company’s derivative instruments are designated as hedges for accounting purposes. December 31, 2014 December 31, 2015 Balance sheet location Fair value Balance sheet location Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ Current assets $ Commodity contracts Long-term assets Long-term assets Total asset derivatives Total liability derivatives — — Net derivatives $ $ The following table presents the gross amounts 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, 2014 December 31, 2015 Gross amounts on balance sheet Gross amounts offset on balance sheet Net amounts of assets on balance sheet Gross amounts on balance sheet Gross amounts offset on balance sheet Net amounts of assets on balance sheet Commodity derivative assets $ $ Commodity derivative liabilities $ — — — $ — — — The following is a summary of derivative fair value gains and where such values are recorded in the consolidated statemen ts of operations for the years ended December 31, 2013 , 2014 , and 2015 (in thousands): Statement of operations Year ended December 31, location 2013 2014 2015 Commodity derivative fair value gains Revenue $ 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, 2015
Contingencies
Contract Termination and Rig Stacking	(11) 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.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Taxes
Income Taxes	(12) Income Taxes For the years ended December 31, 2013 , 2014 , and 2015 , income tax expense from continuing operations consisted of the fol lowing (in thousands): Year ended December 31, 2013 2014 2015 Current income tax benefit $ — — Deferred income tax expense Total income tax expense from continuing operations $ Income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to income from continuing operations for the years ended December 31, 2013 , 2014 , and 2015 as a result of the following (in thousands): Year ended December 31, 2013 2014 2015 Federal income tax expense $ State income tax expense, net of federal benefit Nondeductible equity-based compensation Noncontrolling interest in Antero Midstream Partners LP — Change in valuation allowance Other Total income tax expense from continuing operations $ For the years ended December 31, 2013 , 2014 , and 2015 , income tax expense was allocated to continuing and discontinued operations as follows (in thousands): Year ended December 31, 2013 2014 2015 Continuing operations $ Discontinued operations and sale of discontinued operations — Total income tax expense $ 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, 2014 and 2015 is as follows (in thousands): 2014 2015 Deferred tax assets: Net operating loss carryforwards $ Minimum tax credit carryforward Equity-based compensation Other Total deferred tax assets Valuation allowance Net deferred tax assets Deferred tax liabilities: Unrealized gains on derivative instruments Oil and gas properties Investment in Antero Midstream Partners LP Total deferred tax liabilities Net deferred tax liabilities $ 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 $ 27 million at December 31, 2014 and 2015 related to NOL carryforwards primarily attributable to states where the Company no longer operates. The amount of the deferred tax asset considered realizable could be reduced in the near term if estimates of future taxable income during the carryforward period are revised. The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more ‑likely-than ‑not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements include unrecognized benefits at December 31, 2015 of $ 11 million that, if recognized, would result in a reduction of noncurrent income taxes payable (included in other long ‑term liabilities) and an increase in noncurrent deferred tax liabilities. No impact to the Company’s 2015 effective tax rate would result. As of December 31, 2015 , interest of $1.6 million has been accrued on unrecognized tax benefits. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2013 2014 2015 Balance at beginning of year $ Revised estimate of unrecognized tax position — — Balance at end of year $ As of December 31, 2015 , the Company’s corporate subsidiaries have U.S. Federal and state net operating loss carryforwards (NOLs) of $1.4 billion and $1.2 billion, respectively, which expire at various dates from 2024 to 2035. The tax years 2012 through 2014 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 2011 through 2015. During 2015, the State of West Virginia completed its examination of the tax returns of Antero Resources Corporation for its tax years 2011 through 2013. There were no material adjustments to our provision for income taxes as a result of the examination.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2015
Commitments
Commitments	(13) Commitments The following is a schedule of future minimum payments for firm transportation, drilling rig, hydraulic fracturing, 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, 2015 (in millions). Firm transportation Processing, gathering and compression Drilling rigs and frac services Office and equipment (a) (b) (c) (d) Total Year ending December 31: 2016 $ 2017 2018 2019 — 2020 — Thereafter — Total $ (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 represent 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 compressor service agreements with third parties that provide for payments based on volumes compressed and have minimum payment obligations which 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. (c) Drilling Rig Service Commitments The Company has obligations under agreements with service providers to procure drilling rigs and hydraulic fracturing 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, as well as field equipment, under operating lease arrangements. Rental expense under operating leases was $1.8 million, $10.2 million, and $9.0 million for the years ended December 31, 2013 , 2014 , and 2015 , respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2015
Contingencies
Contingencies	(14) Contingencies The Company is the subject of two nearly identical lawsuits brought by South Jersey Gas Company and South Jersey Resources Group, LLC (collectively “SJGC”) filed on February 4, 2015 in the Superior Court of New Jersey. The lawsuits have since been consolidated into one case. SJGC are purchasers of some of the Company’s natural gas production under contracts entered into in 2011. Deliveries under the contracts began in October 2011 and the delivery obligation continues through October 2019. SJGC allege that the index prices specified in the contracts, and the index prices at which SJGC paid for deliveries from 2011 through September 2014, are no longer appropriate under the contracts because a market disruption event (as defined by the contract) has occurred and, as a result, a new index price is to be determined by the parties. The lawsuit seeks a reformation of the contracts, compensatory and punitive damages to be determined at trial, and costs and expenses of the actions. Beginning in October 2014, SJGC began paying the Company under indexes unilaterally selected by SJGC and not specified in the contract. The Company contends that no market disruption event has occurred and that SJGC has breached the contracts by failing to pay the Company based on the express price terms of the contracts. The Company further contends that jurisdiction and venue are improper in New Jersey. On March 30, 2015, the Company filed suit against SJGC in United States District Court in Colorado seeking relief for breach of contract, damages in the amounts that SJGC has short paid and continues to short pay, as well as costs of the suit. Through December 31, 2015, the Company estimates that it is owed approximately $39 million more than SJGC has paid using the indexes unilaterally selected by them. 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.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Information
Segment Information	(15) Segment Information See note 2(r) for a description of the Company’s determination of its reportable segments for 2015. Marketing of excess firm transportation capacity began in the second quarter of 2014, and was subsequently determined to be a new reportable segment. Revenues from gathering and compression 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 determined by the respective operating income of each segment. General and administrative expenses are allocated to the gathering and compression and water handling and treatment segments based on estimates of labor and overhead expenditures on those activities. 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 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, 2013 , 2014 , and 2015 (in thousands): Exploration and production Gathering and compression Water handling and treatment Elimination of intersegment transactions Consolidated total Year ended December 31, 2013: Sales and revenues: Third-party $ — — — Intersegment — — Total $ Operating expenses: Lease operating $ — Gathering, compression, processing, and transportation — Depletion, depreciation, and amortization — General and administrative expense — Other operating expenses — — Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ Exploration and production Gathering and compression Water handling and treatment Marketing Elimination of intersegment transactions Consolidated total Year ended December 31, 2014: Sales and revenues: Third-party $ — Intersegment — — Total $ Operating expenses: Lease operating $ — — Gathering, compression, processing, and transportation — — Depletion, depreciation, and amortization — — General and administrative expense — Other operating expenses — Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ — Exploration and production Gathering and compression Water handling and treatment Marketing Elimination of intersegment transactions Consolidated total Year ended December 31, 2015: Sales and revenues: Third-party $ — Intersegment — — Total $ Operating expenses: Lease operating $ — — Gathering, compression, processing, and transportation — — Depletion, depreciation, and amortization — — General and administrative expense — Other operating expenses Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ —

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2015
Subsidiary Guarantors
Subsidiary Guarantors	(16) Subsidiary Guarantors Antero’s wholly-owned subsidiaries each have fully and unconditionally guaranteed Antero’s senior notes. Antero Midstream and its subsidiaries have been designated 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 4). 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, 2014 and 2015, and the related statements of operations and comprehensive income and statements cash flows for the years ended December 31, 2014 and 2015, present financial information for Antero on a stand ‑alone basis (carrying its investment in wholly-owned subsidiaries using the equity method), financial information for the subsidiary guarantors, financial information for the non-guarantor subsidiaries, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. Antero’s wholly-owned subsidiaries had no revenues, expenses, or cash flows during the year ended December 31, 2013, or for any year prior to 2013 and immaterial assets and liabilities at December 31, 2013. Antero’s wholly-owned subsidiaries are not restricted from making distributions to the Parent. Condensed Consolidating Balance Sheet December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ — — Accounts receivable, net — — — Intercompany receivables — — Accrued revenue — — — Derivative instruments — — — Other current assets Total current assets Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties — — — Proved properties — — — Water handling and treatment systems — — — Gathering systems and facilities — — Other property and equipment — — — — — Less accumulated depletion, depreciation, and amortization — — Property and equipment, net — — Derivative instruments — — — Investments in subsidiaries — — — Other assets, net — — Total assets $ Liabilities and Equity Current liabilities: Accounts payable $ — — Intercompany payable — — Accrued liabilities — — Revenue distributions payable — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Other liabilities — — — Total liabilities Equity: Stockholders' equity: Parent net investment — — — Partners' capital — — — Common stock — — — Additional paid-in capital — — — Accumulated earnings — — — Total stockholders' equity Noncontrolling interest in consolidated subsidiary — — — Total equity Total liabilities and equity $ Condensed Consolidating Balance Sheet December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ — — Accounts receivable, net — — Intercompany receivables — — Accrued revenue — — — Derivative instruments — — — Other current assets — — — Total current assets — Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties — — — Proved properties — — Water handling and treatment systems — — — Gathering systems and facilities — — Other property and equipment — — — — Less accumulated depletion, depreciation, and amortization — — Property and equipment, net — Derivative instruments — — — Investments in subsidiaries — — — Contingent acquisition consideration — — — Other assets, net — — Total assets $ — Liabilities and Equity Current liabilities: Accounts payable $ — — Intercompany payable — — Accrued liabilities — — Revenue distributions payable — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Contingent acquisition consideration — — — Other liabilities — — Total liabilities — Equity: Stockholders' equity: Partners' capital — — — Common stock — — — Additional paid-in capital — — — Accumulated earnings — — — Total stockholders' equity — Noncontrolling interest in consolidated subsidiary — — — Total equity — Total liabilities and equity $ — Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenue: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — Marketing — — — Commodity derivative fair value gains — — — Gain on sale of gathering system — — — Other income — — — Total revenue — Operating expenses: Lease operating — — — Gathering, compression, processing, and transportation — Production and ad valorem taxes — — Marketing — — — Exploration — — — Impairment of unproved properties — — — Depletion, depreciation, and amortization — — Accretion of asset retirement obligations — — — General and administrative — Total operating expenses — Operating income — — Other income (expenses): Interest — — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income before income taxes — Provision for income tax expense — — — Income from continuing operations — Discontinued operations: Income from sale of discontinued operations, net of income taxes — — — Net income and comprehensive income including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income and comprehensive income attributable to Antero Resources Corporation $ — Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenue: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — Marketing — — — Commodity derivative fair value gains — — — Other income — — — Total revenue — Operating expenses: Lease operating — Gathering, compression, processing, and transportation — Production and ad valorem taxes — — Marketing — — — Exploration — — — Impairment of unproved properties — — — Depletion, depreciation, and amortization — — Accretion of asset retirement obligations — — — General and administrative — Contract termination and rig stacking — — — Accretion of contingent acquisition consideration — — — Total operating expenses — Operating income — Other income (expenses): Interest — — Equity in net income of subsidiaries — — — Total other expenses — Income before income taxes — Provision for income tax expense — — — Net income and comprehensive income including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income and comprehensive income attributable to Antero Resources Corporation $ — Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ — — Cash flows used in investing activities: Additions to proved properties — — — Additions to unproved properties — — — Drilling and completion costs — — — Additions to water handling and treatment systems — — — Additions to gathering systems and facilities — — Additions to other property and equipment — — — Change in other assets — — Net distributions from guarantor subsidiary — — — Distributions from non-guarantor subsidiary — — — Net cash used in investing activities — Cash flows provided by (used in) financing activities: Issuance of common units in Antero Midstream Partners LP — — — Issuance of senior notes — — — Repayment of senior notes — — — Borrowings (repayments) on bank credit facility, net — Make-whole premium on debt extinguished — — — Payments of deferred financing costs — — Distributions — — Other — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ — — Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ — — Cash flows used in investing activities: Additions to unproved properties — — — Drilling and completion costs — — — Additions to water handling and treatment systems — — Additions to gathering systems and facilities — — Additions to other property and equipment — — — Change in other assets — — Net distributions from guarantor subsidiary — — — Distributions from non-guarantor subsidiary — — — Proceeds from contribution of assets to non-guarantor subsidiary — — — Proceeds from asset sales — — — Net cash used in investing activities — Cash flows provided by (used in) financing activities: Issuance of common stock — — — Issuance of common units in Antero Midstream Partners LP — — — Issuance of senior notes — — — Borrowings (repayments) on bank credit facility, net — Payments of deferred financing costs — — Distributions — Other — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — Cash and cash equivalents, beginning of period — — Cash and cash equivalents, end of period $ — —

