Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 23, 2017 | Jun. 30, 2016 | |
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, 2016 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 4.6 | ||
Entity Common Stock, Shares Outstanding | 315,006,448 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,016 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Current assets: | ||||
Cash and cash equivalents | $ 31,610 | $ 23,473 | $ 245,979 | $ 17,487 |
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016 | 29,682 | 79,404 | ||
Accrued revenue | 261,960 | 128,242 | ||
Derivative instruments | 73,022 | 1,009,030 | ||
Other current assets | 6,313 | 8,087 | ||
Total current assets | 402,587 | 1,248,236 | ||
Natural gas properties, at cost (successful efforts method): | ||||
Unproved properties | 2,331,173 | 1,996,081 | ||
Proved properties | 9,549,671 | 8,211,106 | ||
Water handling and treatment systems | 744,682 | 565,616 | ||
Gathering systems and facilities | 1,723,768 | 1,502,396 | ||
Other property and equipment | 41,231 | 46,415 | ||
Property and equipment, gross | 14,390,525 | 12,321,614 | ||
Less accumulated depletion, depreciation, and amortization | (2,363,778) | (1,589,372) | ||
Property and equipment, net | 12,026,747 | 10,732,242 | ||
Derivative instruments | 1,731,063 | 2,108,450 | ||
Other assets | 95,153 | 26,565 | ||
Total assets | 14,255,550 | 14,115,493 | ||
Current liabilities: | ||||
Accounts payable | 38,627 | 69,911 | ||
Accrued liabilities | 393,803 | 488,325 | ||
Revenue distributions payable | 163,989 | 129,949 | ||
Derivative instruments | 203,635 | |||
Other current liabilities | 17,334 | 19,085 | ||
Total current liabilities | 817,388 | 707,270 | ||
Long-term liabilities: | ||||
Long-term debt | 4,703,973 | 4,668,782 | ||
Deferred income tax liability | 950,217 | 1,370,686 | ||
Derivative instruments | 234 | |||
Other liabilities | 55,160 | 82,077 | ||
Total liabilities | 6,526,972 | 6,828,815 | ||
Equity: | ||||
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 277,036 shares and 314,877 shares, respectively | 3,149 | 2,770 | ||
Additional paid-in capital | 5,299,481 | 4,122,811 | ||
Accumulated earnings | 959,995 | 1,808,811 | ||
Total stockholders' equity | 6,262,625 | 5,934,392 | ||
Noncontrolling interest in consolidated subsidiary | 1,465,953 | 1,352,286 | ||
Total equity | 7,728,578 | 7,286,678 | $ 5,473,830 | $ 3,598,660 |
Total liabilities and equity | $ 14,255,550 | $ 14,115,493 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Condensed Consolidated Balance Sheets | ||
Allowance for doubtful accounts | $ 1,195 | $ 1,195 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, authorized shares | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued | 314,877,000 | 277,036,000 |
Common stock, shares outstanding | 314,877,000 | 277,036,000 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, authorized shares | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Consolidated Statements of Oper
Consolidated Statements of Operations and Comprehensive Income (Loss) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue: | |||||||||||
Natural gas sales | $ 1,260,750 | $ 1,039,892 | $ 1,301,349 | ||||||||
Natural gas liquids sales | 432,992 | 264,483 | 328,323 | ||||||||
Oil sales | 61,319 | 70,753 | 107,080 | ||||||||
Gathering, processing, and water handling and treatment | 12,961 | 22,000 | 22,075 | ||||||||
Marketing | 393,049 | 176,229 | 53,604 | ||||||||
Commodity derivative fair value gains (losses) | (514,181) | 2,381,501 | 868,201 | ||||||||
Gain on sale of assets | 97,635 | 40,000 | |||||||||
Total revenue and other | $ 156,216 | $ 1,116,503 | $ (249,198) | $ 721,004 | $ 905,122 | $ 1,443,335 | $ 376,714 | $ 1,229,687 | 1,744,525 | 3,954,858 | 2,720,632 |
Operating expenses: | |||||||||||
Lease operating | 50,090 | 36,011 | 29,341 | ||||||||
Gathering, compression, processing, and transportation | 882,838 | 659,361 | 461,413 | ||||||||
Production and ad valorem taxes | 66,588 | 78,325 | 87,918 | ||||||||
Marketing | 499,343 | 299,062 | 103,435 | ||||||||
Exploration | 6,862 | 3,846 | 27,893 | ||||||||
Impairment of unproved properties | 162,935 | 104,321 | 15,198 | ||||||||
Depletion, depreciation, and amortization | 809,873 | 709,763 | 477,896 | ||||||||
Accretion of asset retirement obligations | 2,473 | 1,655 | 1,271 | ||||||||
General and administrative (including equity-based compensation expense) | 239,324 | 233,697 | 216,533 | ||||||||
Contract termination and rig stacking | 38,500 | 38,531 | |||||||||
Total operating expenses | 788,225 | 649,171 | 640,675 | 642,255 | 591,896 | 502,220 | 540,463 | 529,993 | 2,720,326 | 2,164,572 | 1,420,898 |
Operating income (loss) | (632,009) | 467,332 | (889,873) | 78,749 | 313,226 | 941,115 | (163,749) | 699,694 | (975,801) | 1,790,286 | 1,299,734 |
Other income (expenses): | |||||||||||
Equity in earnings of unconsolidated affiliate | 485 | ||||||||||
Interest | (253,552) | (234,400) | (160,051) | ||||||||
Loss on early extinguishment of debt | (16,956) | (20,386) | |||||||||
Total other expenses | (270,023) | (234,400) | (180,437) | ||||||||
Income (loss) before income taxes | (1,245,824) | 1,555,886 | 1,119,297 | ||||||||
Provision for income tax (expense) benefit | 496,376 | (575,890) | (445,672) | ||||||||
Income (loss) from continuing operations | (749,448) | 979,996 | 673,625 | ||||||||
Income Loss From Discontinued Operations Net Of Tax [Abstract] | |||||||||||
Income from sale of discontinued operations, net of income tax expense | 2,210 | ||||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | (452,804) | 268,196 | (575,490) | 10,650 | 175,574 | 544,734 | (139,483) | 399,171 | (749,448) | 979,996 | 675,835 |
Net income and comprehensive income attributable to noncontrolling interest | 32,968 | 29,941 | 20,754 | 15,705 | 17,110 | 10,892 | 5,890 | 4,740 | 99,368 | 38,632 | 2,248 |
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ (485,772) | $ 238,255 | $ (596,244) | $ (5,055) | $ 158,464 | $ 533,842 | $ (145,373) | $ 394,431 | $ (848,816) | $ 941,364 | $ 673,587 |
Earnings (loss) per common share: | |||||||||||
Continuing operations (in dollars per share) | $ (2.88) | $ 3.43 | $ 2.56 | ||||||||
Discontinued operations (in dollars per share) | 0.01 | ||||||||||
Total (in dollars per share) | $ (1.55) | $ 0.78 | $ (2.12) | $ (0.02) | $ 0.57 | $ 1.93 | $ (0.52) | $ 1.49 | (2.88) | 3.43 | 2.57 |
Earnings (loss) per common share assuming dilution: | |||||||||||
Continuing operations (in dollars per share) | (2.88) | 3.43 | 2.56 | ||||||||
Discontinued operations (in dollars per share) | 0.01 | ||||||||||
Total (in dollars per share) | $ (1.55) | $ 0.77 | $ (2.12) | $ (0.02) | $ 0.57 | $ 1.93 | $ (0.52) | $ 1.49 | $ (2.88) | $ 3.43 | $ 2.57 |
Weighted average number of shares outstanding | |||||||||||
Basic (in shares) | 294,945 | 274,123 | 262,054 | ||||||||
Diluted (in shares) | 294,945 | 274,143 | 262,068 |
Consolidated Statements of Ope5
Consolidated Statements of Operations and Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) | |||
Equity-based compensation expense | $ 102,421 | $ 97,877 | $ 112,252 |
Deferred income tax expense - discontinued operations | $ 1,354 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) shares in Thousands, $ in Thousands | Common Stock | Additional paid-in capital | Accumulated (deficit) earnings | Noncontrolling Interests | Total |
Balances at Dec. 31, 2013 | $ 2,620 | $ 3,402,180 | $ 193,860 | $ 3,598,660 | |
Shares Issued, Beginning Balance at Dec. 31, 2013 | 262,050 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
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 by 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 |
Shares Issued, Ending Balance at Dec. 31, 2014 | 262,072 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs | $ 147 | 537,685 | 537,832 | ||
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs (in shares) | 14,700 | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | $ 2 | (4,627) | (4,625) | ||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares) | 264 | ||||
Equity-based compensation | 93,300 | 4,577 | 97,877 | ||
Issuance of common units by subsidiary - Antero Midstream Partners LP | 240,703 | 240,703 | |||
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings | (17,272) | 12,466 | (4,806) | ||
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 |
Shares Issued, Ending Balance at Dec. 31, 2015 | 277,036 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs | $ 365 | 1,012,066 | 1,012,431 | ||
Issuance of shares of common stock in public offering, net of underwriter discounts and offering costs (in shares) | 36,493 | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | $ 14 | (21,274) | (21,260) | ||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings (in shares) | 1,348 | ||||
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation | 106,659 | 6,419 | 113,078 | ||
Equity-based compensation | 94,409 | 8,012 | 102,421 | ||
Issuance of common units by subsidiary - Antero Midstream Partners LP | 65,395 | 65,395 | |||
Issuance of common units in Antero Midstream LP upon vesting of equity-based compensation awards, net of units withheld for income tax withholdings | (15,190) | 9,555 | (5,635) | ||
Net income (loss) and including noncontrolling interest | (848,816) | 99,368 | (749,448) | ||
Distributions to non-controlling interests | (75,082) | (75,082) | |||
Balances at Dec. 31, 2016 | $ 3,149 | $ 5,299,481 | $ 959,995 | $ 1,465,953 | $ 7,728,578 |
Shares Issued, Ending Balance at Dec. 31, 2016 | 314,877 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash flows from operating activities: | |||
Net income (loss) including noncontrolling interest | $ (749,448) | $ 979,996 | $ 675,835 |
Adjustment to reconcile net income to net cash provided by operating activities: | |||
Depletion, depreciation, amortization, and accretion | 812,346 | 711,418 | 479,167 |
Impairment of unproved properties | 162,935 | 104,321 | 15,198 |
Derivative fair value (gains) losses | 514,181 | (2,381,501) | (868,201) |
Gains on settled derivatives | 1,003,083 | 856,572 | 135,784 |
Deferred income tax expense (benefit) | (485,392) | 575,890 | 445,672 |
Equity in earnings of unconsolidated affiliate | (485) | ||
Distributions of earnings from unconsolidated affiliates | 7,702 | ||
Gain on sale of assets | (97,635) | (40,000) | |
Equity-based compensation expense | 102,421 | 97,877 | 112,252 |
Loss on early extinguishment of debt | 16,956 | 20,386 | |
Gain on sale of discontinued operations | (3,564) | ||
Deferred income tax expense - discontinued operations | 1,354 | ||
Other | (12,488) | 31,741 | 6,433 |
Changes in current assets and liabilities: | |||
Accounts receivable | 39,857 | (3,201) | (45,593) |
Accrued revenue | (133,718) | 63,316 | (94,733) |
Other current assets | 1,774 | (2,221) | (2,891) |
Accounts payable | 7,365 | (8,536) | (20,681) |
Accrued liabilities | 18,853 | 36,377 | 95,066 |
Revenue distributions payable | 34,040 | (52,403) | 85,763 |
Other current liabilities | (1,091) | 6,166 | 1,016 |
Net cash provided by operating activities | 1,241,256 | 1,015,812 | 998,263 |
Cash flows used in investing activities: | |||
Additions to proved properties | (134,113) | (64,066) | |
Additions to unproved properties | (611,631) | (198,694) | (777,422) |
Drilling and completion costs | (1,327,759) | (1,651,282) | (2,477,150) |
Additions to water handling and treatment systems | (188,188) | (131,051) | (196,675) |
Additions to gathering systems and facilities | (231,044) | (360,287) | (558,037) |
Additions to other property and equipment | (2,694) | (6,595) | (13,218) |
Investment in unconsolidated affiliate | (75,516) | ||
Change in other assets | 3,977 | 9,750 | (3,082) |
Proceeds from asset sales | 171,830 | 40,000 | |
Net cash used in investing activities | (2,395,138) | (2,298,159) | (4,089,650) |
Cash flows from financing activities: | |||
Issuance of common stock | 1,012,431 | 537,832 | |
Issuance of common units by Antero Midstream Partners LP | 65,395 | 240,703 | 1,087,224 |
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | 178,000 | ||
Issuance of senior notes | 1,250,000 | 750,000 | 1,102,500 |
Repayment of senior notes | (525,000) | (260,000) | |
Borrowings (repayments) on bank credit facility, net | (677,000) | (403,000) | 1,442,000 |
Make-whole premium on debt extinguished | (15,750) | (17,383) | |
Payments of deferred financing costs | (18,759) | (17,293) | (31,543) |
Distributions to noncontrolling interest in consolidated subsidiary | (75,082) | (34,129) | |
Employee tax withholding for settlement of equity compensation awards | (26,895) | (9,431) | (142) |
Other | (5,321) | (4,841) | (2,777) |
Net cash provided by financing activities | 1,162,019 | 1,059,841 | 3,319,879 |
Net increase (decrease) in cash and cash equivalents | 8,137 | (222,506) | 228,492 |
Cash and cash equivalents, beginning of period | 23,473 | 245,979 | 17,487 |
Cash and cash equivalents, end of period | 31,610 | 23,473 | 245,979 |
Supplemental disclosure of cash flow information: | |||
Cash paid during the period for interest | 239,369 | 219,945 | 163,055 |
Supplemental disclosure of noncash investing activities: | |||
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment | $ (152,093) | $ (169,783) | $ 181,591 |
Organization
Organization | 12 Months Ended |
Dec. 31, 2016 | |
Organization | |
Organization | (1) 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, NGL, 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” or “the Partnership”), the Company has water handling and treatment operations and midstream 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, 2016 | |