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information (Unaudited)
Quarterly Financial Information (Unaudited)	(17) Quarterly Financial Information (Unaudited) The Company’s quarterly consolidated financial information for the years ended December 31, 2014 and 2015 is summarized in the following table (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 quarter Second quarter Third quarter Fourth quarter Year Ended December 31, 2014: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) Income (loss) from continuing operations Income from discontinued operations — — — Net income (loss) and comprehensive income (loss) including noncontrolling interest Net income attributable to noncontrolling interest — — — Net income (loss) attributable to Antero Resources Corporation Earnings (loss) per common share: Continuing operations $ $ $ $ Discontinued operations — — — Net income (loss) $ $ $ $ Earnings (loss) per common share—diluted: Continuing operations $ $ $ $ Discontinued operations — — — Net income (loss) $ $ $ $ First quarter Second quarter Third quarter Fourth quarter Year Ended December 31, 2015: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) Income (loss) from continuing operations Net income (loss) and comprehensive income (loss) including noncontrolling interest Net income attributable to noncontrolling interest Net income (loss) attributable to Antero Resources Corporation Earnings (loss) per common share $ $ $ $ Earnings (loss) per common share—diluted $ $ $ $

Supplemental Information on Oil

Supplemental Information on Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2015
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)	(18) 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) 2014 2015 Proved properties $ $ Unproved properties Accumulated depletion and depreciation Net capitalized costs $ $ (b) Costs Incurred in Certain Oil and Gas Activities Year ended December 31, (In thousands) 2013 2014 2015 Acquisition costs: Proved property $ $ $ — Unproved property Development costs Exploration costs Total costs incurred $ $ $ (c) Results of Operations for Oil and Gas Producing Activities Year ended December 31, (In thousands) 2013 2014 2015 Revenues $ $ $ Operating expenses: Production expenses Exploration expenses Depletion and depreciation Impairment of unproved properties Results of operations before income tax expense Income tax expense Results of operations $ $ $ (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 oil and gas segment’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the year ended December 31, 2013, 2014, and 2015 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; and cash flows from operations, future drilling costs, demand for natural gas, and other economic factors. Natural gas (Bcf) NGLs (MMBbl) Oil and condensate (MMBbl) Equivalents (Bcfe) Proved reserves: December 31, 2012 Revisions — (a) Extensions, discoveries and other additions Production — (a) December 31, 2013 Revisions — (a) Extensions, discoveries and other additions Purchases — — Production December 31, 2014 Revisions Extensions, discoveries and other additions Production December 31, 2015 (a) Less than 1.0. Natural gas (Bcf) NGLs (MMBbl) Oil and condensate (MMBbl) Equivalents (Bcfe) Proved developed reserves: December 31, 2013 December 31, 2014 December 31, 2015 Proved undeveloped reserves: December 31, 2013 December 31, 2014 December 31, 2015 Significa nt items included in the categories of proved developed and undeveloped reserve changes for the years 2013, 2014, and 2015 in the above table include the following: 2013 Changes in Reserves · Extensions, discoveries, and other additions during 2013 of 3,682 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. · Downward revisions of 788 Bcfe resulted from changing the underlying production assumption used to estimate reserves to ethane rejection at December 31, 2013 from ethane recovery at December 31, 2012 as well as the reclassification of certain wells to the probable reserves category in 2013 because they are no longer expected to be drilled within five years of initial booking. 2014 Changes in Reserves · 2014— Extensions, discoveries, and other additions during 2014 of 6,444 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. · Purchases of 29 Bcfe relate to 5 horizontal producing wells acquired as part of our leasehold acquisition efforts. · Upward performance revisions of 361 Bcfe relate to improved well performance from shorter stage length completions. · Downward revisions of 1,417 Bcfe due were due to the reclassification of 191 dry gas locations to the probable category because they were no longer expected to be drilled within five years of initial booking. · Upward price revisions of 2 Bcfe were due to increases in the reference price for natural gas, partially offset by decreases in the prices for NGLs and oil. 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. · Upward 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, we began ethane recovery and changed our 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 we no longer expect certain locations in the eastern portion of our 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. 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) 2013 2014 2015 Future cash inflows $ $ $ Future production costs Future development costs Future net cash flows before income tax Future income tax expense Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows $ $ $ The 12 ‑month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe): December 31, 2013 $ December 31, 2014 $ December 31, 2015 $ (f) Changes in Standardized Measure of Discou nted Future Net Cash Flow Year ended December 31, (in millions) 2013 2014 2015 Sales of oil and gas, net of productions costs $ $ $ Net changes in prices and production costs Development costs incurred during the period Net changes in future development costs Extensions, discoveries and other additions Acquisitions — Revisions of previous quantity estimates Accretion of discount Net change in income taxes Other changes Net increase (decrease) Beginning of year End of year $ $ $

Summary of Significant Accoun26

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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, 2014 and 2015 , and the results of its operations and its cash flows for the years ended December 31, 2013 , 2014 , and 2015 . 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 Securities and Exchange Commission, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified.
Principles of Consolidation	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 in which the Company is the primary beneficiary. 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 third-party individuals or entities, or Antero Midstream’s general partner. An affiliate of the Company owns the general partner interest in Antero Midstream. Noncontrolling interest is included as a component of equity in the Company’s consolidated balance sheets.
Use of Estimates	Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as the reported amounts of revenues and expenses during the reporting period. 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 in the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in the prices the Company receives for its production could have a significant impact on the Company’s future results of operations and reserve quantities.
Cash and Cash Equivalents	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.
Oil and Gas Properties	Oil and Gas Properties The Company accounts for its natural gas 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, 2013, 2014, and 2015. 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 with significant acquisition costs 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. Other unproved properties are assessed for impairment on an aggregate basis. 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 $10.9 million, $15.2 million, and $104.3 million for the years ended December 31, 2013 , 2014 , and 2015 , 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 determine 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 determine 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 properties during the year ended December 31, 2015. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2013 and 2014. At December 31, 2015 , the Company did not have significant capitalized costs related to exploratory wells ‑in ‑progress which were pending determination of proved reserves. The Company also had no significant costs which have been deferred for longer than one year pending determination of proved reserves at December 31, 2015 . The provision for depletion, depreciation, and amortization of oil and gas properties is calculated on a geological reservoir basis using the units ‑of ‑production method. Depletion, depreciation, and amortization expense for oil and gas properties was $219.8 million, $418.7 million, and $614.7 million for the years ended December 31, 2013 , 2014 , and 2015 , respectively.
Gathering Pipelines, Compressor Stations, and Water Handling 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 $11.9 million, $53.2 million, and $87.4 million for the years ended December 31, 2013 , 2014 , and 2015 , 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	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 unit being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair value, which is based on discounted future cash flows or other techniques, as appropria te. There were no impairments for such assets during the years ended December 31, 2013 , 2014 , and 2015 .
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 $2.2 million, $5.9 million, and $7.7 million for the years ended December 31, 2013 , 2014 , and 2015 , respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs represent loan origination fees, initial purchasers’ discounts, and other borrowing costs, and are included in noncurrent other assets on the consolidated balance sheets. These costs are amortized over the term of the related debt instrument using the effective interest method. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2015 , the Company had $59 million of unamortized deferred financing costs included in other long ‑term assets. The amounts amortized and the write ‑off of previously deferred debt issuance costs were $15.8 million, $11.0 million, and $10.1 million for the years ended December 31, 2013 , 2014 , and 2015 , 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, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its 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 an asset or liability 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 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	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. The 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 ARO can result from changes in retirement cost estimates and 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 the obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. The Company delivers natural gas through its gathering assets and delivers water through its water handling and treatment assets and may become obligated by regulatory or other requirements to remove certain facilities or perform other remediation upon retirement of these assets. However, the Company cannot reasonably predict when production from existing reserves of the fields in which it operates will cease. In the absence of such information, management is not able to make a reasonable estimate of when future dismantlement and removal dates will occur; therefore, the Company has not recorded asset retirement obligations related to its gathering and water handling and treatment assets.
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, 2014 and 2015 , the Company did not have a material amount accrued for any environmental liabilities, nor has the Company been cited for any environmental violations that are likely to have a material adverse effect on future capital expenditures or operating results of the Company.
Natural Gas, NGLs, and Oil Reserves	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 natural gas revenues. At December 31, 2014 and 2015 , the Company had no significant imbalance positions.
Concentrations of Credit Risk	Concentrations of Credit Risk The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry. The concentration of credit risk in a single industry 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, 2013 , 2014 , and 2015 are as follows: 2013 2014 2015 Company A — % 5 % 19 % Company B 30 29 18 Company C 14 16 13 Company D 8 12 9 All others 48 38 41 100 % 100 % 100 % Although a substantial portion of the Company’s production is purchased by these major customers, the Company does not believe the loss of any one or several customers would have a material adverse effect on its business, as other customers or markets would be accessible. 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, all of which are a lender under Antero’s Credit Facility. The fair value of the Company’s commodity derivative contracts of approximately $ 3.1 billion at December 31, 2015 includes the following values by bank counterparty: Morgan Stanley— $691 million; Barclays— $593 million; JP Morgan— $575 million; Citigroup— $362 million; Wells Fargo— $285 million; Scotiabank— $214 million; BNP Paribas— $188 million; Toronto Dominion Bank— $76 million; Fifth Third Bank— $41 million; Canadian Imperial Bank of Commerce— $37 million; Bank of Montreal— $29 million; SunTrust— $17 million; Capital One— $8 million; and Natixis— $1 million. The credit ratings of certain of these banks were downgraded in recent years because of the sovereign debt crisis in Europe. 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, 2015 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts.
Income Taxes	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 the tax laws or tax rates is recognized in income in the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense.
Fair Value Measurements	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). The 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 and basis 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 compression; (3) water handling and treatment; and ( 4 ) marketing of excess firm transportation capacity. The Company identified marketing of excess firm transportation capacity as a new operating segment in 2014. 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.
Marketing Revenues and Expenses	Marketing Revenues and Expenses In 2014, the Company commenced activities 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. The costs of unutilized capacity are charged to transportation expense.
Earnings (loss) per common share	Earnings (loss) per common share Earnings (loss) per common share for each period is computed by dividing net income (loss) from continuing operations attributable to Antero or income from discontinued operations, as applicable, by the basic weighted average number of shares outstanding during such period. Earnings per common share—assuming dilution for each period is computed giving consideration to the potential dilution from outstanding equity awards, calculated using the treasury stock method. 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: Year ended December 31, 2013 2014 2015 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock and restricted stock units — Add: Dilutive effect of outstanding stock options — — — Diluted weighted average number of shares outstanding 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 — Outstanding stock options — (1) The potential dilutive effects of these awards were excluded from the computation of earnings per common share—assuming dilution because the inclusion of these awards would have been anti-dilutive.
New Accounting Principle	New Accounting Principle On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes–Balance Sheet Classification of Deferred Taxes , which requires that deferred income tax liabilities and assets be presented in the balance sheet as noncurrent. The new standard becomes effective for the Company on January 1, 2017. However, the Company has elected to early-adopt the standard as of December 31, 2015. The Company has also elected to apply this standard retrospectively; as such, deferred taxes have been recast as noncurrent for all prior periods presented in this Form 10-K. The Company does not believe that this standard has a material impact on its ongoing financial reporting. The retrospective adjustment to the December 31, 2014 consolidated balance sheet is as follows: As Previously Reported Adjustment As Adjusted December 31, 2014 Effect December 31, 2014 Net deferred income tax liability - current $ — Net deferred income tax liability - long-term Total net deferred tax liabilities $ —