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, 2015 and 2016, and the results of its operations and its cash flows for the years ended December 31, 2014, 2015, and 2016. 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. The Company’s balance sheets and statements of cash flows for prior periods include reclassifications within current liabilities that were made to conform to the 2016 presentation. As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified except for those identified in note 20. (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 for which the Company is the primary beneficiary. The Company consolidates Antero Midstream as it is the primary beneficiary based on its significant ownership interest in Antero Midstream, the significance of the Company’s activities to Antero Midstream’s operations, and its influence over Antero Midstream through the presence of Company executives and directors that serve on the board of directors of Antero Midstream’s general partner. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. Noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream which are owned by the public and Antero Midstream’s general partner. An affiliate of Antero owns the general partner interest in Antero Midstream. Noncontrolling interest is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. Such investments are included in Other assets on the Company’s consolidated balance sheets. Income from such investments is included in Equity in earnings of unconsolidated affiliate on the Company’s consolidated statements of operations and cash flows. (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, regional levels of production, 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, NGLs, and crude oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells‑in‑progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred no such charges during the years ended December 31, 2014, 2015, and 2016. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units‑of‑production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property‑by‑property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired, or are expected to expire, was $15 million, $104 million, and $163 million for the years ended December 31, 2014, 2015, and 2016, respectively. The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties at the end of each quarter, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties during the year ended December 31, 2016. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2014 and 2015. At December 31, 2016, the Company did not have capitalized costs related to exploratory wells‑in‑progress which have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units‑of‑production method. Depletion expense for oil and gas properties was $419 million, $615 million, and $700 million for the years ended December 31, 2014, 2015, and 2016, 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 $53 million, $87 million, and $101 million for the years ended December 31, 2014, 2015, and 2016, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment. (h) Impairment of Long‑Lived Assets Other than Oil and Gas Properties The Company evaluates its long‑lived assets other than natural gas properties for impairment when events or changes in circumstances indicate that the related carrying values of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows or other techniques, as appropriate. There were no impairments for such assets during the years ended December 31, 2014, 2015, and 2016. (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 $5.9 million, $7.7 million, and $8.9 million for the years ended December 31, 2014, 2015, and 2016, 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. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument using the straight-line method. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2016, the Company had $14 million of unamortized deferred financing costs included in other long‑term assets, and $48 million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write‑off of previously deferred debt issuance costs were $11 million, $10 million, and $16 million for the years ended December 31, 2014, 2015, and 2016, respectively. (k) Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position. The Company records derivative instruments on the consolidated balance sheets as either 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, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes. (l) Asset Retirement Obligations The Company is obligated to dispose of certain long‑lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their lives. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations, which are then discounted at the Company’s credit‑adjusted, risk‑free interest rate. Revisions to estimated ARO often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If an obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. 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 its producing properties 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 compression 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, 2015 and 2016, 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, 2015 and 2016, the Company had no 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, 2014, 2015, and 2016 are as follows: 2014 2015 2016 Company A 5 % 19 % 29 % Company B — — 13 Company C 16 13 3 Company D 29 18 2 Company E 12 9 1 All others 38 41 52 100 % 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 fifteen 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 $1.6 billion at December 31, 2016 includes the following receivables by bank counterparty: Morgan Stanley—$551 million; Barclays—$392 million; JP Morgan—$306 million; Wells Fargo—$159 million; Scotiabank—$136 million; Canadian Imperial Bank of Commerce—$58 million; Toronto Dominion Bank—$32 million; Fifth Third Bank—$12 million; Bank of Montreal—$10 million; and Capital One—$2 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, 2016 for each of the European and American banks. The Company believes that all of these institutions currently are acceptable credit risks. The Company, at times, may have cash in banks in excess of federally insured amounts. (p) Income Taxes The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense. (q) Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long‑lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over‑the‑counter commodity price swaps 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 processing; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity. All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who resell the Company’s production to third parties located in foreign countries. (s) Marketing Revenues and Expenses Marketing revenues and expenses represent activities undertaken by the Company to purchase and sell third-party natural gas and NGLs and to market its excess firm transportation capacity in order to utilize this excess capacity. Marketing revenues include sales of purchased third-party gas and NGLs, as well as revenues from the release of firm transportation capacity to others. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense. (t) Earnings (loss) Per Common Share Earnings (loss) per common share for each period is computed by dividing net income (loss) 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 (loss) 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. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the year were the end of the performance period required for the vesting of such performance share unit awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive. The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): Year ended December 31, 2014 2015 2016 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock units — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — — 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 Performance stock units — — (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. When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive. (u) New Accounting Principle On March 30, 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2016-09, Stock Compensation–Improvements to Employee Share-Based Payment Accounting. This standard simplifies or clarifies several aspects of the accounting for equity-based payment awards, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Certain of these changes are required to be applied retrospectively, while other changes are required to be applied prospectively. The Company elected to early-adopt the standard as of January 1, 2016. As permitted by this standard, the Company has elected to account for forfeitures in compensation cost as they occur. This standard also permits an entity to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rate and requires that such payments be classified as financing activities on the statement of cash flows. As a result of adopting this standard, cash outflows attributable to tax withholdings on the net settlement of equity-classified awards have been reclassified from operating cash flows to financing cash flows. The retrospective adjustment to the consolidated statement of cash flows for the year ended December 31, 2015 is as follows (in thousands): As Previously Reported As Adjusted Year Ended Adjustment Year Ended Changes in accrued liabilities $ Employee tax withholding for settlement of equity compensation awards — |
Antero Midstream Partners LP
Antero Midstream Partners LP | 12 Months Ended |
Dec. 31, 2016 | |
Antero Midstream Partners LP | |
Antero Midstream Partners LP | (3) In 2014, the Company formed Antero Midstream to own, operate, and develop midstream assets to service Antero’s production. Antero Midstream’s assets consist of gathering pipelines, 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 Resources 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 is also the managing member of the entity that holds 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 and its subsidiaries are not guarantors of Antero’s obligations, and Antero is not a guarantor of Antero Midstream’s obligations (see note 17). On September 23, 2015, Antero contributed (i) all of the outstanding limited liability company interests of Antero Water LLC (“Antero Water”) to Antero Midstream and (ii) all of the assets, contracts, rights, permits and properties owned or leased by Antero and used primarily in connection with the construction, ownership, operation, use or maintenance of Antero’s advanced waste water treatment complex under construction in Doddridge County, West Virginia, to Antero Treatment LLC (“Antero Treatment”), a subsidiary of Antero Midstream (collectively, (i) and (ii) are referred to herein as the “Contributed Assets”). In consideration for the Contributed Assets, Antero Midstream (i) paid to Antero a cash distribution equal to $552 million, less $171 million of assumed debt, (ii) issued to Antero 10,988,421 common units representing limited partner interests in Antero Midstream, (iii) distributed to Antero proceeds of approximately $241 million from a private placement of Antero Midstream common units, and (iv) has agreed to pay Antero (a) $125 million in cash if Antero Midstream delivers 176,295,000 barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivers 219,200,000 barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. Antero Midstream borrowed $525 million on its bank credit facility in connection with this transaction. On March 30, 2016, Antero sold 8,000,000 of its Antero Midstream common units for $178 million. The sale of the units is reflected in stockholders’ equity as additional paid-in capital, net of taxes. On May 26, 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline, in which Antero is an anchor shipper, for approximately $45 million. This investment is accounted for under the equity method. During the third quarter of 2016, the Partnership entered into an Equity Distribution Agreement (the “Distribution Agreement”). Pursuant to the terms of the agreement, the Partnership may sell, from time to time through brokers acting as its sales agents, common units representing limited partner interests having an aggregate offering price of up to $250 million. Sales of the common units are made by means of ordinary brokers’ transactions on the New York Stock Exchange, at market prices, in block transactions, or as otherwise agreed to between the Partnership and the sales agents. Proceeds are used for general partnership purposes, which may include repayment of indebtedness and funding working capital or capital expenditures. The Partnership is under no obligation to offer and sell common units under the Distribution Agreement. During the year ended December 31, 2016, the Partnership issued and sold 2,391,595 common units under the Distribution Agreement, resulting in net proceeds of $65.4 million after deducting commissions and other offering costs. The Partnership used the net proceeds from the sales for general partnership purposes. As of December 31, 2016, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate amount of $183.8 million. At December 31, 2015 and December 31, 2016, Antero owned approximately 66.3% and 60.9% 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, 2016 | |
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 2014 by $3.6 million for the resolution of certain liabilities recorded at the time of the sales and settlement of final contractual purchase price adjustments. |
Sales of Assets
Sales of Assets | 12 Months Ended |
Dec. 31, 2016 | |
Appalachian Gathering Assets | |
Sale of Assets | |
Sale of Appalachian Gathering Assets | (5) Sales of Assets Sale of Pennsylvania Leasehold Acreage On December 16, 2016, the Company closed the sale of approximately 17,000 net acres primarily located in Washington and Westmoreland Counties, Pennsylvania. The acreage was outside of the Company’s infrastructure build-out and was not expected to be developed in the near future. Included in the sale were several producing wells and a gathering pipeline belonging to Antero Midstream. Total proceeds from the sale were $169.8 million (subject to customary purchase price adjustments), which includes the proceeds received by Antero Midstream. As a result of the sale, the Company recognized a gain on the sale of assets of $99.0 million for the year ended December 31, 2016. 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”) for $375 million. 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. |
Accrued Liabilities
Accrued Liabilities | 12 Months Ended |
Dec. 31, 2016 | |
Accrued Liabilities | |
Accrued Liabilities | 6) Accrued Liabilities Accrued liabilities as of December 31, 2015 and 2016 consisted of the following items (in thousands): December 31, 2015 2016 Accrued capital expenditures $ Accrued gathering, compression, processing, and transportation expenses Accrued marketing expenses Accrued interest expense Other accrued liabilities $ |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2016 | |
Long-Term Debt. | |
Long-Term Debt | (7) Long‑Term Debt Long‑term debt was as follows at December 31, 2015 and 2016 (in thousands): December 31, 2015 2016 Antero: Bank credit facility(a) $ 6.00% senior notes due 2020(b) — 5.375% senior notes due 2021(c) 5.125% senior notes due 2022(d) 5.625% senior notes due 2023(e) 5.00% senior notes due 2025(f) — Net unamortized premium Net unamortized debt issuance costs Antero Midstream: Bank credit facility(h) 5.375% senior notes due 2024 (i) — Net unamortized debt issuance costs — $ Antero Resources Corporation (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 assets and are subject to regular semiannual redeterminations. At December 31, 2016, the borrowing base was $4.75 billion and lender commitments were $4.0 billion. The next redetermination of the borrowing base is scheduled to occur in April 2017. 