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of Significant Accounting Policies
Reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding	Year ended December 31, 2013 2014 2015 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock and restricted stock units — Add: Dilutive effect of outstanding stock options — — — Diluted weighted average number of shares outstanding 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 — Outstanding stock options —
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales)	2013 2014 2015 Company A — % 5 % 19 % Company B 30 29 18 Company C 14 16 13 Company D 8 12 9 All others 48 38 41 100 % 100 % 100 %
New Accounting Pronouncement, Early Adoption [Table Text Block]	As Previously Reported Adjustment As Adjusted December 31, 2014 Effect December 31, 2014 Net deferred income tax liability - current $ — Net deferred income tax liability - long-term Total net deferred tax liabilities $ —

Sale of Piceance and Arkoma P28

Sale of Piceance and Arkoma Properties - Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Piceance Basin and Arkoma Basin
Schedule of results of operations and the loss on the sale of the Piceance Basin and Arkoma Basin assets shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss)	Income from discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) is comprised of the following (in thousands): Year ended December 31, 2013 2014 2015 Income from discontinued operations before income taxes — Income tax expense — Net income from discontinued operations $ —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Long-Term Debt
Schedule of long-term debt	Long ‑term debt was follows at December 31, 2014 and 2015 (in thousands): 2014 2015 Antero: Bank credit facility(a) $ 6.00% senior notes due 2020(c) 5.375% senior notes due 2021(d) 5.125% senior notes due 2022(e) 5.625% senior notes due 2023(f) — Net unamortized premium Antero Midstream: Bank credit facility(b) — $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2014 and 2015 (in thousands). 2014 2015 Asset retirement obligations—beginning of year $ $ Obligations incurred for wells drilled Revisions to prior estimates — Accretion expense Asset retirement obligations—end of year $ $

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Equity-Based Compensation
Schedule of equity-based compensation expense	The Company’s equity ‑based compensation expense is as follows for the years ended December 31, 2013 , 2014 , and 2015 (in thousands): Year ended December 31, 2013 2014 2015 Profits interests awards $ Restricted stock awards Stock options Antero Midstream phantom and restricted unit awards — Common stock issued to directors in lieu of cash compensation — Total expense $
Summary of restricted stock and restricted stock unit awards activity	Weighted average Aggregate Number of shares grant date fair value intrinsic value (in thousands) Total awarded and unvested—December 31, 2014 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2015 $ $
Summary of stock option activity	Weighted Weighted average average remaining Intrinsic Stock options exercise price contractual life value (in thousands) Outstanding at December 31, 2014 $ $ — Granted $ Exercised — — Forfeited $ Expired — — Outstanding at December 31, 2015 $ $ — Vested or expected to vest as of December 31, 2015 $ $ — Exercisable at December 31, 2015 $ $ —
Schedule of information regarding weighted average fair value of options granted and the assumptions used to determine fair value	Year ended December 31, 2013 2014 2015 Dividend yield — % — % — % Volatility % % % Risk-free interest rate % % % Expected life (years) Weighted average fair value of options granted $ $ $
Schedule of outstanding unvested restricted stock awards vesting schedule	Number of units Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested—December 31, 2014 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2015 $ $

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of outstanding commodity derivatives	Natural gas MMbtu/day Propane Bbls/day Weighted average index price Three months ending March 31, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending June 30, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending September 30, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Three months ending December 31, 2016: TCO ($/MMBtu) — $ Dominion South ($/MMBtu) — $ NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2017: NYMEX ($/MMBtu) — $ CGTLA ($/MMBtu) — $ CCG ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2018: NYMEX ($/MMBtu) — $ Mont Belvieu-TET ($/Gallon) — $ Total Year ending December 31, 2019: NYMEX ($/MMBtu) $ Year ending December 31, 2020: NYMEX ($/MMBtu) $ Year ending December 31, 2021: NYMEX ($/MMBtu) $ Year ending December 31, 2022: NYMEX ($/MMBtu) $
Summary of the fair values of derivative instruments, which are not designated as hedges for accounting purposes	December 31, 2014 December 31, 2015 Balance sheet location Fair value Balance sheet location Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ Current assets $ Commodity contracts Long-term assets Long-term assets Total asset derivatives Total liability derivatives — — Net derivatives $ $
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 amounts 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, 2014 December 31, 2015 Gross amounts on balance sheet Gross amounts offset on balance sheet Net amounts of assets on balance sheet Gross amounts on balance sheet Gross amounts offset on balance sheet Net amounts of assets on balance sheet Commodity derivative assets $ $ Commodity derivative liabilities $ — — — $ — — —
Summary of derivative fair value gains (losses)	The following is a summary of derivative fair value gains and where such values are recorded in the consolidated statemen ts of operations for the years ended December 31, 2013 , 2014 , and 2015 (in thousands): Statement of operations Year ended December 31, location 2013 2014 2015 Commodity derivative fair value gains Revenue $
TCOminusNYMEX
Tabular disclosure of commodity derivatives basis differential positions which settle on the pricing index to basis differential of Columbia Gas (TCO) to the NYMEX Henry Hub natural gas price.	Natural gas MMbtu/day Hedged Differential Year ending December 31, 2016: $ Year ending December 31, 2017: $
NYMEXminusTCO
Tabular disclosure of commodity derivatives basis differential positions which settle on the pricing index to basis differential of NYMEX Henry Hub to the Columbia Gas (TCO) natural gas price	Natural gas MMbtu/day Hedged Differential Year ending December 31, 2016: $ Year ending December 31, 2017: $

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Taxes
Schedule of income tax expense from continuing operations	For the years ended December 31, 2013 , 2014 , and 2015 , income tax expense from continuing operations consisted of the fol lowing (in thousands): Year ended December 31, 2013 2014 2015 Current income tax benefit $ — — Deferred income tax expense Total income tax expense from continuing operations $
Schedule of reconciliation of income tax expense from continuing operations	Income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to income from continuing operations for the years ended December 31, 2013 , 2014 , and 2015 as a result of the following (in thousands): Year ended December 31, 2013 2014 2015 Federal income tax expense $ State income tax expense, net of federal benefit Nondeductible equity-based compensation Noncontrolling interest in Antero Midstream Partners LP — Change in valuation allowance Other Total income tax expense from continuing operations $
Schedule of income tax expense (benefit) allocated to continuing and discontinued operations	For the years ended December 31, 2013 , 2014 , and 2015 , income tax expense was allocated to continuing and discontinued operations as follows (in thousands): Year ended December 31, 2013 2014 2015 Continuing operations $ Discontinued operations and sale of discontinued operations — Total income tax expense $
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, 2014 and 2015 is as follows (in thousands): 2014 2015 Deferred tax assets: Net operating loss carryforwards $ Minimum tax credit carryforward Equity-based compensation Other Total deferred tax assets Valuation allowance Net deferred tax assets Deferred tax liabilities: Unrealized gains on derivative instruments Oil and gas properties Investment in Antero Midstream Partners LP Total deferred tax liabilities Net deferred tax liabilities $
Schedule of reconciliation of beginning and ending amount of unrecognized tax benefits	2013 2014 2015 Balance at beginning of year $ Revised estimate of unrecognized tax position — — Balance at end of year $

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments
Schedule of future minimum payments for firm transportation, drilling rig and hydraulic fracturing and gas processing gathering and compression, office and equipment agreements, and leases that have remaining lease terms in excess of one year	The following is a schedule of future minimum payments for firm transportation, drilling rig, hydraulic fracturing, 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, 2015 (in millions). Firm transportation Processing, gathering and compression Drilling rigs and frac services Office and equipment (a) (b) (c) (d) Total Year ending December 31: 2016 $ 2017 2018 2019 — 2020 — Thereafter — Total $

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2013 , 2014 , and 2015 (in thousands): Exploration and production Gathering and compression Water handling and treatment Elimination of intersegment transactions Consolidated total Year ended December 31, 2013: Sales and revenues: Third-party $ — — — Intersegment — — Total $ Operating expenses: Lease operating $ — Gathering, compression, processing, and transportation — Depletion, depreciation, and amortization — General and administrative expense — Other operating expenses — — Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ Exploration and production Gathering and compression Water handling and treatment Marketing Elimination of intersegment transactions Consolidated total Year ended December 31, 2014: Sales and revenues: Third-party $ — Intersegment — — Total $ Operating expenses: Lease operating $ — — Gathering, compression, processing, and transportation — — Depletion, depreciation, and amortization — — General and administrative expense — Other operating expenses — Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ — Exploration and production Gathering and compression Water handling and treatment Marketing Elimination of intersegment transactions Consolidated total Year ended December 31, 2015: Sales and revenues: Third-party $ — Intersegment — — Total $ Operating expenses: Lease operating $ — — Gathering, compression, processing, and transportation — — Depletion, depreciation, and amortization — — General and administrative expense — Other operating expenses Total Operating income (loss) $ Segment assets $ Capital expenditures for segment assets $ —

Subsidiary Guarantors (Tables)

Subsidiary Guarantors (Tables)	12 Months Ended
	Dec. 31, 2015
Subsidiary Guarantors
Schedule of condensed consolidated balance sheets	Condensed Consolidating Balance Sheet December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ — — Accounts receivable, net — — — Intercompany receivables — — Accrued revenue — — — Derivative instruments — — — Other current assets Total current assets Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties — — — Proved properties — — — Water handling and treatment systems — — — Gathering systems and facilities — — Other property and equipment — — — — — Less accumulated depletion, depreciation, and amortization — — Property and equipment, net — — Derivative instruments — — — Investments in subsidiaries — — — Other assets, net — — Total assets $ Liabilities and Equity Current liabilities: Accounts payable $ — — Intercompany payable — — Accrued liabilities — — Revenue distributions payable — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Other liabilities — — — Total liabilities Equity: Stockholders' equity: Parent net investment — — — Partners' capital — — — Common stock — — — Additional paid-in capital — — — Accumulated earnings — — — Total stockholders' equity Noncontrolling interest in consolidated subsidiary — — — Total equity Total liabilities and equity $ Condensed Consolidating Balance Sheet December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ — — Accounts receivable, net — — Intercompany receivables — — Accrued revenue — — — Derivative instruments — — — Other current assets — — — Total current assets — Property and equipment: Natural gas properties, at cost (successful efforts method): Unproved properties — — — Proved properties — — Water handling and treatment systems — — — Gathering systems and facilities — — Other property and equipment — — — — Less accumulated depletion, depreciation, and amortization — — Property and equipment, net — Derivative instruments — — — Investments in subsidiaries — — — Contingent acquisition consideration — — — Other assets, net — — Total assets $ — Liabilities and Equity Current liabilities: Accounts payable $ — — Intercompany payable — — Accrued liabilities — — Revenue distributions payable — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Contingent acquisition consideration — — — Other liabilities — — Total liabilities — Equity: Stockholders' equity: Partners' capital — — — Common stock — — — Additional paid-in capital — — — Accumulated earnings — — — Total stockholders' equity — Noncontrolling interest in consolidated subsidiary — — — Total equity — Total liabilities and equity $ —
Schedule of condensed consolidated statement of operations and comprehensive income (loss)	Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenue: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — Marketing — — — Commodity derivative fair value gains — — — Gain on sale of gathering system — — — Other income — — — Total revenue — Operating expenses: Lease operating — — — Gathering, compression, processing, and transportation — Production and ad valorem taxes — — Marketing — — — Exploration — — — Impairment of unproved properties — — — Depletion, depreciation, and amortization — — Accretion of asset retirement obligations — — — General and administrative — Total operating expenses — Operating income — — Other income (expenses): Interest — — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income before income taxes — Provision for income tax expense — — — Income from continuing operations — Discontinued operations: Income from sale of discontinued operations, net of income taxes — — — Net income and comprehensive income including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income and comprehensive income attributable to Antero Resources Corporation $ — Condensed Consolidating Statement of Operations and Comprehensive Income Year Ended December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenue: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — Marketing — — — Commodity derivative fair value gains — — — Other income — — — Total revenue — Operating expenses: Lease operating — Gathering, compression, processing, and transportation — Production and ad valorem taxes — — Marketing — — — Exploration — — — Impairment of unproved properties — — — Depletion, depreciation, and amortization — — Accretion of asset retirement obligations — — — General and administrative — Contract termination and rig stacking — — — Accretion of contingent acquisition consideration — — — Total operating expenses — Operating income — Other income (expenses): Interest — — Equity in net income of subsidiaries — — — Total other expenses — Income before income taxes — Provision for income tax expense — — — Net income and comprehensive income including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income and comprehensive income attributable to Antero Resources Corporation $ —
Schedule of condensed consolidated statement of cash flows	Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ — — Cash flows used in investing activities: Additions to proved properties — — — Additions to unproved properties — — — Drilling and completion costs — — — Additions to water handling and treatment systems — — — Additions to gathering systems and facilities — — Additions to other property and equipment — — — Change in other assets — — Net distributions from guarantor subsidiary — — — Distributions from non-guarantor subsidiary — — — Net cash used in investing activities — Cash flows provided by (used in) financing activities: Issuance of common units in Antero Midstream Partners LP — — — Issuance of senior notes — — — Repayment of senior notes — — — Borrowings (repayments) on bank credit facility, net — Make-whole premium on debt extinguished — — — Payments of deferred financing costs — — Distributions — — Other — — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — Cash and cash equivalents, beginning of period — — — Cash and cash equivalents, end of period $ — — Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2015 (In thousands) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ — — Cash flows used in investing activities: Additions to unproved properties — — — Drilling and completion costs — — — Additions to water handling and treatment systems — — Additions to gathering systems and facilities — — Additions to other property and equipment — — — Change in other assets — — Net distributions from guarantor subsidiary — — — Distributions from non-guarantor subsidiary — — — Proceeds from contribution of assets to non-guarantor subsidiary — — — Proceeds from asset sales — — — Net cash used in investing activities — Cash flows provided by (used in) financing activities: Issuance of common stock — — — Issuance of common units in Antero Midstream Partners LP — — — Issuance of senior notes — — — Borrowings (repayments) on bank credit facility, net — Payments of deferred financing costs — — Distributions — Other — — Net cash provided by (used in) financing activities — Net increase (decrease) in cash and cash equivalents — — Cash and cash equivalents, beginning of period — — Cash and cash equivalents, end of period $ — —

Quarterly Financial Informati37

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information (Unaudited)
Schedule of quarterly financial information	The Company’s quarterly consolidated financial information for the years ended December 31, 2014 and 2015 is summarized in the following table (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 quarter Second quarter Third quarter Fourth quarter Year Ended December 31, 2014: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) Income (loss) from continuing operations Income from discontinued operations — — — Net income (loss) and comprehensive income (loss) including noncontrolling interest Net income attributable to noncontrolling interest — — — Net income (loss) attributable to Antero Resources Corporation Earnings (loss) per common share: Continuing operations $ $ $ $ Discontinued operations — — — Net income (loss) $ $ $ $ Earnings (loss) per common share—diluted: Continuing operations $ $ $ $ Discontinued operations — — — Net income (loss) $ $ $ $ First quarter Second quarter Third quarter Fourth quarter Year Ended December 31, 2015: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) Income (loss) from continuing operations Net income (loss) and comprehensive income (loss) including noncontrolling interest Net income attributable to noncontrolling interest Net income (loss) attributable to Antero Resources Corporation Earnings (loss) per common share $ $ $ $ Earnings (loss) per common share—diluted $ $ $ $

Supplemental Information on O38

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2014 2015 Proved properties $ $ Unproved properties Accumulated depletion and depreciation Net capitalized costs $ $
Schedule of costs incurred in certain oil and gas activities	Year ended December 31, (In thousands) 2013 2014 2015 Acquisition costs: Proved property $ $ $ — Unproved property Development costs Exploration costs Total costs incurred $ $ $
Schedule of results of operations (including discontinued operations) for oil and gas producing activities	Year ended December 31, (In thousands) 2013 2014 2015 Revenues $ $ $ Operating expenses: Production expenses Exploration expenses Depletion and depreciation Impairment of unproved properties Results of operations before income tax expense Income tax expense Results of operations $ $ $
Schedule of proved developed and undeveloped reserves	Natural gas (Bcf) NGLs (MMBbl) Oil and condensate (MMBbl) Equivalents (Bcfe) Proved reserves: December 31, 2012 Revisions — (a) Extensions, discoveries and other additions Production — (a) December 31, 2013 Revisions — (a) Extensions, discoveries and other additions Purchases — — Production December 31, 2014 Revisions Extensions, discoveries and other additions Production December 31, 2015 (a) Less than 1.0. Natural gas (Bcf) NGLs (MMBbl) Oil and condensate (MMBbl) Equivalents (Bcfe) Proved developed reserves: December 31, 2013 December 31, 2014 December 31, 2015 Proved undeveloped reserves: December 31, 2013 December 31, 2014 December 31, 2015
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves	Year ended December 31, (in millions) 2013 2014 2015 Future cash inflows $ $ $ Future production costs Future development costs Future net cash flows before income tax Future income tax expense Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted future net cash flows $ $ $
Schedule of weighted average prices used to estimate the Company's total equivalent reserves	December 31, 2013 $ December 31, 2014 $ December 31, 2015 $
Schedule of changes in standardized measure of discounted future net cash flow	Year ended December 31, (in millions) 2013 2014 2015 Sales of oil and gas, net of productions costs $ $ $ Net changes in prices and production costs Development costs incurred during the period Net changes in future development costs Extensions, discoveries and other additions Acquisitions — Revisions of previous quantity estimates Accretion of discount Net change in income taxes Other changes Net increase (decrease) Beginning of year End of year $ $ $

Summary of Significant Accoun39

Summary of Significant Accounting Policies - Fair Value of Derivative Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)segmentCounterparty
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 3,100
Number of counterparties | Counterparty	14
Industry Segment and Geographic Information
Number of operating segments | segment	4
Citigroup
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 362
Barclays
Derivative Financial Instruments
Fair value of commodity derivative contracts	593
JP Morgan
Derivative Financial Instruments
Fair value of commodity derivative contracts	575
Wells Fargo
Derivative Financial Instruments
Fair value of commodity derivative contracts	285
BNP Paribas
Derivative Financial Instruments
Fair value of commodity derivative contracts	188
Scotiabank
Derivative Financial Instruments
Fair value of commodity derivative contracts	214
Toronto Dominion Bank
Derivative Financial Instruments
Fair value of commodity derivative contracts	76
Fifth Third Bank
Derivative Financial Instruments
Fair value of commodity derivative contracts	41
Canadian Imperial Bank of Commerce
Derivative Financial Instruments
Fair value of commodity derivative contracts	37
Bank of Montreal
Derivative Financial Instruments
Fair value of commodity derivative contracts	29
Morgan Stanley
Derivative Financial Instruments
Fair value of commodity derivative contracts	691
SunTrust
Derivative Financial Instruments
Fair value of commodity derivative contracts	17
Capital One
Derivative Financial Instruments
Fair value of commodity derivative contracts	8
Natixis
Derivative Financial Instruments
Fair value of commodity derivative contracts	$ 1

Summary of Significant Accoun40

Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings per share
Weighted Average Number of Shares Outstanding, Basic	274,122,567	262,053,868	262,049,659
Weighted Average Number of Shares Outstanding, Diluted	274,143,341	262,068,106	262,049,659
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Net deferred income tax liability - long-term	$ 1,370,686	$ 794,796
Deferred Income Tax Liabilities, Net		794,796
As Previously Reported
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Net deferred income tax liability - current		260,373
Net deferred income tax liability - long-term		534,423
Deferred Income Tax Liabilities, Net		794,796
Adjustment Effect
New Accounting Pronouncement or Change in Accounting Principle, Retrospective Adjustments [Abstract]
Net deferred income tax liability - current		(260,373)
Net deferred income tax liability - long-term		$ 260,373
Restricted Stock and Restricted Stock Unit
Earnings per share
Dilutive effect of equity awards	20,774	14,238
Weighted Average Anti-dilutive Awards	2,264,394	1,444,023
Stock options
Earnings per share
Weighted Average Anti-dilutive Awards	553,297	72,592

Summary of Significant Accoun41

Summary of Significant Accounting Policies (Details 3) - USD ($)	12 Months Ended			36 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Other Property and Equipment
Depreciation expense	$ 709,763,000	$ 477,896,000	$ 233,876,000
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	104,300,000	15,200,000	10,900,000
Impairment of proved properties	$ 0	0	0
Period of deferment of significant costs, pending proved reserves	1 year
Depreciation, depletion, and amortization expense for oil and gas properties	$ 614,700,000	418,700,000	219,800,000
Impairment of long-lived assets other than oil and gas properties				$ 0
Deferred Financing Costs
Unamortized deferred financing costs included in other long-term assets	59,000,000			$ 59,000,000
Amounts amortized and the write-off of previously deferred debt issuance costs	$ 10,100,000	11,000,000	15,800,000
Gathering Systems and Facilities
Other Property and Equipment
Estimated useful life	P20Y
Other property and equipment
Other Property and Equipment
Depreciation expense	$ 7,700,000	5,900,000	2,200,000
Other property and equipment | Minimum
Other Property and Equipment
Estimated useful life	P2Y
Other property and equipment | Maximum
Other Property and Equipment
Estimated useful life	P20Y
Gathering pipelines, compressor stations, and fresh water distribution systems
Other Property and Equipment
Depreciation expense	$ 87,400,000	$ 53,200,000	$ 11,900,000
Water handling and treatment | Minimum
Other Property and Equipment
Estimated useful life	P5Y
Water handling and treatment | Maximum
Other Property and Equipment
Estimated useful life	P20Y

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Details 4) - Sales - Customer concentration	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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)	19.00%	5.00%
Company B
Concentrations of Credit Risk
Sales to major customers (as a percent)	18.00%	29.00%	30.00%
Company C
Concentrations of Credit Risk
Sales to major customers (as a percent)	13.00%	16.00%	14.00%
Company D
Concentrations of Credit Risk
Sales to major customers (as a percent)	9.00%	12.00%	8.00%
All others
Concentrations of Credit Risk
Sales to major customers (as a percent)	41.00%	38.00%	48.00%

Antero Midstream Partners LP (D

Antero Midstream Partners LP (Details) $ in Millions	Dec. 31, 2015	Sep. 23, 2015USD ($)sharesbbl	Dec. 31, 2014
Antero Resources Corp
Antero Midstream Partners LP
Limited partner ownership interest	66.30%		69.70%
Antero Midstream Partners LP
Antero Midstream Partners LP
Cash distribution		$ 552
Assumed debt		$ 171
Common units issued | shares		10,988,421
Amount borrowed on bank credit facility		$ 525
Antero Midstream Partners LP | Contingent Consideration Period One
Antero Midstream Partners LP
Contingent consideration		$ 125
Threshold number of barrels of water to trigger contingent consideration payment | bbl		176,295,000
Antero Midstream Partners LP | Contingent Consideration Period Two
Antero Midstream Partners LP
Contingent consideration		$ 125
Threshold number of barrels of water to trigger contingent consideration payment | bbl		219,200,000
Antero Midstream Partners LP | Private Placement
Antero Midstream Partners LP
Proceeds from issuance of common units		$ 241

Sale of Piceance and Arkoma P44

Sale of Piceance and Arkoma Properties - Discontinued Operations (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013
Discontinued Operations:
Income from discontinued operations before income taxes		$ 3,564	$ 8,506
Income tax expense		(1,354)	(3,249)
IncomeLossFromDiscontinuedOperationsNetOfTax	$ 2,210	$ 2,210	$ 5,257

Sale of Appalachian Gathering45

Sale of Appalachian Gathering Assets (Details) - USD ($) $ in Thousands	Mar. 31, 2012	Dec. 31, 2014
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Gain on sale of gathering system		$ 40,000
Appalachian Gathering Assets
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Gain on sale of gathering system		$ 40,000
Period for which entity is committed to deliver minimum annual volumes into gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies	7 years
Period of exclusive rights to gather the gas within AOD	20 years