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, 2015 and 2016. As of December 31, 2016, Antero had an outstanding balance under the Credit Facility of $440 million with a weighted average interest rate of 2.44% and outstanding letters of credit of $710 million. As of December 31, 2015, Antero had an outstanding balance under the Credit Facility of $707 million, with a weighted average interest rate of 2.32%, and outstanding letters of credit of approximately $702 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) 6.00% Senior Notes Due 2020 On December 30, 2016, Antero satisfied and discharged the obligations with respect to its outstanding 6.00% senior notes due 2020 (the “2020” notes) having a principal balance of $525 million at a redemption price of 103% of the principal amount, plus accrued and unpaid interest. The call premium, along with the write-offs of the unamortized issuance premium and deferred financing costs, resulted in a loss of approximately $17 million which was charged to Loss on early extinguishment of debt in the accompanying statement of operations. (c) 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 at redemption prices ranging from 104.031% currently to 100.00% on or after November 1, 2019. If Antero undergoes a change of control, the holders of the 2021 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued and unpaid interest. (d) 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 and unpaid 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 and unpaid 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 and unpaid interest. (e) 5.625% Senior Notes Due 2023 On March 17, 2015, Antero issued $750 million of 5.625% senior notes due June 1, 2023 (the “2023 notes”) at par. The 2023 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2023 notes rank pari passu to Antero’s other outstanding senior notes. The 2023 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2023 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2023 notes at any time on or after June 1, 2018 at redemption prices ranging from 104.219% on or after June 1, 2018 to 100.00% on or after June 1, 2021. In addition, on or before June 1, 2018, Antero may redeem up to 35% of the aggregate principal amount of the 2023 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.625% of the principal amount of the 2023 notes, plus accrued and unpaid interest. At any time prior to June 1, 2018, Antero may also redeem the 2023 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2023 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero undergoes a change of control, the holders of the 2023 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2023 notes, plus accrued and unpaid interest. (f) 5.00% Senior Notes Due 2025 On December 21, 2016, Antero issued $600 million of 5.00% senior notes due March 1, 2025 (the “2025 notes”) at par. The 2025 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2025 notes rank pari passu to Antero’s other outstanding senior notes. The 2025 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2025 notes is payable on March 1 and September 1 of each year. Antero may redeem all or part of the 2025 notes at any time on or after March 1, 2020 at redemption prices ranging from 103.750% on or after March 1, 2020 to 100.00% on or after March 1, 2023. In addition, on or before March 1, 2020, Antero may redeem up to 35% of the aggregate principal amount of the 2025 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.00% of the principal amount of the 2025 notes, plus accrued and unpaid interest. At any time prior to March 1, 2020, Antero may also redeem the 2025 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2025 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero undergoes a change of control, the holders of the 2025 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2025 notes, plus accrued and unpaid interest. Proceeds from the 2025 notes were used to redeem the 2020 notes (see note 7(b) above) and for general corporate purposes. (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, 2017. At December 31, 2015 and 2016, there were no outstanding borrowings under this facility. Antero Midstream Partners LP (h) Senior Secured Revolving Credit Facility – Antero Midstream Antero Midstream has a secured revolving credit facility (the “Midstream Facility”) with a syndicate of bank lenders. At December 31, 2016, lender commitments were $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, 2015 and 2016. As of December 31, 2016, Antero Midstream had an outstanding balance under the Midstream Facility of $210 million with a weighted average interest rate of 2.23%. As of December 31, 2015, Antero Midstream had a total outstanding balance under the Midstream Facility of $620 million with a weighted average interest rate of 1.92%. 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. (i) 5.375% Senior Notes Due 2024 – Antero Midstream On September 13, 2016, Antero Midstream and its wholly-owned subsidiary, Antero Midstream Finance Corporation (“Midstream Finance Corp.”) as co-issuers, issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Midstream notes”) at par. The 2024 Midstream notes are unsecured and effectively subordinated to the Midstream Facility to the extent of the value of the collateral securing the Midstream Facility. The 2024 Midstream notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero Midstream’s wholly-owned subsidiaries, excluding Midstream Finance Corp., and certain of Antero Midstream’s future restricted subsidiaries. Interest on the 2024 Midstream notes is payable on March 15 and September 15 of each year. Antero Midstream may redeem all or part of the 2024 Midstream notes at any time on or after September 15, 2019 at redemption prices ranging from 104.031% on or after September 15, 2019 to 100.00% on or after September 15, 2022. In addition, prior to September 15, 2019, Antero Midstream may redeem up to 35% of the aggregate principal amount of the 2024 Midstream notes with an amount of cash not greater than the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest. At any time prior to September 15, 2019, Antero Midstream may also redeem the 2024 Midstream notes, in whole or in part, at a price equal to 100% of the principal amount of the 2024 Midstream notes plus a “make-whole” premium and accrued and unpaid interest. If Antero Midstream undergoes a change of control, the holders of the 2024 Midstream notes will have the right to require Antero Midstream to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2024 Midstream notes, plus accrued and unpaid interest. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations | |
Asset Retirement Obligations | (8) Asset Retirement Obligations The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2015 and 2016 (in thousands). 2015 2016 Asset retirement obligations—beginning of year $ Obligations incurred for wells drilled and producing properties acquired Revisions to prior estimates Accretion expense Asset retirement obligations—end of year $ Revisions to prior estimates in 2016 are primarily due to a decrease in the estimated costs to plug and abandon the Company’s horizontal wells. Revisions to prior estimates in 2015 are primarily due to a decrease in the estimated economic lives of the Company’s 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, 2016 | |
Equity-Based Compensation | |
Equity-Based Compensation | (9) Equity‑Based Compensation Antero is authorized to grant up to 16,906,500 shares of common stock to employees and directors of the Company under the Antero Resources Corporation Long‑Term Incentive Plan (the “Plan”). The Plan allows equity‑based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent awards, and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of Antero’s Board of Directors. A total of 8,449,452 shares were available for future grant under the Plan as of December 31, 2016. Antero Midstream’s general partner is authorized to grant up to 10,000,000 common units representing limited partner interests in Antero Midstream under the Antero Midstream Partners LP Long-Term Incentive Plan (the “Midstream Plan”) to certain officers, employees, and consultants of Antero and Antero Midstream’s general partner, and its non-employee directors. A total of 7,937,930 common units are available for future grant under the Midstream Plan as of December 31, 2016. The Company’s equity‑based compensation expense, by type of award, is as follows for the years ended December 31, 2014, 2015, and 2016 (in thousands): Year ended December 31, 2014 2015 2016 Profits interests awards $ — Restricted stock unit awards Stock options Performance share unit awards — — Antero Midstream phantom unit awards Equity awards issued to directors Total expense $ Profits Interests Awards Certain profits interest awards historically held by certain of the Company’s officers and employees were fully vested as of December 31, 2015. All available profits interest awards were made prior to the date of the Company’s IPO in 2013, and no additional profits interest awards have been made since the Company’s IPO. Restricted Stock 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. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. A summary of restricted stock and restricted stock unit awards activity for the year ended December 31, 2016 is as follows: Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2015 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2016 $ $ Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. Unamortized expense of $130.2 million at December 31, 2016 is expected to be recognized over a weighted average period of approximately 2.0 years. Stock Options Stock options granted under the Plan vest over periods from one to four years and have a maximum contractual life of 10 years. Expense related to stock options is recognized on a straight‑line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. Stock options are granted with an exercise price equal to or greater than the market price of the Company’s common stock on the date of grant. A summary of stock option activity for the year ended December 31, 2016 is as follows: Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2015 $ $ — Granted — $ — Exercised — — Forfeited $ Expired — — Outstanding at December 31, 2016 $ $ — Vested or expected to vest as of December 31, 2016 $ $ — Exercisable at December 31, 2016 $ $ — Intrinsic value is based on the exercise price of the options and the closing price of the Company’s stock on the referenced dates. A Black‑Scholes option‑pricing model is used to determine the grant-date fair value of stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies’ stock prices as the Company common stock had traded for a relatively short period of time at the dates the options were granted. The risk‑free interest rate was determined using the implied yield available for zero‑coupon U.S. government issues with a remaining term approximating the expected life of the options. A dividend yield of zero was assumed. The following table presents information regarding the weighted average fair value for options granted during the years ended December 31, 2014 and 2015 and the assumptions used to determine fair value. Year ended December 31, 2014 Year ended December 31, 2015 Dividend yield — % — % Volatility % % Risk-free interest rate % % Expected life (years) Weighted average fair value of options granted $ $ As of December 31, 2016, there was $5.4 million of unamortized equity‑based compensation expense related to nonvested stock options. That expense is expected to be recognized over a weighted average period of approximately 2.2 years. Performance Share Unit Awards Performance Share Unit Awards Based on Price Targets In the first quarter of 2016, the Company granted performance share unit awards (“PSUs”) to certain of its executive officers. The vesting of these PSUs is conditioned on the closing price of the Company’s common stock achieving specific thresholds over 10-day periods, subject to the following vesting restrictions: no PSUs may vest before the first anniversary of the grant date; no more than one-third of the PSUs may vest before the second anniversary of the grant date; and no more than two-thirds of the PSUs may vest before the third anniversary of the grant date. Any PSUs which have not vested by the fifth anniversary of the grant date will expire. Expense related to these PSUs is recognized on a graded basis over three years. Performance Share Unit Awards Based on Total Shareholder Return In the second quarter of 2016, the Company granted PSUs to certain of its employees and executive officers which vest based on the total shareholder return (“TSR”) of the Company’s common stock relative to the TSR of a peer group of companies over a three-year performance period. The number of performance shares which may ultimately be earned ranges from zero to 200% of the PSUs granted. Expense related to these PSUs is recognized on a straight-line basis over three years. Summary Information for Performance Share Unit Awards A summary of PSU activity for the year ended December 31, 2016 is as follows: Number of Weighted Total awarded and unvested—December 31, 2015 — $ — Granted $ Vested — $ — Forfeited $ Total awarded and unvested—December 31, 2016 $ The grant-date fair values of PSUs were determined using Monte Carlo simulations, which use a probabilistic approach for estimating the fair values of the awards. Expected volatilities were derived from the volatility of the historical stock prices of a peer group of similar publicly-traded companies’ stock prices. The risk-free interest rate was determined using the yield available for zero-coupon U.S. government issues with remaining terms corresponding to the service periods of the PSUs. A dividend yield of zero was assumed. The following table presents information regarding the weighted average fair value for PSUs granted during the year ended December 31, 2016 and the assumptions used to determine the fair values. Year ended December 31, 2016 Dividend yield — % Volatility % Risk-free interest rate % Weighted average fair value of awards granted $ As of December 31, 2016, there was $14.7 million of unamortized equity-based compensation expense related to unvested PSUs. That expense is expected to be recognized over a weighted average period of approximately 2.1 years. Antero Midstream Partners Phantom Unit Awards Phantom units granted by Antero Midstream vest subject to the satisfaction of service requirements, upon the completion of which common units in Antero Midstream are delivered to the holder of the phantom units. These phantom units are treated, for accounting purposes, as if Antero Midstream distributed the units to Antero. Antero recognizes compensation expense as the units are granted to employees, and a portion of the expense is allocated to Antero Midstream. Expense related to each phantom unit award is recognized on a straight-line basis over the requisite service period of the entire award. Forfeitures are accounted for as they occur through reversal of expense on awards that were forfeited during the period. The grant date fair values of these awards are determined based on the closing price of Antero Midstream’s common units on the date of grant. A summary of phantom unit awards activity for the year ended December 31, 2016 is as follows: Number of Weighted Aggregate Total awarded and unvested—December 31, 2015 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2016 $ $ Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. Unamortized expense of $33.2 million at December 31, 2016 is expected to be recognized over a weighted average period of approximately 2.1 years. |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Financial Instruments | |
Financial Instruments | (10) Financial Instruments The carrying values of accounts receivable and accounts payable at December 31, 2015 and 2016 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, 2015 and 2016 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 $2.6 billion at December 31, 2015 and $3.5 billion at December 31, 2016. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $657 million at December 31, 2016. See note 11 for information regarding the fair value of derivative financial instruments. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments. | |