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($)	Sep. 18, 2014	Feb. 04, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 17, 2015	May. 06, 2014	Nov. 05, 2013	Nov. 19, 2012
Long- term Debt
Net unamortized premium			$ 6,513,000	$ 7,550,000
Long-term debt Noncurrent			4,708,513,000	4,362,550,000
Loss on Early Extinguishment of Debt				(20,386,000)	$ (42,567,000)
Midstream Credit Facility Member
Long- term Debt
Bank credit facility long-term debt			620,000,000
Maximum amount of the Credit Facility			$ 1,500,000,000
Weighted average interest rate (as a percent)			1.92%
Midstream Credit Facility Member | Minimum
Long- term Debt
Commitment fees on the unused portion (as a percent)			0.25%
Midstream Credit Facility Member | Maximum
Long- term Debt
Commitment fees on the unused portion (as a percent)			0.375%
Bank credit facility
Long- term Debt
Bank credit facility long-term debt			$ 707,000,000	1,730,000,000
Current borrowing base			4,500,000,000
Lender commitments			4,000,000,000
Outstanding balance			$ 707,000,000	$ 1,700,000,000
Weighted average interest rate (as a percent)			2.32%	2.06%
Outstanding letters of credit			$ 702,000,000	$ 387,000,000
Bank credit facility | Minimum
Long- term Debt
Commitment fees on the unused portion (as a percent)			0.375%
Bank credit facility | Maximum
Long- term Debt
Commitment fees on the unused portion (as a percent)			0.50%
6.00% senior notes due 2020
Long- term Debt
Long-term notes payable			$ 525,000,000	525,000,000
Interest rate (as a percent)									6.00%
Senior notes issued		$ 225,000,000							$ 300,000,000
Issue price as percentage of par value		103.00%
Redemption price			104.50%
Percentage of principal amount at which notes may be required to be repurchased in event of change of control			101.00%
6.00% senior notes due 2020 | On or after December 1, 2018
Long- term Debt
Redemption price of the debt instrument in the event of change of control (as a percent)			100.00%
5.375% senior notes due 2021
Long- term Debt
Long-term notes payable			$ 1,000,000,000	1,000,000,000
Interest rate (as a percent)								5.375%
Senior notes issued								$ 1,000,000,000
Percentage of principal amount 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, 2016
Long- term Debt
Redemption price			104.031%
5.375% senior notes due 2021 | On or after November 1, 2019
Long- term Debt
Redemption price			100.00%
5.375% senior notes due 2021 | On or before November 1, 2016
Long- term Debt
Redemption price			100.00%
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent)			105.375%
5.375% senior notes due 2021 | Maximum | On or before November 1, 2016
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%
Stand-alone revolving note
Long- term Debt
Maximum amount of the Credit Facility			$ 25,000,000
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			$ 1,100,000,000	$ 1,100,000,000
Interest rate (as a percent)							5.125%
Senior notes issued	$ 500,000,000						$ 600,000,000
Issue price as percentage of par value	100.50%
Percentage of principal amount 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, 2017
Long- term Debt
Redemption price			103.844%
5.125% senior notes due 2022 | On or before June 1, 2017
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)			105.125%
5.125% senior notes due 2022 | Prior to June 1, 2017
Long- term Debt
Redemption price			100.00%
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			$ 750,000,000
Interest rate (as a percent)						5.625%
Senior notes issued						$ 750,000,000
Percentage of principal amount at which notes may be required to be repurchased in event of change of control			101.00%
5.625% senior notes due 2023 | Prior to June 1, 2016
Long- term Debt
Redemption price of the debt instrument in the event of change of control (as a percent)			110.00%
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%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligations
Asset retirement obligations - beginning of period	$ 16,614	$ 11,859
Obligations incurred for wells drilled	9,213	3,484
Revisions to prior estimates	3,130
Accretion expense	1,655	1,271	$ 1,065
Asset retirement obligations - end of period	$ 30,612	$ 16,614	$ 11,859

Equity-Based Compensation (Deta

Equity-Based Compensation (Details) - USD ($)	12 Months Ended			27 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Stock-based compensation expense
Equity based compensation expense recognized	$ 97,877,000	$ 112,252,000	$ 365,280,000
Number of stock-based compensation awards authorized	16,906,500			16,906,500
Number of shares available for future grant under the Plan	9,377,755			9,377,755
Midstream Plan
Stock-based compensation expense
Number of stock-based compensation awards authorized	10,000,000			10,000,000
Number of shares available for future grant under the Plan	7,947,771			7,947,771
Profits interests awards
Stock-based compensation expense
Equity based compensation expense recognized	$ 37,620,000	83,615,000	364,957,000	$ 486,000,000
Additional equity compensation to be recognized over the remaining period	0			0
Restricted stock awards
Stock-based compensation expense
Equity based compensation expense recognized	40,663,000	25,624,000	219,000
Additional equity compensation to be recognized over the remaining period	177,600,000			177,600,000
Stock options
Stock-based compensation expense
Equity based compensation expense recognized	2,155,000	501,000	$ 104,000
Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	8,300,000			8,300,000
Antero Midstream Partners Phantom and Restricted Unit Awards
Stock-based compensation expense
Equity based compensation expense recognized	17,126,000	2,360,000
Additional equity compensation to be recognized over the remaining period	46,100,000			$ 46,100,000
Common stock issued to directors in lieu of cash compensation
Stock-based compensation expense
Equity based compensation expense recognized	$ 313,000	$ 152,000

Equity-Based Compensation (De49

Equity-Based Compensation (Details 2) - Restricted stock awards $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Number of shares
Total granted and unvested at the beginning of the period (in shares) | shares	1,983,673
Granted (in shares) | shares	5,441,449
Vested (in shares) | shares	(377,630)
Forfeited (in shares) | shares	(518,033)
Total awarded and unvested at the end of the period (in shares) | shares	6,529,459
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 64.71
Granted (in dollars per share) | $ / shares	24.04
Vested (in dollars per share) | $ / shares	63.39
Forfeited (in dollars per share) | $ / shares	31.37
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 33.48
Aggregate intrinsic value
Total awarded and unvested at the beginning of the period | $	$ 80,497
Total awarded and unvested at the end of the period | $	142,342
Additional equity compensation to be recognized over the remaining period | $	$ 177,600
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 8 months 12 days

Equity-Based Compensation (De50

Equity-Based Compensation (Details 3) - Stock options - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Stock-based compensation
Contractual life	10 years
Stock options
Outstanding at the beginning of the period (in shares)	81,021
Options granted (in shares)	665,366
Options forfeited (in shares)	(25,500)
Outstanding at the end of the period (in shares)	720,887	81,021
Vested or expected to vest (in shares)	720,887
Exercisable (in shares)	51,021
Weighted average exercise price
Outstanding at the beginning of the period (in dollars per share)	$ 53.92
Options granted (in dollars per share)	50
Options forfeited (in dollars per share)	50
Outstanding at the end of the period (in dollars per share)	50.44	$ 53.92
Vested or expected to vest (in dollars per share)	50.44
Exercisable (in dollars per share)	$ 53.79
Weighted average remaining contractual life
Outstanding	9 years 1 month 21 days	8 years 11 months 1 day
Vested or expected to vest	9 years 1 month 21 days
Exercisable	8 years
Weighted-average assumptions used to calculate fair value of stock options granted
Volatility (as a percent)	40.00%	40.00%	35.00%
Risk-free interest rate (as a percent)	1.66%	1.75%	1.48%
Expected life	6 years 3 months	5 years 6 months	6 years 2 months 1 day
Weighted average fair value of options granted (in dollars per share)	$ 14.74	$ 20.55	$ 20.20
Additional disclosures
Unrecognized stock-based compensation expense	$ 8.3
Weighted average period for recognizing unrecognized stock-based compensation expense	3 years 2 months 12 days
Minimum
Stock-based compensation
Vesting period	1 year
Maximum
Stock-based compensation
Vesting period	4 years

Equity-Based Compensation (De51

Equity-Based Compensation (Details 4) - Antero Midstream Partners Phantom and Restricted Unit Awards $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
Number of units
Total granted and unvested at the beginning of the period (in shares) | shares	2,381,440
Granted (in shares) | shares	12,057
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	(595,595)
Forfeited (in shares) | shares	(130,070)
Total awarded and unvested at the end of the period (in shares) | shares	1,667,832
Weighted average grant date fair value
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares	$ 29
Granted (in dollars per share) | $ / shares	24.88
Vested (in dollars per share) | $ / shares	29
Forfeited (in dollars per share) | $ / shares	29
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares	$ 28.97
Aggregate intrinsic value
Outstanding at the beginning of the period | $	$ 65,490
Outstanding at the end of the period | $	38,060
Additional equity compensation to be recognized over the remaining period | $	$ 46,100
Weighted average period for recognizing unrecognized stock-based compensation expense	2 years 10 months 24 days

Financial Instruments (Details)

Financial Instruments (Details) - USD ($) $ in Billions	Dec. 31, 2015	Dec. 31, 2014
Recurring | Level 2 market data
Financial Instruments
Fair value of senior notes	$ 2.6	$ 2.5

Derivative Instruments (Details

Derivative Instruments (Details)	Dec. 31, 2015bbl / dMMBTU / d$ / gal$ / MMBTU
TCOminusNYMEX | Year ending December 31, 2016 | Basis Differential Positions
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	290,000
Weighted average index price | $ / MMBTU	(0.42)
TCOminusNYMEX | Year ending December 31, 2017 | Basis Differential Positions
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	125,000
Weighted average index price | $ / MMBTU	(0.49)
Natural gas | NYMEXminusTCO | Year ending December 31, 2016 | Basis Differential Positions
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	170,000
Weighted average index price | $ / MMBTU	0.26
Natural gas | NYMEXminusTCO | Year ending December 31, 2017 | Basis Differential Positions
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	125,000
Weighted average index price | $ / MMBTU	0.30
Swaps | Natural gas | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,612,500
Swaps | Natural gas | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,612,500
Swaps | Natural gas | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,612,500
Swaps | Natural gas | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,612,500
Swaps | Natural gas | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,860,000
Swaps | Natural gas | Year ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	2,002,500
Swaps | Natural gas | TCO | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	60,000
Weighted average index price | $ / MMBTU	5.07
Swaps | Natural gas | TCO | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	60,000
Weighted average index price | $ / MMBTU	4.77
Swaps | Natural gas | TCO | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	60,000
Weighted average index price | $ / MMBTU	4.81
Swaps | Natural gas | TCO | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	60,000
Weighted average index price | $ / MMBTU	5.01
Swaps | Natural gas | Dominion South | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	272,500
Weighted average index price | $ / MMBTU	5.54
Swaps | Natural gas | Dominion South | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	272,500
Weighted average index price | $ / MMBTU	5.17
Swaps | Natural gas | Dominion South | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	272,500
Weighted average index price | $ / MMBTU	5.24
Swaps | Natural gas | Dominion South | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	272,500
Weighted average index price | $ / MMBTU	5.47
Swaps | Natural gas | NYMEX | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,110,000
Weighted average index price | $ / MMBTU	3.58
Swaps | Natural gas | NYMEX | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,110,000
Weighted average index price | $ / MMBTU	3.38
Swaps | Natural gas | NYMEX | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,110,000
Weighted average index price | $ / MMBTU	3.44
Swaps | Natural gas | NYMEX | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,110,000
Weighted average index price | $ / MMBTU	3.57
Swaps | Natural gas | NYMEX | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,370,000
Weighted average index price | $ / MMBTU	3.39
Swaps | Natural gas | NYMEX | Year ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	2,002,500
Weighted average index price | $ / MMBTU	3.91
Swaps | Natural gas | NYMEX | Year ending December 31, 2019
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,960,000
Weighted average index price | $ / MMBTU	3.87
Swaps | Natural gas | NYMEX | Year ending December 31, 2020
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	1,287,500
Weighted average index price | $ / MMBTU	3.72
Swaps | Natural gas | NYMEX | Year Ending December 31, 2021
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	480,000
Weighted average index price | $ / MMBTU	3.48
Swaps | Natural gas | NYMEX | Year ending December 31, 2022
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	10,000
Weighted average index price | $ / MMBTU	3.30
Swaps | Natural gas | CGTLA | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	170,000
Weighted average index price | $ / MMBTU	4.21
Swaps | Natural gas | CGTLA | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	170,000
Weighted average index price | $ / MMBTU	3.94
Swaps | Natural gas | CGTLA | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	170,000
Weighted average index price | $ / MMBTU	4.03
Swaps | Natural gas | CGTLA | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	170,000
Weighted average index price | $ / MMBTU	4.20
Swaps | Natural gas | CGTLA | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	420,000
Weighted average index price | $ / MMBTU	4.27
Swaps | Natural gas | CCG | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day)	70,000
Weighted average index price | $ / MMBTU	4.57
Swaps | Propane | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Swaps | Propane | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Swaps | Propane | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Swaps | Propane | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Swaps | Propane | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	35,500
Swaps | Propane | Year ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	2,000
Swaps | Propane | Mont Belvieu-TET | Three months ending March 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Weighted average index price | $ / gal	0.58
Swaps | Propane | Mont Belvieu-TET | Three months ending June 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Weighted average index price | $ / gal	0.57
Swaps | Propane | Mont Belvieu-TET | Three months ending September 30, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Weighted average index price | $ / gal	0.58
Swaps | Propane | Mont Belvieu-TET | Three months ending December 31, 2016
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	30,000
Weighted average index price | $ / gal	0.61
Swaps | Propane | Mont Belvieu-TET | Year ending December 31, 2017
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	35,500
Weighted average index price | $ / gal	0.43
Swaps | Propane | Mont Belvieu-TET | Year ending December 31, 2018
Derivative Instruments
Notional amount (MMBtu/Bbls per day) | bbl / d	2,000
Weighted average index price | $ / gal	0.65

Derivative Instruments (Detai54

Derivative Instruments (Details 2) $ in Thousands	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)
Fair value of derivative instruments
Current portion of fair value of derivative assets	$ 1,009,030	$ 692,554
Noncurrent portion of fair value of derivative assets	2,108,450	899,997
Total asset derivatives	3,117,480	1,592,551
Net derivatives	$ 3,117,480	$ 1,592,551
Derivatives designated as hedges for accounting purposes
Fair value of derivative instruments
Number of derivative instruments held | item	0

Derivative Instruments (Detai55

Derivative Instruments (Details 3) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Commodity derivative assets
Gross amounts on balance sheet	$ 3,163,639	$ 1,621,665
Gross amounts offset on balance sheet	(46,159)	(29,114)
Total asset derivatives	$ 3,117,480	$ 1,592,551

Derivative Instruments (Detai56

Derivative Instruments (Details 4) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains	$ 2,381,501	$ 868,201	$ 491,689
Revenue
Summary of realized and unrealized gains (losses) on derivative instruments
Commodity derivative fair value gains	$ 2,381,501	$ 868,201	$ 491,689

Contract Termination and Rig 57

Contract Termination and Rig Stacking (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Contract Termination and Rig Stacking Line Items
Contract termination and rig stacking	$ 38,531

Income Taxes (Detail)

Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income tax expense from continuing operations
Current income tax expense (benefit)			$ (4,000)
Deferred income tax expense (benefit)	$ 575,890	$ 445,672	190,210
Total income tax expense from continuing operations	$ 575,890	$ 445,672	$ 186,210
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	$ 544,560	$ 391,754	$ 56,708
State income tax expense , net of federal benefit	26,983	25,545	21,429
Nondeductible stock compensation	16,441	29,141	127,736
Noncontrolling interest in Antero Midstream Partners LP	(13,521)	(787)
Change in valuation allowance	570	(120)	(20,919)
Other	857	139	1,256
Total income tax expense from continuing operations	575,890	445,672	186,210
Income tax expense (benefit) allocated to continuing and discontinued operations
Total income tax expense from continuing operations	575,890	445,672	186,210
Discontinued operations and sale of discontinued operations		1,354	3,249
Total income tax expense (benefit)	575,890	447,026	$ 189,459
Deferred tax assets:
Net operating loss carryforwards	521,617	431,681
Minimum tax credit carryforward	11,000	11,000
Equity based compensation	16,130	10,032
Other	18,633	12,785
Total deferred tax assets	567,380	465,498
Valuation allowance	(27,209)	(26,639)
Net deferred tax assets	540,171	438,859
Deferred tax liabilities:
Unrealized gains on derivative instruments	1,167,983	601,859
Oil and gas properties	708,664	600,050
Investment in Antero Midstream Partners LP	34,210	31,746
Total deferred tax liabilities	1,910,857	1,233,655
Net deferred tax liabilities	$ (1,370,686)	$ (794,796)

Income Taxes (Details 2)

Income Taxes (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2013
Unrecognized tax benefits
Balance at beginning of year	$ 11,000,000	$ 15,000,000
Revised estimate of unrecognized tax position		(4,000,000)
Balance at end of year	11,000,000	$ 11,000,000
Unrecognized tax benefits impacting effective tax rate	11,000,000
Impact to the effective tax rate	0
Interest or penalties that have been accrued on unrecognized tax benefits	1,600,000
U.S Federal
Income Taxes
Net operating loss carryforward	1,400,000,000
State
Income Taxes
Net operating loss carryforward	$ 1,200,000,000

Commitments (Detail)

Commitments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Future minimum payments
2,016	$ 1,026
2,017	1,191
2,018	1,170
2,019	1,268
2,020	1,285
Thereafter	12,036
Total	17,976
Firm transportation
Future minimum payments
2,016	522
2,017	729
2,018	900
2,019	1,060
2,020	1,079
Thereafter	11,004
Total	15,294
Processing, gathering and compression
Future minimum payments
2,016	320
2,017	344
2,018	242
2,019	186
2,020	186
Thereafter	861
Total	2,139
Drilling rigs and frac services
Future minimum payments
2,016	171
2,017	104
2,018	4
Total	279
Office and equipment
Future minimum payments
2,016	13
2,017	14
2,018	24
2,019	22
2,020	20
Thereafter	171
Total	264
Commitments
Rental expense under operating leases	$ 9	$ 10.2	$ 1.8

Contingencies (Details)

Contingencies (Details) $ in Millions	Dec. 31, 2015USD ($)lawsuit	Feb. 04, 2015lawsuit
Contingencies
Number of lawsuits | lawsuit	1	2
Additional accounts receivable | $	$ 39

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Sales and revenues:
Sales and revenues	$ 905,122	$ 1,443,335	$ 376,714	$ 1,229,687	$ 1,481,823	$ 762,490	$ 311,338	$ 164,981	$ 3,954,858	$ 2,720,632	$ 1,313,134
Operating expenses:
Lease operating									36,011	29,341	9,439
Gathering, compression, processing, and transportation									659,361	461,413	218,428
Depletion, depreciation, and amortization									709,763	477,896	233,876
General and administrative expense									233,697	216,533	425,438
Total operating expenses	591,896	502,220	540,463	529,993	454,106	381,091	316,641	269,060	2,164,572	1,420,898	971,927
Operating income (loss)	313,226	$ 941,115	$ (163,749)	$ 699,694	1,027,717	$ 381,399	$ (5,303)	$ (104,079)	1,790,286	1,299,734	341,207
Segment assets	14,155,224				11,573,495				14,155,224	11,573,495
Exploration and production
Sales and revenues:
Sales and revenues									3,761,424	2,645,148	1,313,134
Gathering and compression
Sales and revenues:
Sales and revenues									230,592	95,746	22,363
Water handling and treatment
Sales and revenues:
Sales and revenues									156,732	171,925	35,871
Marketing
Sales and revenues:
Sales and revenues									176,229	53,604
Operating segments
Sales and revenues:
Sales and revenues									3,954,858	2,720,632	1,313,134
Operating expenses:
Lease operating									36,011	29,341	9,439
Gathering, compression, processing, and transportation									659,361	461,413	218,428
Depletion, depreciation, and amortization									709,763	477,896	233,876
General and administrative expense									233,697	216,533	425,438
Other operating expenses									525,740	235,715	84,746
Total operating expenses									2,164,572	1,420,898	971,927
Operating income (loss)									1,790,286	1,299,734	341,207
Segment assets	14,155,224				11,573,495				14,155,224	11,573,495	6,613,581
Capital expenditures for segment assets									2,347,909	4,086,568	2,671,573
Operating segments | Exploration and production
Sales and revenues:
Sales and revenues									3,756,629	2,644,953	1,313,134
Operating expenses:
Lease operating									35,552	28,041	9,439
Gathering, compression, processing, and transportation									852,573	536,879	238,712
Depletion, depreciation, and amortization									622,379	424,684	219,757
General and administrative expense									183,675	186,335	391,373
Other operating expenses									222,990	128,419	82,787
Total operating expenses									1,917,169	1,304,358	942,068
Operating income (loss)									1,844,255	1,340,790	371,066
Segment assets	12,466,249				9,920,331				12,466,249	9,920,331	5,859,933
Capital expenditures for segment assets									1,954,256	3,455,079	2,110,358
Operating segments | Gathering and compression
Sales and revenues:
Sales and revenues									12,353	6,810
Operating expenses:
Gathering, compression, processing, and transportation									25,305	13,497	2,079
Depletion, depreciation, and amortization									61,552	36,972	11,346
General and administrative expense									40,448	22,035	23,124
Other operating expenses									3,811	1,973
Total operating expenses									131,116	74,477	36,549
Operating income (loss)									99,476	21,269	(14,186)
Segment assets	1,470,691				1,411,470				1,470,691	1,411,470	561,855
Capital expenditures for segment assets									360,287	558,037	389,453
Operating segments | Water handling and treatment
Sales and revenues:
Sales and revenues									9,647	15,265
Operating expenses:
Lease operating									49,859	34,737	3,843
Depletion, depreciation, and amortization									25,832	16,240	2,773
General and administrative expense									10,758	8,331	10,941
Other operating expenses									3,210	1,888	1,959
Total operating expenses									89,659	61,196	19,516
Operating income (loss)									67,073	110,729	16,355
Segment assets	525,004				422,885				525,004	422,885	230,247
Capital expenditures for segment assets									131,051	196,675	203,790
Operating segments | Marketing
Sales and revenues:
Sales and revenues									176,229	53,604
Operating expenses:
Other operating expenses									299,062	103,435
Total operating expenses									299,062	103,435
Operating income (loss)									(122,833)	(49,831)
Segment assets	16,123				10,456				16,123	10,456
Elimination of intersegment transaction
Sales and revenues:
Sales and revenues									(370,119)	(245,791)	(58,234)
Operating expenses:
Lease operating									(49,400)	(33,437)	(3,843)
Gathering, compression, processing, and transportation									(218,517)	(88,963)	(22,363)
General and administrative expense									(1,184)	(168)
Other operating expenses									(3,333)
Total operating expenses									(272,434)	(122,568)	(26,206)
Operating income (loss)									(97,685)	(123,223)	(32,028)
Segment assets	$ (322,843)				$ (191,647)				(322,843)	(191,647)	(38,454)
Capital expenditures for segment assets									(97,685)	(123,223)	(32,028)
Elimination of intersegment transaction | Exploration and production
Sales and revenues:
Sales and revenues									4,795	195
Elimination of intersegment transaction | Gathering and compression
Sales and revenues:
Sales and revenues									218,239	88,936	22,363
Elimination of intersegment transaction | Water handling and treatment
Sales and revenues:
Sales and revenues									$ 147,085	$ 156,660	$ 35,871