Derivative Instruments | (11) Derivative Instruments (a) Commodity Derivatives The Company periodically enters into natural gas, NGLs, and oil derivative contracts with counterparties to hedge the price risk associated with its production. These derivatives are not 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. The Company was party to various fixed price commodity swap contracts that settled during the years ended December 31, 2014, 2015, and 2016. The Company enters into these swap contracts when management believe that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the difference to the counterparty. When actual commodity prices are below the contractually provided fixed price, the Company receives the difference from the counterparty. When actual commodity prices are above the contractually provided fixed price, the Company pays the difference to the counterparty. In addition to fixed price swap contracts, 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 at which the Company sells a portion of its natural gas production. 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, 2016, the Company’s fixed price natural gas and NGLs swap positions from January 1, 2017 through December 31, 2022 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: NYMEX=Henry Hub; CGTLA=Columbia Gas Louisiana Onshore; CCG=Chicago City Gate; Mont Belvieu-Ethane=Mont Belvieu Purity Ethane; Mont Belvieu-Propane=Mont Belvieu Propane; NYMEX-WTI=West Texas Intermediate): Natural gas Oil Natural Gas Weighted Three months ending March 31, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending June 30, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending September 30, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending December 31, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Year ending December 31, 2018: NYMEX ($/MMBtu) — $ Mont Belvieu-Propane ($/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, 2016, 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, were as follows: Natural gas Hedged Year ending December 31, 2017: $ As of December 31, 2016, 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, were as follows: Natural gas Hedged 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, 2015 and 2016. None of the Company’s derivative instruments are designated as hedges for accounting purposes. December 31, 2015 December 31, 2016 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ Current assets Commodity contracts Long-term assets Long-term assets Total asset derivatives Liability derivatives not designated as hedges for accounting purposes: Commodity contracts Current liabilities — Current liabilities Commodity contracts Long-term liabilities — Long-term liabilities 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, 2015 December 31, 2016 Gross Gross amounts Net amounts Gross Gross amounts Net amounts of assets (liabilities) on balance sheet Commodity derivative assets $ $ Commodity derivative liabilities $ — — — $ The following is a summary of derivative fair value gains (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2014, 2015, and 2016 (in thousands): Statement of Year ended December 31, location 2014 2015 2016 Commodity derivative fair value gains (losses) 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, 2016 | |
Contingencies | |
Contract Termination and Rig Stacking | (12) Contract Termination and Rig Stacking During the year ended December 31, 2015, the Company incurred $38.5 million of costs for the buy-back and termination of a firm sales contract priced at an unfavorable pricing index and the delay or cancelation of drilling contracts with third-party contractors. There were no such costs incurred during the year ended December 31, 2016. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes | |
Income Taxes | (13) Income Taxes For the years ended December 31, 2014, 2015, and 2016, income tax expense (benefit) from continuing operations consisted of the following (in thousands): Year ended December 31, 2014 2015 2016 Current income tax benefit $ — — Deferred income tax expense (benefit) Total income tax expense (benefit) from continuing operations $ Income tax expense (benefit) 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, 2014, 2015, and 2016 as a result of the following (in thousands): Year ended December 31, 2014 2015 2016 Federal income tax expense (benefit) $ State income tax expense (benefit), 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, 2014, 2015, and 2016, income tax expense (benefit) was allocated to continuing and discontinued operations as follows (in thousands): Year ended December 31, 2014 2015 2016 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, 2015 and 2016 is as follows (in thousands): 2015 2016 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 Other — 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 and $16 million at December 31, 2015 and 2016, respectively related to NOL carryforwards primarily attributable to states where the Company no longer operates. The valuation allowance was reduced in 2016 due to a change in the estimated amount of state NOLs that can be utilized in the future. The amount of the deferred tax asset considered realizable could be further reduced in the near term if estimates of future taxable income during the carryforward period are revised. The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more‑likely-than‑not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. In 2016, the Company reversed unrecognized benefits recorded in prior years due to the expiration of the applicable statutes of limitations. The removal of the unrecognized benefits does not impact the Company’s 2016 effective tax rate. The Company will continue to monitor potential uncertain tax positions, but does not anticipate any changes within the next year. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2014 2015 2016 Balance at beginning of year $ Reductions for tax positions of prior years — — Balance at end of year $ — As of December 31, 2016, the Company’s corporate subsidiaries have U.S. Federal and state net operating loss carryforwards (NOLs) of $1.5 billion and $1.4 billion, respectively, which expire at various dates from 2024 to 2036. The tax years 2013 through 2016 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 2012 through 2016. |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2016 | |
Commitments | |
Commitments | (14) Commitments The following is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, as well as leases that have remaining lease terms in excess of one year as of December 31, 2016 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (a) (b) (c) (d) Total 2017 $ 2018 2019 2020 — 2021 — 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 are based on the Company’s minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. (b) Processing, Gathering, and Compression Service Commitments The Company has entered into various long‑term gas processing agreements for certain of its production that will allow it to realize the value of its NGLs. The minimum payment obligations under the agreements are presented in the table. The Company has various gathering and compression service agreements with third parties that provide for payments based on volumes gathered or compressed. The minimum payment obligations under these agreements are presented in the table. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. The values in the table also include Antero Midstream’s commitments for the construction of its advanced waste water treatment complex. The table does not include intracompany commitments. (c) Drilling Rig Service Commitments The Company has obligations under agreements with service providers to procure drilling rigs and completion services. The values in the table represent the gross amounts that the Company is committed to pay; however, the Company will record in the consolidated financial statements its proportionate share of costs based on its working interest. (d) Office and Equipment Leases The Company leases various office space and equipment, as well as field equipment, under capital and operating lease arrangements. Rental expense under operating leases was $10 million, $9 million, and $9 million for the years ended December 31, 2014, 2015, and 2016, respectively. |
Contingencies
Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Contingencies | |
Contingencies | (15) Contingencies The Company is the plaintiff in two nearly identical lawsuits against South Jersey Gas Company and South Jersey Resources Group, LLC (collectively “SJGC”) pending in United States District Court in Colorado. The Company filed suit against SJGC seeking relief for breach of contract and damages in the amounts that SJGC has short paid, and continues to short pay, the Company in connection with two long term gas contracts. Under those contracts, SJGC are long term purchasers of some of the Company’s natural gas production. Deliveries under the contracts began in October 2011 and the delivery obligation continues through October 2019. SJGC unilaterally breached the contracts claiming 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. Beginning in October 2014, SJGC began short paying the Company based on indexes unilaterally selected by SJGC and not the index specified in the contract. The Company contends that no market disruption event has occurred and that SJGC have breached the contracts by failing to pay the Company based on the express price terms of the contracts. Through December 31, 2016, the Company estimates that it is owed approximately $55 million more than SJGC has paid using the indexes unilaterally selected by them. The Company and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”) are also involved in a pricing dispute involving contracts that the Company began delivering gas under in January 2016. The Company has invoiced WGL at the index price specified in the contract and WGL has paid the Company based on that invoice price; however, WGL asserted that the index price is no longer appropriate under the contracts and that an undefined alternative index was more appropriate for the delivery point of the gas. In July 2016, the matter was referred to arbitration by the Colorado district court. In January 2017, the arbitration panel ruled in the Company’s favor. As a result, the index price has remained as specified in the contracts and there will be no adjustments to the invoices that have been paid by WGL. 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, 2016 | |
Segment Information | |
Segment Information | (16) Segment Information See note 2(r) for a description of the Company’s determination of its reportable segments. Revenues from gathering and processing and water handling and treatment operations are primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties. Operating segments are evaluated based on their contribution to consolidated results, which is determined by the respective operating income of each segment. General and administrative expenses are allocated to the gathering and processing and water handling and treatment segments based on the nature of the expenses and on a combination of the segments’ proportionate share of the Company’s consolidated property and equipment, capital expenditures, and labor costs, as applicable. General and administrative expenses related to the marketing segment are not allocated because they are immaterial. Other income, income taxes, and interest expense are primarily managed 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, 2014, 2015, and 2016 (in thousands): Exploration Gathering and processing Water handling and treatment Marketing Elimination of Consolidated 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 Gathering and processing Water handling and treatment Marketing Elimination of Consolidated 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 $ — Exploration Gathering and processing Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2016: 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, 2016 | |
Subsidiary Guarantors | |
Subsidiary Guarantors | (17) 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 7). In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a “Subsidiary” of the Company (as defined in the indentures governing the notes) or the sale of all or substantially all of its assets (other than by lease)) and whether or not the subsidiary guarantor is the surviving entity in such transaction to a person which is not Antero or a restricted subsidiary of Antero, such subsidiary guarantor will be released from its obligations under its subsidiary guarantee if the sale or other disposition does not violate the covenants set forth in the indentures governing the notes. In addition, a subsidiary guarantor will be released from its obligations under the indentures and its guarantee, upon the release or discharge of the guarantee of other Indebtedness (as defined in the indentures governing the notes) that resulted in the creation of such guarantee, except a release or discharge by or as a result of payment under such guarantee; if Antero designates such subsidiary as an unrestricted subsidiary and such designation complies with the other applicable provisions of the indentures governing the notes or in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the notes. The following Condensed Consolidating Balance Sheets at December 31, 2015 and 2016, and the related Condensed Consolidating Statements of Operations and Comprehensive Income and Condensed Consolidating Statements Cash Flows for the years ended December 31, 2014, 2015, and 2016, 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 are not restricted from making distributions to the Parent. Condensed Consolidating Balance Sheet December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor 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 Balance Sheet December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor 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 — — — Derivative instruments — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Contingent acquisition consideration — — — Derivative instruments — — — 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 Non-Guarantor Eliminations Consolidated Revenue and other: 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 assets — — — Other income — — — Total revenue and other — 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 expenses: Interest — — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income from continuing operations before income taxes and discontinued operations — 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 Non-Guarantor Eliminations Consolidated Revenue and other: 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 and other — 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 Operations and Comprehensive Income (Loss) Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — — Marketing — — — Commodity derivative fair value losses — — — Gain on sale of assets — — Other income — — — Total revenue and other — 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 — Accretion of contingent acquisition consideration — — — Total operating expenses — Operating income (loss) — Other income (expenses): Equity in earnings of unconsolidated affiliate — — — Interest — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income (loss) before income taxes — Provision for income tax benefit — — — Net income (loss) and comprehensive income (loss) including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ — Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Parent Guarantor Non-Guarantor 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 by 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 — — Employee tax withholding for settlement of equity compensation awards — — — Other — — — Net cash provided by (used in) financing activities — Net 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 Non-Guarantor 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 to 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 by Antero Midstream Partners LP — — — Issuance of senior notes — — — Borrowings (repayments) on bank credit facility, net — Payments of deferred financing costs — — Distributions — Employee tax withholding for settlement of equity compensation awards — — Other — — Net cash provided by (used in) financing activities — Net 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, 2016 (In thousands) Parent Guarantor Non-Guarantor 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 — — — Investments in unconsolidated affiliates — — — Change in other assets — — Net distributions from subsidiaries — — — Proceeds from asset sales — — Net cash used in investing activities — Cash flows provided by financing activities: Issuance of common stock — — — Issuance of common units by Antero Midstream Partners LP — — — Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation — — — Issuance of senior notes — — Repayment of senior notes — — — Repayments on bank credit facility, net — — Make-whole premium on debt extinguished — — — Payments of deferred financing costs — — Distributions — — Employee tax withholding for settlement of equity compensation awards — — Other — — Net cash provided by 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, 2016 | |
Quarterly Financial Information (Unaudited) | |
Quarterly Financial Information (Unaudited) | (18) Quarterly Financial Information (Unaudited) The Company’s quarterly consolidated financial information for the years ended December 31, 2015 and 2016 is summarized in the following tables (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. First Second Third Fourth Year Ended December 31, 2015: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) 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—basic $ $ $ $ Earnings (loss) per common share—assuming dilution $ $ $ $ First Second Third Fourth Year Ended December 31, 2016: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) 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, 2016 | |
Supplemental Information on Oil and Gas Producing Activities (Unaudited) | |
Supplemental Information on Oil and Gas Producing Activities (Unaudited) | (19) Supplemental Information on Oil and Gas Producing Activities (Unaudited) The following is supplemental information regarding the Company’s consolidated oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties. (a) Capitalized Costs Relating to Oil and Gas Producing Activities Year ended December 31, (In thousands) 2015 2016 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) 2014 2015 2016 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) 2014 2015 2016 Revenues $ Operating expenses: Production expenses Exploration expenses Depletion and depreciation Impairment of unproved properties Results of operations before income tax expense Income tax (expense) benefit 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 Company’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the years ended December 31, 2014, 2015, and 2016 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (D&M) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States. Proved reserves are the estimated quantities of crude oil, condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months. Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future oil and gas prices, cash flows from operations, future drilling costs, demand for natural gas, and other economic factors. Natural NGLs Oil and Equivalents Proved reserves: December 31, 2013 Revisions — (a) Extensions, discoveries and other additions Purchases of reserves — — Production December 31, 2014 Revisions Extensions, discoveries and other additions Production December 31, 2015 Revisions Extensions, discoveries and other additions Production Purchases of reserves Sales of reserves in place — — December 31, 2016 (a) Less than 1.0. Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2014 December 31, 2015 December 31, 2016 Proved undeveloped reserves: December 31, 2014 December 31, 2015 December 31, 2016 Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2014, 2015, and 2016 in the above table include the following: 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 the Company’s leasehold acquisition efforts. · Positive 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. · Positive revisions of 1,091 Bcfe due to partial ethane recovery is a result of changing from ethane rejection at December 31, 2014 to partial ethane recovery in 2015. In 2015, the Company began ethane recovery and changed its underlying production assumptions to the recovery of approximately 11,500 gross barrels per day of ethane at December 31, 2015. · Negative performance revisions of 358 Bcfe resulted from the revised statistical analysis of reserves based on actual production results. · Negative revisions of 2,332 Bcfe were due to the SEC 5-year development rule because the Company no longer expected certain locations in the eastern portion of its Marcellus acreage containing primarily dry gas to be developed within five years. · Negative revisions of 202 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. 2016 Changes in Reserves · Extensions, discoveries and other additions of 2,637 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales, which was aided in 2016 by longer laterals than in previous years and the utilization of advanced completion techniques. · Purchases of 624 Bcfe relate to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales. · Positive revisions of 1,359 Bcfe are due to an increase in our actual and assumed future ethane recovery rate based on existing sales contracts for ethane. · Positive performance revisions of 762 Bcfe primarily relate to improved well performance. · Negative revisions of 2,478 Bcfe were due to the impact of the SEC 5-year development rule. Due to the SEC 5-year development rule, these primarily dry gas reserves were displaced by our current development plan targeting more liquids-rich areas in our portfolio which have better economic returns. · Negative revisions of 47 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil. · A negative revision of 10 Bcfe was related to our sale of producing and non-producing leasehold in Pennsylvania. 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) 2014 2015 2016 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, 2014 $ December 31, 2015 $ December 31, 2016 $ (f) Changes in Standardized Measure of Discounted Future Net Cash Flow Year ended December 31, (in millions) 2014 2015 2016 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 — Divestitures — — Revisions of previous quantity estimates Accretion of discount Net change in income taxes Other changes Net increase (decrease) Beginning of year End of year $ |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events | |
Subsequent Events | (20) Subsequent Events On February 6, 2017, Antero Midstream formed a joint venture (the “Joint Venture”) to develop processing assets in Appalachia with MarkWest Energy Partners, L.P. (“MarkWest”), a wholly owned subsidiary of MPLX, L.P. Antero Midstream and MarkWest will each own a 50% interest in the Joint Venture and MarkWest will operate the Joint Venture assets. The Joint Venture assets will consist of processing plants in West Virginia and a one-third interest in a recently commissioned MarkWest fractionator in Ohio. In conjunction with the formation of the Joint Venture, on February 10, 2017 Antero Midstream issued 6,900,000 common units, including the underwriters’ purchase option, generating net proceeds of approximately $223 million. Antero Midstream used the net proceeds to fund the initial $155 million contribution to the Joint Venture, repay outstanding borrowings under its credit facility, and for general partnership purposes. |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2015 and 2016, and the results of its operations and its cash flows for the years ended December 31, 2014, 2015, and 2016. 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. The Company’s balance sheets and statements of cash flows for prior periods include reclassifications within current liabilities that were made to conform to the 2016 presentation. As of the date these financial statements were filed with the SEC, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified except for those identified in note 20. |
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 for which the Company is the primary beneficiary. The Company consolidates Antero Midstream as it is the primary beneficiary based on its significant ownership interest in Antero Midstream, the significance of the Company’s activities to Antero Midstream’s operations, and its influence over Antero Midstream through the presence of Company executives and directors that serve on the board of directors of Antero Midstream’s general partner. All significant intercompany accounts and transactions have been eliminated in the Company’s consolidated financial statements. Noncontrolling interest in the Company’s consolidated financial statements represents the interests in Antero Midstream which are owned by the public and Antero Midstream’s general partner. An affiliate of Antero owns the general partner interest in Antero Midstream. Noncontrolling interest is included as a component of equity in the Company’s consolidated balance sheets. Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. Such investments are included in Other assets on the Company’s consolidated balance sheets. Income from such investments is included in Equity in earnings of unconsolidated affiliate on the Company’s consolidated statements of operations and cash flows. |
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, regional levels of production, 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, NGLs, and crude oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the Company determines that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells‑in‑progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. The Company incurred no such charges during the years ended December 31, 2014, 2015, and 2016. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units‑of‑production amortization rate. A gain or loss is recognized for all other sales of producing properties. Unproved properties are assessed for impairment on a property‑by‑property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed, to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of unproved properties for leases which have expired, or are expected to expire, was $15 million, $104 million, and $163 million for the years ended December 31, 2014, 2015, and 2016, respectively. The Company evaluates the carrying amount of its proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates, anticipated capital expenditures, and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties at the end of each quarter, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties during the year ended December 31, 2016. Additionally, the Company did not record any impairment expenses for proved properties during the years ended December 31, 2014 and 2015. At December 31, 2016, the Company did not have capitalized costs related to exploratory wells‑in‑progress which have been deferred for longer than one year pending determination of proved reserves. The provision for depletion of oil and gas properties is calculated on a geological reservoir basis using the units‑of‑production method. Depletion expense for oil and gas properties was $419 million, $615 million, and $700 million for the years ended December 31, 2014, 2015, and 2016, respectively. |
Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems | Gathering Pipelines, Compressor Stations, and Water Handling and Treatment Systems Expenditures for construction, installation, major additions, and improvements to property, plant, and equipment that is not directly related to production are capitalized, whereas minor replacements, maintenance, and repairs are expensed as incurred. Gathering pipelines and compressor stations are depreciated using the straight‑line method over their estimated useful lives of 20 years. Water handling and treatment systems are depreciated using the straight-line method over their estimated useful lives of 5 to 20 years. Depreciation expense for gathering pipelines, compressor stations, and water handling and treatment systems was $53 million, $87 million, and $101 million for the years ended December 31, 2014, 2015, and 2016, 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 assets being assessed. If the carrying values of the assets are deemed not recoverable, the carrying values are reduced to the estimated fair values, which are based on discounted future cash flows or other techniques, as appropriate. There were no impairments for such assets during the years ended December 31, 2014, 2015, and 2016. |
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 $5.9 million, $7.7 million, and $8.9 million for the years ended December 31, 2014, 2015, and 2016, 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. Such costs are capitalized and included in Other assets on the consolidated balance sheets if related to the Company’s revolving credit facilities, and are included as a reduction to Long-term debt on the consolidated balance sheets if related to the issuance of the Company’s senior notes. These costs are amortized over the term of the related debt instrument using the straight-line method. The Company charges expense for unamortized deferred financing costs if credit facilities are retired prior to their maturity date. At December 31, 2016, the Company had $14 million of unamortized deferred financing costs included in other long‑term assets, and $48 million of unamortized deferred financing costs included as a reduction to long-term debt. The amounts amortized and the write‑off of previously deferred debt issuance costs were $11 million, $10 million, and $16 million for the years ended December 31, 2014, 2015, and 2016, respectively. |
Derivative Financial Instruments | Derivative Financial Instruments In order to manage its exposure to natural gas, NGLs, and oil price volatility, the Company enters into derivative transactions from time to time, which may include commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements related to the price risk associated with the Company’s production. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent that the counterparty is unable to satisfy its settlement obligations. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position. The Company records derivative instruments on the consolidated balance sheets as either 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, including gains or losses on settled derivatives, are classified as revenues on the Company’s consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes. |
Asset Retirement Obligations Policy | 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 obligations, which are then discounted at the Company’s credit‑adjusted, risk‑free interest rate. Revisions to estimated ARO often result from changes in retirement cost estimates or changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If an obligation is settled for an amount other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. 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 its producing properties 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 compression 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, 2015 and 2016, 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 Revenues | Natural Gas, NGLs, and Oil Revenues Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month after the sale has occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a revenue distribution payable to the extent it receives more than its proportionate share of natural gas revenues. At December 31, 2015 and 2016, the Company had no 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, 2014, 2015, and 2016 are as follows: 2014 2015 2016 Company A 5 % 19 % 29 % Company B — — 13 Company C 16 13 3 Company D 29 18 2 Company E 12 9 1 All others 38 41 52 100 % 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 fifteen 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 $1.6 billion at December 31, 2016 includes the following receivables by bank counterparty: Morgan Stanley—$551 million; Barclays—$392 million; JP Morgan—$306 million; Wells Fargo—$159 million; Scotiabank—$136 million; Canadian Imperial Bank of Commerce—$58 million; Toronto Dominion Bank—$32 million; Fifth Third Bank—$12 million; Bank of Montreal—$10 million; and Capital One—$2 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, 2016 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 tax laws or tax rates is recognized in income during the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense. |