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 23,473	$ 245,979	$ 17,487	$ 18,989
Accounts receivable, net	79,404	116,203
Accrued revenue	128,242	191,558
Derivative instruments	1,009,030	692,554
Other current assets	8,087	5,866
Total current assets	1,248,236	1,252,160
Unproved properties	1,996,081	2,060,936
Proved properties	8,211,106	6,515,221
Water handling systems	565,616	421,012
Gathering systems and facilities	1,502,396	1,197,239
Other property and equipment	46,415	37,687
Property and equipment, gross	12,321,614	10,232,095
Less accumulated depletion, depreciation, and amortization	(1,589,372)	(879,643)
Property and equipment, net	10,732,242	9,352,452
Derivative instruments	2,108,450	899,997
Other assets, net	66,296	68,886
Total assets	14,155,224	11,573,495
Liabilities and Stockholders' Equity
Accounts payable	364,160	531,564
Accrued liabilities	194,076	168,614
Revenue distributions payable	129,949	182,352
Other current liabilities	19,085	12,202
Total current liabilities	707,270	894,732
Long-term debt Noncurrent	4,708,513	4,362,550
Deferred income tax liability	1,370,686	794,796
Other liabilities	82,077	47,587
Total liabilities	6,868,546	6,099,665
Common stock	2,770	2,621
Additional paid-in capital	4,122,811	3,513,725
Accumulated earnings	1,808,811	867,447
Total stockholders' equity	5,934,392	4,383,793
Noncontrolling interest in consolidated subsidiary	1,352,286	1,090,037
Total equity	7,286,678	5,473,830	3,598,660	$ 1,673,737
Total liabilities and equity	14,155,224	11,573,495
Eliminations
Current assets:
Intercompany receivables	(67,850)	(19,026)
Other current assets		(1)
Total current assets	(67,850)	(19,027)
Proved properties	(32,795)
Property and equipment, gross	(32,795)
Property and equipment, net	(32,795)
Investment in subsidiaries	302,336	(137,423)
Contingent acquisition consideration asset	(178,049)
Total assets	23,642	(156,450)
Liabilities and Stockholders' Equity
Intercompany payable	(67,850)	(19,026)
Other current liabilities		(1)
Total current liabilities	(67,850)	(19,027)
Contingent acquisition consideration liability	(178,049)
Total liabilities	(245,899)	(19,027)
Parent net investment		114,999
Partners' capital	(1,082,745)	(1,342,459)
Total stockholders' equity	(1,082,745)	(1,227,460)
Noncontrolling interest in consolidated subsidiary	1,352,286	1,090,037
Total equity	269,541	(137,423)
Total liabilities and equity	23,642	(156,450)
Antero Resources Corp | Reportable legal entity
Current assets:
Cash and cash equivalents	16,590	15,787	$ 17,487
Accounts receivable, net	76,697	116,203
Intercompany receivables	2,138	1,380
Accrued revenue	128,242	191,558
Derivative instruments	1,009,030	692,554
Other current assets	8,087	5,348
Total current assets	1,240,784	1,022,830
Unproved properties	1,996,081	2,060,936
Proved properties	8,243,901	6,515,221
Water handling systems		421,012
Gathering systems and facilities	16,561	16,532
Other property and equipment	46,415	37,687
Property and equipment, gross	10,302,958	9,051,388
Less accumulated depletion, depreciation, and amortization	(1,431,747)	(828,533)
Property and equipment, net	8,871,211	8,222,855
Derivative instruments	2,108,450	899,997
Investment in subsidiaries	(302,336)	137,423
Contingent acquisition consideration asset	178,049
Other assets, net	55,392	51,718
Total assets	12,151,550	10,334,823
Liabilities and Stockholders' Equity
Accounts payable	303,197	485,628
Intercompany payable	65,712	17,646
Accrued liabilities	158,713	163,268
Revenue distributions payable	129,949	182,352
Other current liabilities	18,935	12,203
Total current liabilities	676,506	861,097
Long-term debt Noncurrent	4,088,513	4,247,550
Deferred income tax liability	1,370,686	794,796
Other liabilities	81,453	47,587
Total liabilities	6,217,158	5,951,030
Common stock	2,770	2,621
Additional paid-in capital	4,122,811	3,513,725
Accumulated earnings	1,808,811	867,447
Total stockholders' equity	5,934,392	4,383,793
Total equity	5,934,392	4,383,793
Total liabilities and equity	12,151,550	10,334,823
Guarantor Subsidiaries | Reportable legal entity
Current assets:
Other current assets		1
Total current assets		1
Total assets		1
Liabilities and Stockholders' Equity
Long-term debt Noncurrent		115,000
Total liabilities		115,000
Parent net investment		(114,999)
Total stockholders' equity		(114,999)
Total equity		(114,999)
Total liabilities and equity		1
Non-Guarantor Subsidiaries | Reportable legal entity
Current assets:
Cash and cash equivalents	6,883	230,192
Accounts receivable, net	2,707
Intercompany receivables	65,712	17,646
Other current assets		518
Total current assets	75,302	248,356
Water handling systems	565,616
Gathering systems and facilities	1,485,835	1,180,707
Property and equipment, gross	2,051,451	1,180,707
Less accumulated depletion, depreciation, and amortization	(157,625)	(51,110)
Property and equipment, net	1,893,826	1,129,597
Other assets, net	10,904	17,168
Total assets	1,980,032	1,395,121
Liabilities and Stockholders' Equity
Accounts payable	60,963	45,936
Intercompany payable	2,138	1,380
Accrued liabilities	35,363	5,346
Other current liabilities	150
Total current liabilities	98,614	52,662
Long-term debt Noncurrent	620,000
Contingent acquisition consideration liability	178,049
Other liabilities	624
Total liabilities	897,287	52,662
Partners' capital	1,082,745	1,342,459
Total stockholders' equity	1,082,745	1,342,459
Total equity	1,082,745	1,342,459
Total liabilities and equity	$ 1,980,032	$ 1,395,121

Subsidiary Guarantor (Details 2

Subsidiary Guarantor (Details 2) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue:
Natural gas sales									$ 1,039,892	$ 1,301,349	$ 689,198
Natural gas liquids sales									264,483	328,323	111,663
Oil sales									70,753	107,080	20,584
Gathering, compression and water distribution									22,000	22,075
Marketing									176,229	53,604
Commodity derivative fair value gains									2,381,501	868,201	491,689
Gain on sale of gathering system										40,000
Total revenue	$ 905,122	$ 1,443,335	$ 376,714	$ 1,229,687	$ 1,481,823	$ 762,490	$ 311,338	$ 164,981	3,954,858	2,720,632	1,313,134
Operating expenses:
Lease operating									36,011	29,341	9,439
Gathering, compression, processing, and transportation									659,361	461,413	218,428
Production and ad valorem taxes									78,325	87,918	50,481
Marketing									299,062	103,435
Exploration									3,846	27,893	22,272
Impairment of unproved properties									104,321	15,198	10,928
Depletion, depreciation, and amortization									709,763	477,896	233,876
Accretion of asset retirement obligations									1,655	1,271	1,065
General and administrative									233,697	216,533	425,438
Contract termination and rig stacking									38,531
Total operating expenses	591,896	502,220	540,463	529,993	454,106	381,091	316,641	269,060	2,164,572	1,420,898	971,927
Operating income	313,226	941,115	(163,749)	699,694	1,027,717	381,399	(5,303)	(104,079)	1,790,286	1,299,734	341,207
Interest									(234,400)	(160,051)	(136,617)
Loss on early extinguishment of debt										(20,386)	(42,567)
Total other expenses									(234,400)	(180,437)	(179,184)
Income from continuing operations before income taxes and discontinued operations									1,555,886	1,119,297	162,023
Provision for income tax expense									(575,890)	(445,672)	(186,210)
Income (loss) from continuing operations	175,574	544,734	(139,483)	399,171	608,970	203,909	(44,495)	(94,759)	979,996	673,625	(24,187)
Discontinued operations:
Income from sale of discontinued operations, net of income tax expense							2,210			2,210	5,257
Net income (loss) and comprehensive income (loss) including noncontrolling interest	175,574	544,734	(139,483)	399,171	608,970	203,909	(42,285)	(94,759)	979,996	675,835	(18,930)
Net income and comprehensive income attributable to noncontrolling interest	17,110	10,892	5,890	4,740	2,248				38,632	2,248
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 158,464	$ 533,842	$ (145,373)	$ 394,431	$ 606,722	$ 203,909	$ (42,285)	$ (94,759)	941,364	673,587	$ (18,930)
Reportable legal entity | Antero Resources Corp
Revenue:
Natural gas sales									1,039,892	1,301,349
Natural gas liquids sales									264,483	328,323
Oil sales									70,753	107,080
Gathering, compression and water distribution									6,651	20,284
Marketing									176,229	53,604
Commodity derivative fair value gains									2,381,501	868,201
Other income									4,594	143
Gain on sale of gathering system										40,000
Total revenue									3,944,103	2,718,984
Operating expenses:
Lease operating									36,132	29,341
Gathering, compression, processing, and transportation									852,573	480,367
Production and ad valorem taxes									77,074	85,945
Marketing									299,062	103,435
Exploration									3,846	27,893
Impairment of unproved properties									104,321	15,198
Depletion, depreciation, and amortization									641,860	471,372
Accretion of asset retirement obligations									1,655	1,271
General and administrative									190,712	212,316
Contract termination and rig stacking									38,531
Total operating expenses									2,245,766	1,427,138
Operating income									1,698,337	1,291,846
Interest									(228,568)	(159,585)
Loss on early extinguishment of debt										(20,386)
Equity in net income of subsidiaries									47,485	5,174
Total other expenses									(181,083)	(174,797)
Income from continuing operations before income taxes and discontinued operations									1,517,254	1,117,049
Provision for income tax expense									(575,890)	(445,672)
Income (loss) from continuing operations										671,377
Discontinued operations:
Income from sale of discontinued operations, net of income tax expense										2,210
Net income (loss) and comprehensive income (loss) including noncontrolling interest									941,364	673,587
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									941,364	673,587
Reportable legal entity | Non-Guarantor Subsidiaries
Revenue:
Gathering, compression and water distribution									299,787	25,178
Total revenue									299,787	25,178
Operating expenses:
Lease operating									33,283
Gathering, compression, processing, and transportation									25,305	4,460
Production and ad valorem taxes									1,251	1,973
Depletion, depreciation, and amortization									67,903	6,524
General and administrative									43,968	4,333
Accretion of contingent acquisition consideration									3,333
Total operating expenses									175,043	17,290
Operating income									124,744	7,888
Interest									(5,832)	(466)
Total other expenses									(5,832)	(466)
Income from continuing operations before income taxes and discontinued operations									118,912	7,422
Income (loss) from continuing operations										7,422
Discontinued operations:
Net income (loss) and comprehensive income (loss) including noncontrolling interest									118,912	7,422
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									118,912	7,422
Eliminations
Revenue:
Gathering, compression and water distribution									(284,438)	(23,387)
Other income									(4,594)	(143)
Total revenue									(289,032)	(23,530)
Operating expenses:
Lease operating									(33,404)
Gathering, compression, processing, and transportation									(218,517)	(23,414)
General and administrative									(983)	(116)
Accretion of contingent acquisition consideration									(3,333)
Total operating expenses									(256,237)	(23,530)
Operating income									(32,795)
Equity in net income of subsidiaries									(47,485)	(5,174)
Total other expenses									(47,485)	(5,174)
Income from continuing operations before income taxes and discontinued operations									(80,280)	(5,174)
Income (loss) from continuing operations										(5,174)
Discontinued operations:
Net income (loss) and comprehensive income (loss) including noncontrolling interest									(80,280)	(5,174)
Net income and comprehensive income attributable to noncontrolling interest									38,632	2,248
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation									$ (118,912)	$ (7,422)