Fair Value Measurements | Fair Value Measurements FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties and other long‑lived assets). Fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted, quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over‑the‑counter commodity price swaps 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 processing; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity. All of the Company’s assets are located in the United States and substantially all of its production revenues are attributable to customers located in the United States; however, some of the Company’s production revenues are attributable to customers who resell the Company’s production to third parties located in foreign countries. |
Marketing Revenues and Expenses | Marketing Revenues and Expenses Marketing revenues and expenses represent activities undertaken by the Company to purchase and sell third-party natural gas and NGLs and to market its excess firm transportation capacity in order to utilize this excess capacity. Marketing revenues include sales of purchased third-party gas and NGLs, as well as revenues from the release of firm transportation capacity to others. Marketing expenses include the cost of purchased third-party natural gas and NGLs. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity and is charged to transportation expense. |
Earnings (loss) per common share | 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 (loss) 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. The Company includes performance share unit awards in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the year were the end of the performance period required for the vesting of such performance share unit awards. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effect of all equity awards is antidilutive. The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): Year ended December 31, 2014 2015 2016 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock units — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — — 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 Performance stock units — — (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. When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive. |
Adoption of New Accounting Principle | New Accounting Principle On March 30, 2016, the Financial Accounting Standards Board (the “FASB”) issued ASU No. 2016-09, Stock Compensation–Improvements to Employee Share-Based Payment Accounting. This standard simplifies or clarifies several aspects of the accounting for equity-based payment awards, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Certain of these changes are required to be applied retrospectively, while other changes are required to be applied prospectively. The Company elected to early-adopt the standard as of January 1, 2016. As permitted by this standard, the Company has elected to account for forfeitures in compensation cost as they occur. This standard also permits an entity to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory tax rate and requires that such payments be classified as financing activities on the statement of cash flows. As a result of adopting this standard, cash outflows attributable to tax withholdings on the net settlement of equity-classified awards have been reclassified from operating cash flows to financing cash flows. The retrospective adjustment to the consolidated statement of cash flows for the year ended December 31, 2015 is as follows (in thousands): As Previously Reported As Adjusted Year Ended Adjustment Year Ended Changes in accrued liabilities $ Employee tax withholding for settlement of equity compensation awards — |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Summary of Significant Accounting Policies | |
Schedule of the Company sales to major customers (purchases in excess of 10% of total sales) | 2014 2015 2016 Company A 5 % 19 % 29 % Company B — — 13 Company C 16 13 3 Company D 29 18 2 Company E 12 9 1 All others 38 41 52 100 % 100 % 100 % |
Reconciliation of basic weighted average shares outstanding to diluted weighted average shares outstanding | The following is a reconciliation of the Company’s basic weighted average shares outstanding to diluted weighted average shares outstanding during the periods presented (in thousands): Year ended December 31, 2014 2015 2016 Basic weighted average number of shares outstanding Add: Dilutive effect of non-vested restricted stock units — Add: Dilutive effect of outstanding stock options — — — Add: Dilutive effect of performance stock units — — — 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 Performance stock units — — (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. When the Company incurs a net loss, all outstanding equity awards are excluded from the calculation of diluted loss per common share because the inclusion of these awards would be anti-dilutive. |
Summary of adjustments from early adoption of new accounting pronouncement | The retrospective adjustment to the consolidated statement of cash flows for the year ended December 31, 2015 is as follows (in thousands): As Previously Reported As Adjusted Year Ended Adjustment Year Ended Changes in accrued liabilities $ Employee tax withholding for settlement of equity compensation awards — |
Accrued Liabilities (Tables)
Accrued Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accrued Liabilities | |
Schedule of accrued liabilities | Accrued liabilities as of December 31, 2015 and 2016 consisted of the following items (in thousands): December 31, 2015 2016 Accrued capital expenditures $ Accrued gathering, compression, processing, and transportation expenses Accrued marketing expenses Accrued interest expense Other accrued liabilities $ |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Long-Term Debt. | |
Schedule of long-term debt | Long‑term debt was as follows at December 31, 2015 and 2016 (in thousands): December 31, 2015 2016 Antero: Bank credit facility(a) $ 6.00% senior notes due 2020(b) — 5.375% senior notes due 2021(c) 5.125% senior notes due 2022(d) 5.625% senior notes due 2023(e) 5.00% senior notes due 2025(f) — Net unamortized premium Net unamortized debt issuance costs Antero Midstream: Bank credit facility(h) 5.375% senior notes due 2024 (i) — Net unamortized debt issuance costs — $ |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2015 and 2016 (in thousands). 2015 2016 Asset retirement obligations—beginning of year $ Obligations incurred for wells drilled and producing properties acquired 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, 2016 | |
Equity-Based Compensation | |
Schedule of equity-based compensation expense | The Company’s equity‑based compensation expense, by type of award, is as follows for the years ended December 31, 2014, 2015, and 2016 (in thousands): Year ended December 31, 2014 2015 2016 Profits interests awards $ — Restricted stock unit awards Stock options Performance share unit awards — — Antero Midstream phantom unit awards Equity awards issued to directors Total expense $ |
Summary of restricted stock and restricted stock unit awards activity | Weighted Aggregate Number of grant date intrinsic value Total awarded and unvested—December 31, 2015 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2016 $ $ |
Summary of stock option activity | Weighted Weighted average Intrinsic Stock exercise contractual value Outstanding at December 31, 2015 $ $ — Granted — $ — Exercised — — Forfeited $ Expired — — Outstanding at December 31, 2016 $ $ — Vested or expected to vest as of December 31, 2016 $ $ — Exercisable at December 31, 2016 $ $ — |
Schedule of weighted average fair value assumptions used for stock options | Year ended December 31, 2014 Year ended December 31, 2015 Dividend yield — % — % Volatility % % Risk-free interest rate % % Expected life (years) Weighted average fair value of options granted $ $ |
Summary of Performance Stock Unit activity | A summary of PSU activity for the year ended December 31, 2016 is as follows: Number of Weighted Total awarded and unvested—December 31, 2015 — $ — Granted $ Vested — $ — Forfeited $ Total awarded and unvested—December 31, 2016 $ |
Schedule of weighted average fair value assumptions used for PSUs granted | Year ended December 31, 2016 Dividend yield — % Volatility % Risk-free interest rate % Weighted average fair value of awards granted $ |
Schedule of outstanding unvested restricted stock awards vesting schedule | Number of Weighted Aggregate Total awarded and unvested—December 31, 2015 $ $ Granted $ Vested $ Forfeited $ Total awarded and unvested—December 31, 2016 $ $ |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Schedule of outstanding commodity derivatives | Natural gas Oil Natural Gas Weighted Three months ending March 31, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending June 30, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending September 30, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Three months ending December 31, 2017: NYMEX ($/MMBtu) — — $ CGTLA ($/MMBtu) — — $ CCG ($/MMBtu) — — $ NYMEX-WTI ($/Bbl) — — $ Mont Belvieu-Ethane ($/Gallon) — — $ Mont Belvieu-Propane ($/Gallon) — — $ Total Year ending December 31, 2018: NYMEX ($/MMBtu) — $ Mont Belvieu-Propane ($/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, 2015 December 31, 2016 Balance sheet Fair value Balance sheet Fair value (In thousands) (In thousands) Asset derivatives not designated as hedges for accounting purposes: Commodity contracts Current assets $ Current assets Commodity contracts Long-term assets Long-term assets Total asset derivatives Liability derivatives not designated as hedges for accounting purposes: Commodity contracts Current liabilities — Current liabilities Commodity contracts Long-term liabilities — Long-term liabilities 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, 2015 December 31, 2016 Gross Gross amounts Net amounts Gross Gross amounts Net amounts of assets (liabilities) 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 (losses) and where such values are recorded in the consolidated statements of operations for the years ended December 31, 2014, 2015, and 2016 (in thousands): Statement of Year ended December 31, location 2014 2015 2016 Commodity derivative fair value gains (losses) 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 Hedged Year ending December 31, 2017: $ |
NYMEXminusTCO | |
Tabular disclosure of pertinent information about 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 Hedged Year ending December 31, 2017: $ |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes | |
Schedule of income tax expense from continuing operations | For the years ended December 31, 2014, 2015, and 2016, income tax expense (benefit) from continuing operations consisted of the following (in thousands): Year ended December 31, 2014 2015 2016 Current income tax benefit $ — — Deferred income tax expense (benefit) Total income tax expense (benefit) from continuing operations $ |
Schedule of reconciliation of income tax expense from continuing operations | Income tax expense (benefit) 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, 2014, 2015, and 2016 as a result of the following (in thousands): Year ended December 31, 2014 2015 2016 Federal income tax expense (benefit) $ State income tax expense (benefit), 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, 2014, 2015, and 2016, income tax expense (benefit) was allocated to continuing and discontinued operations as follows (in thousands): Year ended December 31, 2014 2015 2016 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, 2015 and 2016 is as follows (in thousands): 2015 2016 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 Other — Total deferred tax liabilities Net deferred tax liabilities $ |
Schedule of reconciliation of beginning and ending amount of unrecognized tax benefits | 2014 2015 2016 Balance at beginning of year $ Reductions for tax positions of prior years — — Balance at end of year $ — |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments | |
Schedule of future minimum payments for firm transportation, drilling rig and completion services, gas processing, gathering and compression, office and equipment agreements, and leases that have remaining lease terms in excess of one year | The following is a schedule of future minimum payments for firm transportation, drilling rig and completion services, processing, gathering and compression, and office and equipment agreements, as well as leases that have remaining lease terms in excess of one year as of December 31, 2016 (in millions). Firm Processing, Drilling rigs and completion Office and equipment (a) (b) (c) (d) Total 2017 $ 2018 2019 2020 — 2021 — Thereafter — Total $ |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2014, 2015, and 2016 (in thousands): Exploration Gathering and processing Water handling and treatment Marketing Elimination of Consolidated 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 Gathering and processing Water handling and treatment Marketing Elimination of Consolidated 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 $ — Exploration Gathering and processing Water handling and treatment Marketing Elimination of Consolidated Year ended December 31, 2016: 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, 2016 | |
Subsidiary Guarantors | |
Schedule of condensed consolidated balance sheets | Condensed Consolidating Balance Sheet December 31, 2015 (In thousands) Parent Guarantor Non-Guarantor 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 Balance Sheet December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor 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 — — — Derivative instruments — — — Other current liabilities — — Total current liabilities — Long-term liabilities: Long-term debt — — Deferred income tax liability — — — Contingent acquisition consideration — — — Derivative instruments — — — 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 Non-Guarantor Eliminations Consolidated Revenue and other: 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 assets — — — Other income — — — Total revenue and other — 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 expenses: Interest — — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income from continuing operations before income taxes and discontinued operations — 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 Non-Guarantor Eliminations Consolidated Revenue and other: 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 and other — 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 Operations and Comprehensive Income (Loss) Year Ended December 31, 2016 (In thousands) Parent Guarantor Non-Guarantor Eliminations Consolidated Revenue and other: Natural gas sales $ — — — Natural gas liquids sales — — — Oil sales — — — Gathering, compression, and water handling and treatment — — Marketing — — — Commodity derivative fair value losses — — — Gain on sale of assets — — Other income — — — Total revenue and other — 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 — Accretion of contingent acquisition consideration — — — Total operating expenses — Operating income (loss) — Other income (expenses): Equity in earnings of unconsolidated affiliate — — — Interest — Loss on early extinguishment of debt — — — Equity in net income of subsidiaries — — — Total other expenses — Income (loss) before income taxes — Provision for income tax benefit — — — Net income (loss) and comprehensive income (loss) including noncontrolling interest — Net income and comprehensive income attributable to noncontrolling interest — — — Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $ — |
Condensed Cash Flow Statement [Table Text Block] | Condensed Consolidating Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Parent Guarantor Non-Guarantor 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 by 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 — — Employee tax withholding for settlement of equity compensation awards — — — Other — — — Net cash provided by (used in) financing activities — Net 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 Non-Guarantor 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 to 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 by Antero Midstream Partners LP — — — Issuance of senior notes — — — Borrowings (repayments) on bank credit facility, net — Payments of deferred financing costs — — Distributions — Employee tax withholding for settlement of equity compensation awards — — Other — — Net cash provided by (used in) financing activities — Net 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, 2016 (In thousands) Parent Guarantor Non-Guarantor 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 — — — Investments in unconsolidated affiliates — — — Change in other assets — — Net distributions from subsidiaries — — — Proceeds from asset sales — — Net cash used in investing activities — Cash flows provided by financing activities: Issuance of common stock — — — Issuance of common units by Antero Midstream Partners LP — — — Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation — — — Issuance of senior notes — — Repayment of senior notes — — — Repayments on bank credit facility, net — — Make-whole premium on debt extinguished — — — Payments of deferred financing costs — — Distributions — — Employee tax withholding for settlement of equity compensation awards — — Other — — Net cash provided by 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 Informati39
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information (Unaudited) | |
Schedule of quarterly financial information | The Company’s quarterly consolidated financial information for the years ended December 31, 2015 and 2016 is summarized in the following tables (in thousands, except per share amounts). The Company’s quarterly operating results are affected by the volatility of commodity prices and the resulting effect on our production revenues and the fair value of commodity derivatives. First Second Third Fourth Year Ended December 31, 2015: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) 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—basic $ $ $ $ Earnings (loss) per common share—assuming dilution $ $ $ $ First Second Third Fourth Year Ended December 31, 2016: Total operating revenues $ $ $ $ Total operating expenses Operating income (loss) 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 O40
Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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) 2015 2016 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) 2014 2015 2016 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) 2014 2015 2016 Revenues $ Operating expenses: Production expenses Exploration expenses Depletion and depreciation Impairment of unproved properties Results of operations before income tax expense Income tax (expense) benefit Results of operations $ |
Schedule of proved developed and undeveloped reserves | Natural NGLs Oil and Equivalents Proved reserves: December 31, 2013 Revisions — (a) Extensions, discoveries and other additions Purchases of reserves — — Production December 31, 2014 Revisions Extensions, discoveries and other additions Production December 31, 2015 Revisions Extensions, discoveries and other additions Production Purchases of reserves Sales of reserves in place — — December 31, 2016 (a) Less than 1.0. Natural NGLs Oil and Equivalents Proved developed reserves: December 31, 2014 December 31, 2015 December 31, 2016 Proved undeveloped reserves: December 31, 2014 December 31, 2015 December 31, 2016 |
Schedule of standardized measure of discounted future net cash flows attributable to proved reserves | Year ended December 31, (in millions) 2014 2015 2016 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, 2014 $ December 31, 2015 $ December 31, 2016 $ |
Schedule of changes in standardized measure of discounted future net cash flow | Year ended December 31, (in millions) 2014 2015 2016 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 — Divestitures — — 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 Accoun41
Summary of Significant Accounting Policies - Fair Value of Derivative Contracts (Details) $ in Thousands | Feb. 06, 2017shares | Dec. 31, 2016USD ($)segment | Dec. 31, 2015USD ($) |
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | $ 1,600,000 | ||
Industry Segment and Geographic Information | |||
Number of operating segments | segment | 4 | ||
Basis of Presentation | |||
Proceeds from issuance of stock | $ 1,012,431 | $ 537,832 | |
Morgan Stanley | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 551,000 | ||
Barclays | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 392,000 | ||
JP Morgan | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 306,000 | ||
Wells Fargo | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 159,000 | ||
Scotiabank | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 136,000 | ||
Toronto Dominion Bank | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 32,000 | ||
Canadian Imperial Bank of Commerce | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 58,000 | ||
Fifth Third Bank | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 12,000 | ||
Bank of Montreal | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 10,000 | ||
Capital One | |||
Derivative Financial Instruments | |||
Fair value of commodity derivative contracts | 2,000 | ||
Antero Resources LLC | Bank credit facility | |||
Basis of Presentation | |||
Current borrowing base | $ 4,750,000 | ||
Antero Midstream Partners LP | Subsequent event | |||
Basis of Presentation | |||
Sale of common stock (in shares) | shares | 6,900,000 |
Summary of Significant Accoun42
Summary of Significant Accounting Policies - EPS and New Accounting Principle (Details) - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Earnings per share | |||
Weighted Average Number of Shares Outstanding, Basic | 294,945 | 274,123 | 262,054 |
Weighted Average Number of Shares Outstanding, Diluted | 294,945 | 274,143 | 262,068 |
Other Assets, Noncurrent | $ 95,153 | $ 26,565 | |
Long-term debt | 4,703,973 | 4,668,782 | |
Changes in accrued liabilities | 18,853 | 36,377 | $ 95,066 |
Employee tax withholding for settlement of equity compensation awards | $ (26,895) | (9,431) | $ (142) |
As Previously Reported | |||
Earnings per share | |||
Changes in accrued liabilities | 26,946 | ||
Adjustment Effect | |||
Earnings per share | |||
Changes in accrued liabilities | 9,431 | ||
Employee tax withholding for settlement of equity compensation awards | $ (9,431) | ||
Restricted stock and restricted stock unit [Member] | |||
Earnings per share | |||
Dilutive effect of equity awards (in shares) | 20 | 14 | |
Weighted Average Anti-dilutive Awards | 6,740 | 2,264 | 1,444 |
Stock options | |||
Earnings per share | |||
Weighted Average Anti-dilutive Awards | 702 | 553 | 73 |
Performance share unit awards | |||
Earnings per share | |||
Weighted Average Anti-dilutive Awards | 659 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies - Property and equipment (Details) | 12 Months Ended | 24 Months Ended | 36 Months Ended | ||
Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2016USD ($)item | |
Property and Equipment | |||||
Depreciation expense | $ 809,873,000 | $ 709,763,000 | $ 477,896,000 | ||
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 | 163,000,000 | 104,000,000 | 15,000,000 | ||
Impairment of proved properties | $ 0 | $ 0 | |||
Depreciation, depletion, and amortization expense for oil and gas properties | $ 700,000,000 | 615,000,000 | 419,000,000 | ||
Impairment of long-lived assets other than oil and gas properties | $ 0 | ||||
Time period that payment is generally received after sale has occurred | 1 month | ||||
Number of imbalance positions | item | 0 | 0 | |||
Deferred Financing Costs | |||||
Unamortized deferred financing costs included in long-term debt | $ 48,000,000 | $ 48,000,000 | |||
Unamortized deferred financing costs included in other assets | 14,000,000 | $ 14,000,000 | |||
Amounts amortized and the write-off of previously deferred debt issuance costs | $ 16,000,000 | 10,000,000 | 11,000,000 | ||
Gathering Systems and Facilities | |||||
Property and Equipment | |||||
Estimated useful life | P20Y | ||||
Other property and equipment | |||||
Property and Equipment | |||||
Depreciation expense | $ 8,900,000 | 7,700,000 | 5,900,000 | ||
Other property and equipment | Minimum | |||||
Property and Equipment | |||||
Estimated useful life | P2Y | ||||
Other property and equipment | Maximum | |||||
Property and Equipment | |||||
Estimated useful life | P20Y | ||||
Gathering pipelines, compressor stations, and fresh water distribution systems | |||||
Property and Equipment | |||||
Depreciation expense | $ 101,000,000 | $ 87,000,000 | $ 53,000,000 | ||
Fresh Water Distribution | Minimum | |||||
Property and Equipment | |||||
Estimated useful life | P5Y | ||||
Fresh Water Distribution | Maximum | |||||
Property and Equipment | |||||
Estimated useful life | P20Y |
Summary of Significant Accoun44
Summary of Significant Accounting Policies - Credit Risk (Details) - Sales - Customer concentration | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
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) | 29.00% | 19.00% | 5.00% |
Company B | |||
Concentrations of Credit Risk | |||
Sales to major customers (as a percent) | 13.00% | ||
Company C | |||
Concentrations of Credit Risk | |||
Sales to major customers (as a percent) | 3.00% | 13.00% | 16.00% |
Company D | |||
Concentrations of Credit Risk | |||
Sales to major customers (as a percent) | 2.00% | 18.00% | 29.00% |
Company E | |||
Concentrations of Credit Risk | |||
Sales to major customers (as a percent) | 1.00% | 9.00% | 12.00% |
All others | |||
Concentrations of Credit Risk | |||
Sales to major customers (as a percent) | 52.00% | 41.00% | 38.00% |
Antero Midstream Partners LP (D
Antero Midstream Partners LP (Details) $ in Thousands | May 26, 2016USD ($) | Mar. 30, 2016USD ($)shares | Sep. 23, 2015USD ($)sharesbbl | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Antero Midstream Partners LP | ||||||
Investment in unconsolidated affiliate | $ 75,516 | |||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Amount borrowed on bank credit facility | (677,000) | $ (403,000) | $ 1,442,000 | |||
Equity Transactions | ||||||
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | $ 178,000 | |||||
Antero Resources LLC | ||||||
Antero Midstream Partners LP | ||||||
Antero Resources ownership in Antero Midstream | 60.90% | 66.30% | ||||
Equity Transactions | ||||||
Number of Antero Midstream common units sold to the public by Antero Resources (in units) | shares | 8,000,000 | |||||
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | $ 178,000 | |||||
Antero Midstream Partners LP | ||||||
Antero Midstream Partners LP | ||||||
Ownership percentage | 15.00% | |||||
Investment in unconsolidated affiliate | $ 45,000 | |||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Cash distribution | $ 552,000 | |||||
Assumed debt | $ 171,000 | |||||
Common units issued | shares | 10,988,421 | |||||
Antero Midstream Partners LP | Contingent Consideration Period One | ||||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Contingent consideration | $ 125,000 | |||||
Threshold number of barrels of water to trigger contingent consideration payment | bbl | 176,295,000 | |||||
Antero Midstream Partners LP | Contingent Consideration Period Two | ||||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Contingent consideration | $ 125,000 | |||||
Threshold number of barrels of water to trigger contingent consideration payment | bbl | 219,200,000 | |||||
Antero Midstream Partners LP | Private Placement | ||||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Proceeds from issuance of common units | $ 241,000 | |||||
Equity Transactions | ||||||
Proceeds from Issuance of Common Limited Partners Units | $ 241,000 | |||||
Antero Midstream Partners LP | At the Market Program | ||||||
Sale of Antero Water LLC to Antero Midstream Partners LP | ||||||
Proceeds from issuance of common units | $ 65,400 | |||||
Equity Transactions | ||||||
Units sold under At the Market program (in units) | shares | 2,391,595 | |||||
Proceeds from Issuance of Common Limited Partners Units | $ 65,400 | |||||
Aggregate dollar amount of common units available for issuance and sale under equity distribution agreement | 250,000 | |||||
Remaining capacity under equity distribution agreement | $ 183,800 |
Sale of Piceance and Arkoma P46
Sale of Piceance and Arkoma Properties - Discontinued Operations (Detail) $ in Thousands | 12 Months Ended |
Dec. 31, 2014USD ($) | |
Discontinued Operations: | |
Gain on sale of discontinued operations | $ (3,564) |
Sales of Assets (Details)
Sales of Assets (Details) a in Thousands | Dec. 16, 2016USD ($)a | Mar. 31, 2012 | Mar. 26, 2012USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||||
Proceeds from asset sales | $ 171,830,000 | $ 40,000,000 | ||||
Gain on sale of assets | $ 97,635,000 | $ 40,000,000 | ||||
Pennsylvania Leasehold Acreage | ||||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||||
Proceeds from asset sales | $ 169,800,000 | |||||
Gain on sale of assets | $ 99,000,000 | |||||
Area of land sold | a | 17 | |||||
Appalachian Gathering Assets | ||||||
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||||||
Proceeds from asset sales | $ 375,000,000 | 40,000,000 | ||||
Gain on sale of assets | $ 40,000,000 | |||||
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 |
Accrued Liabilities (Details)
Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accrued capital expenditures | $ 159,811 | $ 271,542 |
Accrued gathering, compression, processing, and transportation expenses | 75,223 | 59,962 |
Accrued marketing expenses | 52,822 | 38,136 |
Accrued interest expense | 35,533 | 26,391 |
Other accrued liabilities | 70,414 | 92,294 |
Total accrued liabilities | $ 393,803 | $ 488,325 |
Long-Term Debt (Details)
Long-Term Debt (Details) - USD ($) $ in Thousands | Dec. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2014 | Dec. 21, 2016 | Sep. 13, 2016 | Dec. 31, 2015 | Sep. 23, 2015 | Mar. 17, 2015 | Sep. 18, 2014 | May 06, 2014 | Nov. 05, 2013 |
Long- term Debt | |||||||||||
Long-term debt | $ 4,703,973 | $ 4,668,782 | |||||||||
Loss on Early Extinguishment of Debt | (16,956) | $ (20,386) | |||||||||
Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Net unamortized premium | 1,749 | 6,513 | |||||||||
Net unamortized debt issuance costs | (37,690) | (39,731) | |||||||||
Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Net unamortized debt issuance costs | (10,086) | ||||||||||
Outstanding balance | $ 525,000 | ||||||||||
Midstream Credit Facility Member | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Bank credit facility long-term debt | 210,000 | 620,000 | |||||||||
Maximum amount of the Credit Facility | $ 1,500,000 | ||||||||||
Weighted average interest rate (as a percent) | 2.23% | ||||||||||
Midstream Credit Facility Member | Minimum | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Commitment fees on the unused portion (as a percent) | 0.25% | ||||||||||
Midstream Credit Facility Member | Maximum | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Commitment fees on the unused portion (as a percent) | 0.375% | ||||||||||
Bank credit facility | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Bank credit facility long-term debt | $ 440,000 | $ 707,000 | |||||||||
Current borrowing base | 4,750,000 | ||||||||||
Lender commitments | $ 4,000,000 | ||||||||||