Subsidiary Guarantor (Details 3

Subsidiary Guarantor (Details 3) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed consolidated statement of cash flows
Net cash provided by operating activities	$ 1,006,381	$ 998,121	$ 534,707
Cash flows used in investing activities:
Additions to proved properties		(64,066)	(15,300)
Additions to unproved properties	(198,694)	(777,422)	(440,825)
Drilling and completion costs	(1,651,282)	(2,477,150)	(1,615,965)
Additions to water handling and treatment systems	(131,051)	(196,675)	(203,790)
Additions to gathering systems and facilities	(360,287)	(558,037)	(389,453)
Additions to other property and equipment	(6,595)	(13,218)	(6,240)
Change in other assets	9,750	(3,082)	(2,019)
Proceeds from asset sales	40,000
Net cash used in investing activities	(2,298,159)	(4,089,650)	(2,673,592)
Cash flows from financing activities:
Issuance of common stock	537,832		1,578,573
Issuance of common units in Antero Midstream Partners LP	240,703	1,087,224
Issuance of senior notes	750,000	1,102,500	1,231,750
Repayment of senior notes		(260,000)	(690,000)
Borrowings (repayments) on bank credit facility, net	(403,000)	1,442,000	71,000
Make-whole premium on debt extinguished		(17,383)	(33,041)
Payments of deferred financing costs	(17,293)	(31,543)	(20,899)
Distributions to noncontrolling interest in consolidated subsidiary	(34,129)
Other	(4,841)	(2,777)
Net cash provided by financing activities	1,069,272	3,320,021	2,137,383
Net increase (decrease) in cash and cash equivalents	(222,506)	228,492	(1,502)
Cash and cash equivalents, beginning of period	245,979	17,487	18,989
Cash and cash equivalents, end of period	23,473	245,979	17,487
Reportable legal entity | Antero Resources Corp
Condensed consolidated statement of cash flows
Net cash provided by operating activities	816,128	992,788
Cash flows used in investing activities:
Additions to proved properties		(64,066)
Additions to unproved properties	(198,694)	(777,422)
Drilling and completion costs	(1,651,282)	(2,477,150)
Additions to water handling and treatment systems	(80,064)	(196,675)
Additions to gathering systems and facilities	(40,285)	(543,196)
Additions to other property and equipment	(6,595)	(13,218)
Change in other assets	2,570	(2,928)
Net distributions (to) from guarantor subsidiary	(115,000)	115,000
Distributions from non-guarantor subsidiary	73,119	332,500
Proceeds from contribution of assets to non-guarantor susidiary	801,116
Proceeds from asset sales	40,000
Net cash used in investing activities	(1,175,115)	(3,627,155)
Cash flows from financing activities:
Issuance of common stock	537,832
Issuance of senior notes	750,000	1,102,500
Repayment of senior notes		(260,000)
Borrowings (repayments) on bank credit facility, net	(908,000)	1,837,000
Make-whole premium on debt extinguished		(17,383)
Payments of deferred financing costs	(15,234)	(26,673)
Other	(4,808)	(2,777)
Net cash provided by financing activities	359,790	2,632,667
Net increase (decrease) in cash and cash equivalents	803	(1,700)
Cash and cash equivalents, beginning of period	15,787	17,487
Cash and cash equivalents, end of period	16,590	15,787	$ 17,487
Reportable legal entity | Guarantor Subsidiaries
Cash flows from financing activities:
Borrowings (repayments) on bank credit facility, net	(115,000)	115,000
Distributions to noncontrolling interest in consolidated subsidiary	115,000	(115,000)
Reportable legal entity | Non-Guarantor Subsidiaries
Condensed consolidated statement of cash flows
Net cash provided by operating activities	190,253	5,333
Cash flows used in investing activities:
Additions to water handling and treatment systems	(50,987)
Additions to gathering systems and facilities	(320,002)	(14,841)
Change in other assets	7,180	(154)
Net cash used in investing activities	(363,809)	(14,995)
Cash flows from financing activities:
Issuance of common units in Antero Midstream Partners LP	240,703	1,087,224
Borrowings (repayments) on bank credit facility, net	620,000	(510,000)
Payments of deferred financing costs	(2,059)	(4,870)
Distributions to noncontrolling interest in consolidated subsidiary	(908,364)	(332,500)
Other	(33)
Net cash provided by financing activities	(49,753)	239,854
Net increase (decrease) in cash and cash equivalents	(223,309)	230,192
Cash and cash equivalents, beginning of period	230,192
Cash and cash equivalents, end of period	6,883	230,192
Eliminations
Cash flows used in investing activities:
Net distributions (to) from guarantor subsidiary	115,000	(115,000)
Distributions from non-guarantor subsidiary	(73,119)	(332,500)
Proceeds from contribution of assets to non-guarantor susidiary	(801,116)
Net cash used in investing activities	(759,235)	(447,500)
Cash flows from financing activities:
Distributions to noncontrolling interest in consolidated subsidiary	759,235	447,500
Net cash provided by financing activities	$ 759,235	$ 447,500

Quarterly Financial Informati66

Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)$ / shares	Sep. 30, 2015USD ($)$ / shares	Jun. 30, 2015USD ($)$ / shares	Mar. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)$ / shares	Sep. 30, 2014USD ($)$ / shares	Jun. 30, 2014USD ($)$ / shares	Mar. 31, 2014USD ($)$ / shares	Dec. 31, 2015USD ($)MMcfe$ / shares	Dec. 31, 2014USD ($)MMcfe$ / shares	Dec. 31, 2013USD ($)$ / shares
Selected Quarterly Financial Information [Abstract]
Total revenue	$ 905,122	$ 1,443,335	$ 376,714	$ 1,229,687	$ 1,481,823	$ 762,490	$ 311,338	$ 164,981	$ 3,954,858	$ 2,720,632	$ 1,313,134
Total operating expenses	591,896	502,220	540,463	529,993	454,106	381,091	316,641	269,060	2,164,572	1,420,898	971,927
Operating income (loss)	313,226	941,115	(163,749)	699,694	1,027,717	381,399	(5,303)	(104,079)	1,790,286	1,299,734	341,207
Income (loss) from continuing operations	175,574	544,734	(139,483)	399,171	608,970	203,909	(44,495)	(94,759)	979,996	673,625	(24,187)
Income from sale of discontinued operations, net of income tax expense							2,210			2,210	5,257
Net income (loss) including noncontrolling interest	175,574	544,734	(139,483)	399,171	608,970	203,909	(42,285)	(94,759)	979,996	675,835	(18,930)
Net Income (Loss) Attributable to Noncontrolling Interest	17,110	10,892	5,890	4,740	2,248				38,632	2,248
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$ 158,464	$ 533,842	$ (145,373)	$ 394,431	$ 606,722	$ 203,909	$ (42,285)	$ (94,759)	$ 941,364	$ 673,587	$ (18,930)
Earnings (loss) per common share - basic:
Continuing operations - basic | $ / shares					$ 2.31	$ 0.78	$ (0.17)	$ (0.36)	$ 3.43	$ 2.56	$ (0.09)
Discontinued operations - basic | $ / shares							0.01			0.01	0.02
Earnings (loss) per common share - basic | $ / shares	$ 0.57	$ 1.93	$ (0.52)	$ 1.49	2.31	0.78	(0.16)	(0.36)	3.43	2.57	(0.07)
Earnings (loss) per share - diluted:
Continuing operations - diluted | $ / shares					2.31	0.78	(0.17)	(0.36)	3.43	2.56	(0.09)
Discontinued operations - diluted | $ / shares							0.01			0.01	0.02
Earnings (loss) per common share - diluted | $ / shares	$ 0.57	$ 1.93	$ (0.52)	$ 1.49	$ 2.31	$ 0.78	$ (0.16)	$ (0.36)	$ 3.43	$ 2.57	$ (0.07)
Increase (decrease) in proved reserves resulting from price revisions | MMcfe									(202,000)	2

Supplemental Information on O67

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs Relating to Oil and Gas Producing Activities
Proved properties	$ 8,211,106	$ 6,515,221
Unproved properties	1,996,081	2,060,936
Total	10,207,187	8,576,157
Accumulated depletion and depreciation	(1,415,005)	(802,665)
Net capitalized costs	8,792,182	7,773,492
Costs Incurred in Certain Oil and Gas Activities
Proved property		64,066	$ 15,300
Unproved property	198,694	777,422	440,825
Development costs	1,039,301	1,536,193	780,583
Exploration costs	611,981	940,957	835,382
Total costs incurred	1,849,976	3,318,638	2,072,090
Results of Operations for Oil and Gas Producing Activities
Revenues	1,375,128	1,736,752	821,445
Operating expenses:
Production expenses	773,697	578,672	278,348
Exploration expenses	3,846	27,893	22,272
Depletion and depreciation	614,700	418,744	219,830
Impairment of unproved properties	104,321	15,198	10,928
Results of operations before income tax expense (benefit)	(121,436)	696,245	290,067
Income tax expense	45,497	(263,126)	(110,805)
Results of operations	$ (75,939)	$ 433,119	$ 179,262

Supplemental Information on O68

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Details 2) MMcfe in Thousands	12 Months Ended
	Dec. 31, 2015MMcfeBcfMMBbls	Dec. 31, 2014MMcfeBcfMMBbls	Dec. 31, 2013MMcfeBcfMMBbls
Proved developed and undeveloped reserves:
Balance at the beginning of the period | MMcfe	12,683	7,632	4,929
Revisions | MMcfe	(1,801)	(1,054)	(788)
Extensions, discoveries and other additions | MMcfe	2,878	6,444	3,682
Production | MMcfe	(545)	(368)	(191)
Purchase of reserves | MMcfe		29
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MMcfe	13,215	12,683	7,632
Oil and Gas Reserves
Proved developed reserves | MMcfe	5,838	3,803	2,022
Proved undeveloped reserves | MMcfe	7,377	8,880	5,610
Natural gas
Proved developed and undeveloped reserves:
Balance at the beginning of the period | Bcf	10,535	6,753	3,694
Revisions | Bcf	(2,816)	(1,025)	152
Extensions, discoveries and other additions | Bcf	2,253	5,095	3,084
Production | Bcf	(439)	(317)	(177)
Purchase of reserves | Bcf		29
Balance at the end of the period | Bcf	9,533	10,535	6,753
Oil and Gas Reserves
Proved developed reserves | Bcf	3,627	3,285	1,818
Proved undeveloped reserves | Bcf	5,906	7,250	4,936
NGLS
Proved developed and undeveloped reserves:
Balance at the beginning of the period	330	137	203
Revisions	176	(6)	(140)
Extensions, discoveries and other additions	97	206	76
Production	(16)	(7)	(2)
Balance at the end of the period	587	330	137
Oil and Gas Reserves
Proved developed reserves	360	80	33
Proved undeveloped reserves	227	250	105
Oil and condensate
Proved developed and undeveloped reserves:
Balance at the beginning of the period	28	10	3
Revisions	(8)
Extensions, discoveries and other additions	8	19	7
Production	(2)	(1)
Balance at the end of the period	26	28	10
Oil and Gas Reserves
Proved developed reserves	8	6	2
Proved undeveloped reserves	18	22	8

Supplemental Information on O69

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail 3) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MMcfebbl	Dec. 31, 2014USD ($)MMcfeitem	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Increase in proved reserves due to ethane recovery | MMcfe	1,091,000
Ethane recovery quantity assumption | bbl	11,500
Decrease in proved reserves due to reclassifications related to five-year rule | MMcfe	(2,332,000)	(1,417,000)
Increase (decrease) in proved reserves resulting from price revisions | MMcfe	(202,000)	2
Increase (decrease) in proved reserves due to performance revisions | MMcfe	(358,000)	361,000
Number of horizontal producing wells acquired | item		5
Number of dry gas locations | item		191
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	$ 35,179	$ 63,632	$ 30,113
Future production costs	(17,393)	(21,722)	(5,967)
Future development costs	(5,217)	(8,212)	(5,349)
Future net cash flows before income tax	12,569	33,698	18,797
Future income tax expense	(1,708)	(10,726)	(5,308)
Future net cash flows	10,861	22,972	13,489
10% annual discount for estimated timing of cash flows	(7,628)	(15,337)	(8,979)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$ 3,233	$ 7,635	$ 4,510	$ 1,601

Supplemental Information on O70

Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail 4) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)$ / MMcfe	Dec. 31, 2014USD ($)$ / MMcfe	Dec. 31, 2013USD ($)$ / MMcfe
Supplemental Information on Oil and Gas Producing Activities (Unaudited)
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe	2.66	5.02	3.95
Changes in Standardized Measure of Discounted Future Net Cash Flow
Sales and Transfers of Oil and Gas Produced, Net of Production Costs	$ (601)	$ (1,158)	$ (543)
Net changes in prices and production costs	(9,416)	(184)	1,061
Previously Estimated Development Costs Incurred During Period	769	564	384
Net changes in future development costs	671	(102)	(181)
Extensions, discoveries and other additions	861	5,759	3,441
Acquisitions		42	2
Revisions of previous quantity estimates	(1,167)	(828)	(270)
Accretion of discount	1,132	600	192
Net change in income taxes	3,284	(2,198)	(1,165)
Other changes	65	630	(12)
Net increase (decrease)	(4,402)	3,125	2,909
Beginning of period	7,635	4,510	1,601
End of period	$ 3,233	$ 7,635	$ 4,510