Weighted average interest rate (as a percent) | 2.44% | 2.32% | |||||||||
Outstanding letters of credit | $ 710,000 | $ 702,000 | |||||||||
Bank credit facility | Minimum | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Commitment fees on the unused portion (as a percent) | 0.375% | ||||||||||
Bank credit facility | Maximum | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Commitment fees on the unused portion (as a percent) | 0.50% | ||||||||||
6.00% senior notes due 2020 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 525,000 | 525,000 | |||||||||
Interest rate (as a percent) | 6.00% | ||||||||||
Loss on Early Extinguishment of Debt | $ 17,000 | ||||||||||
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed | 103.00% | ||||||||||
5.375% senior notes due 2021 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 1,000,000 | 1,000,000 | |||||||||
Interest rate (as a percent) | 5.375% | ||||||||||
Senior notes issued | $ 1,000,000 | ||||||||||
Issue price as percentage of par value | 100.00% | ||||||||||
Redemption price 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 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 104.031% | ||||||||||
5.375% senior notes due 2021 | On or after November 1, 2019 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
Stand-alone revolving note | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Maximum amount of the Credit Facility | $ 25,000 | ||||||||||
Outstanding balance | $ 0 | 0 | |||||||||
Stand-alone revolving note | Lender's Prime Rate | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Basis spread on variable rate (as a percent) | 1.00% | ||||||||||
5.125 senior notes due 2022 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 1,100,000 | 1,100,000 | |||||||||
Interest rate (as a percent) | 5.125% | ||||||||||
Senior notes issued | $ 500,000 | $ 600,000 | |||||||||
Issue price as percentage of par value | 100.50% | 100.00% | |||||||||
Redemption price 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 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 103.844% | ||||||||||
5.125 senior notes due 2022 | On or before June 1, 2017 | Antero Resources LLC | |||||||||||
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 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
5.125 senior notes due 2022 | On or after June 1, 2020 | Antero Resources LLC | |||||||||||
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 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 750,000 | $ 750,000 | |||||||||
Interest rate (as a percent) | 5.625% | ||||||||||
Senior notes issued | $ 750,000 | ||||||||||
Issue price as percentage of par value | 100.00% | ||||||||||
Redemption price at which notes may be required to be repurchased in event of change of control | 101.00% | ||||||||||
5.625% senior notes due 2023 | On Or Before June 1, 2018 | Antero Resources LLC | |||||||||||
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 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 104.219% | ||||||||||
5.625% senior notes due 2023 | On Or After June 1, 2021 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
5.625% senior notes due 2023 | Prior to June 1, 2018 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
5.375% senior notes due 2024 | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 650,000 | ||||||||||
Senior notes issued | $ 650,000 | ||||||||||
Issue price as percentage of par value | 5.375% | ||||||||||
Redemption price at which notes may be required to be repurchased in event of change of control | 101.00% | ||||||||||
5.375% senior notes due 2024 | On or after September 15, 2019 | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 104.031% | ||||||||||
5.375% senior notes due 2024 | On or after September 15, 2022 | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
5.375% senior notes due 2024 | Prior to September 15, 2019 | Antero Midstream Partners LP | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings | 35.00% | ||||||||||
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent) | 105.375% | ||||||||||
5.00% senior notes due 2025 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Long-term notes payable | $ 600,000 | ||||||||||
Interest rate (as a percent) | 5.00% | ||||||||||
Senior notes issued | $ 600,000 | ||||||||||
Issue price as percentage of par value | 100.00% | ||||||||||
Redemption price at which notes may be required to be repurchased in event of change of control | 101.00% | ||||||||||
5.00% senior notes due 2025 | Prior to March 1, 2020 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% | ||||||||||
5.00% senior notes due 2025 | On or before March 1, 2020 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Percentage of the principal amount of the debt instrument which the entity may redeem with the proceeds from certain equity offerings | 35.00% | ||||||||||
Redemption price of the debt instrument if redeemed with the proceeds of certain equity offerings (as a percent) | 105.00% | ||||||||||
5.00% senior notes due 2025 | On or after March 1, 2020 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 103.75% | ||||||||||
5.00% senior notes due 2025 | On or after March1, 2023 | Antero Resources LLC | |||||||||||
Long- term Debt | |||||||||||
Redemption price | 100.00% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligations | |||
Asset retirement obligations - beginning of period | $ 30,612 | $ 16,614 | |
Obligations incurred for wells drilled | 4,487 | 9,213 | |
Revisions to prior estimates | (4,836) | 3,130 | |
Accretion expense | 2,473 | 1,655 | $ 1,271 |
Asset retirement obligations - end of period | $ 32,736 | $ 30,612 | $ 16,614 |
Equity-Based Compensation (Deta
Equity-Based Compensation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stock-based compensation expense | |||
Number of stock-based compensation awards authorized | 16,906,500 | ||
Number of shares available for future grant under the Plan | 8,449,452 | ||
Equity based compensation expense recognized | $ 102,421 | $ 97,877 | $ 112,252 |
Midstream Plan | |||
Stock-based compensation expense | |||
Number of stock-based compensation awards authorized | 10,000,000 | ||
Number of shares available for future grant under the Plan | 7,937,930 | ||
Profits interests awards | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | 37,620 | 83,615 | |
Restricted stock awards | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | $ 73,081 | 40,663 | 25,624 |
Performance share unit awards | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | 8,685 | ||
Stock options | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | 2,578 | 2,155 | 501 |
Antero Midstream Partners Phantom Unit Awards | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | 16,095 | 17,126 | 2,360 |
Equity awards issued to directors | |||
Stock-based compensation expense | |||
Equity based compensation expense recognized | $ 1,982 | $ 313 | $ 152 |
Equity-Based Compensation - Res
Equity-Based Compensation - Restricted Stock and RSU Awards (Details) - Restricted stock awards $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($)$ / sharesshares | |
Number of shares | |
Total granted and unvested at the beginning of the period (in shares) | shares | 6,529,459 |
Granted (in shares) | shares | 1,241,710 |
Vested (in shares) | shares | (2,123,282) |
Forfeited (in shares) | shares | (294,440) |
Total awarded and unvested at the end of the period (in shares) | shares | 5,353,447 |
Weighted average grant date fair value | |
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares | $ 33.48 |
Granted (in dollars per share) | $ / shares | 27.06 |
Vested (in dollars per share) | $ / shares | 34.95 |
Forfeited (in dollars per share) | $ / shares | 26.89 |
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares | $ 31.77 |
Aggregate intrinsic value | |
Total awarded and unvested at the beginning of the period | $ | $ 142,342 |
Total awarded and unvested at the end of the period | $ | 126,609 |
Additional equity compensation to be recognized over the remaining period | $ | $ 130,200 |
Weighted average period for recognizing unrecognized stock-based compensation expense | 2 years |
Equity-Based Compensation - Sto
Equity-Based Compensation - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stock options | |||
Outstanding at the beginning of the period (in shares) | 720,887 | ||
Options forfeited (in shares) | (32,958) | ||
Outstanding at the end of the period (in shares) | 687,929 | 720,887 | |
Vested or expected to vest (in shares) | 687,929 | ||
Exercisable (in shares) | 217,882 | ||
Weighted average exercise price | |||
Outstanding at the beginning of the period (in dollars per share) | $ 50.44 | ||
Options forfeited (in dollars per share) | 50 | ||
Outstanding at the end of the period (in dollars per share) | 50.46 | $ 50.44 | |
Vested or expected to vest (in dollars per share) | 50.46 | ||
Exercisable (in dollars per share) | $ 51.17 | ||
Weighted average remaining contractual life | |||
Outstanding | 8 years 1 month 13 days | 9 years 1 month 21 days | |
Vested or expected to vest | 8 years 1 month 13 days | ||
Exercisable | 7 years 10 months 13 days | ||
Weighted-average assumptions used to calculate fair value of stock options granted | |||
Dividend yield (as a percent) | 0.00% | ||
Volatility (as a percent) | 40.00% | 40.00% | |
Risk-free interest rate (as a percent) | 1.66% | 1.75% | |
Expected life | 6 years 3 months | 5 years 6 months | |
Weighted average fair value of options granted (in dollars per share) | $ 14.74 | $ 20.55 | |
Additional disclosures | |||
Unrecognized stock-based compensation expense | $ 5.4 | ||
Weighted average period for recognizing unrecognized stock-based compensation expense | 2 years 2 months 12 days | ||
Minimum | |||
Stock-based compensation | |||
Vesting period | 1 year | ||
Maximum | |||
Stock-based compensation | |||
Vesting period | 4 years | ||
Contractual life | 10 years |
Equity-Based Compensation - PSU
Equity-Based Compensation - PSU awards (Details) $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($)$ / sharesshares | |
Performance share unit awards | |
Number of units | |
Granted (in shares) | shares | 790,890 |
Forfeited (in shares) | shares | (5,589) |
Total awarded and unvested at the end of the period (in shares) | shares | 785,301 |
Weighted average grant date fair value | |
Granted (in dollars per share) | $ 29.77 |
Forfeited (in dollars per share) | 32.97 |
Total awarded and unvested at the end of the period (in dollars per share) | $ 29.75 |
Additional disclosures | |
Additional equity compensation to be recognized over the remaining period | $ | $ 14.7 |
Weighted average period for recognizing unrecognized stock-based compensation expense | 2 years 1 month 6 days |
Weighted-average assumptions used to calculate fair value of performance share units granted | |
Dividend yield (as a percent) | 0.00% |
Volatility (as a percent) | 45.00% |
Risk-free interest rate (as a percent) | 1.01% |
Weighted average fair value of awards granted (in dollars per share) | $ 29.77 |
Price target performance share unit awards | |
Number of successive days closing stock price must achieve specific thresholds for PSUs to vest per schedule | 10 days |
Vesting period | 3 years |
Price target performance share unit awards | Vesting before first anniversary | Maximum | |
Number of PSUs that may vest, as a percent | 0.00% |
Price target performance share unit awards | Vesting before the second anniversary | Maximum | |
Number of PSUs that may vest, as a percent | 33.33% |
Price target performance share unit awards | Vesting before the third anniversary | Maximum | |
Number of PSUs that may vest, as a percent | 66.66% |
TSR performance share unit awards | |
Vesting period | 3 years |
TSR performance share unit awards | Maximum | |
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent | 200.00% |
TSR performance share unit awards | Minimum | |
Number of PSUs that may be earned as compared to the number of PSUs granted, as a percent | 0.00% |
Equity-Based Compensation - Pha
Equity-Based Compensation - Phantom Unit Awards (Details) - Antero Midstream Partners Phantom Unit Awards $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($)$ / sharesshares | |
Number of units | |
Total granted and unvested at the beginning of the period (in shares) | shares | 1,667,832 |
Granted (in shares) | shares | 297,356 |
Vested (in shares) | shares | (524,659) |
Forfeited (in shares) | shares | (108,568) |
Total awarded and unvested at the end of the period (in shares) | shares | 1,331,961 |
Weighted average grant date fair value | |
Total granted and unvested at the beginning of the period (in dollars per share) | $ / shares | $ 28.97 |
Granted (in dollars per share) | $ / shares | 21.41 |
Vested (in dollars per share) | $ / shares | 28.95 |
Forfeited (in dollars per share) | $ / shares | 28.66 |
Total awarded and unvested at the end of the period (in dollars per share) | $ / shares | $ 27.31 |
Aggregate intrinsic value | |
Outstanding at the beginning of the period | $ | $ 38,060 |
Outstanding at the end of the period | $ | 41,131 |
Additional equity compensation to be recognized over the remaining period | $ | $ 33,200 |
Weighted average period for recognizing unrecognized stock-based compensation expense | 2 years 1 month 6 days |
Financial Instruments (Details)
Financial Instruments (Details) - Recurring - Level 2 market data - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Financial Instruments | ||
Fair value of senior notes | $ 3,500 | $ 2,600 |
Antero Midstream Partners LP | ||
Financial Instruments | ||
Fair value of senior notes | $ 657 |
Derivative Instruments - Commod
Derivative Instruments - Commodity derivatives (Details) | Dec. 31, 2016bbl / dMMBTU / d$ / bbl$ / gal$ / MMBTU |
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) |
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, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,860,000 |
Swaps | Natural gas | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,860,000 |
Swaps | Natural gas | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,860,000 |
Swaps | Natural gas | Three months 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 | NYMEX | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,370,000 |
Weighted average index price | $ / MMBTU | 3.52 |
Swaps | Natural gas | NYMEX | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,370,000 |
Weighted average index price | $ / MMBTU | 3.26 |
Swaps | Natural gas | NYMEX | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,370,000 |
Weighted average index price | $ / MMBTU | 3.33 |
Swaps | Natural gas | NYMEX | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,370,000 |
Weighted average index price | $ / MMBTU | 3.46 |
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) | 2,330,000 |
Weighted average index price | $ / MMBTU | 3.70 |
Swaps | Natural gas | NYMEX | Year ending December 31, 2020 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 1,367,500 |
Weighted average index price | $ / MMBTU | 3.66 |
Swaps | Natural gas | NYMEX | Year Ending December 31, 2021 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 660,000 |
Weighted average index price | $ / MMBTU | 3.35 |
Swaps | Natural gas | NYMEX | Year ending December 31, 2022 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 760,000 |
Weighted average index price | $ / MMBTU | 3.20 |
Swaps | Natural gas | CGTLA | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 420,000 |
Weighted average index price | $ / MMBTU | 4.39 |
Swaps | Natural gas | CGTLA | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 420,000 |
Weighted average index price | $ / MMBTU | 4.13 |
Swaps | Natural gas | CGTLA | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 420,000 |
Weighted average index price | $ / MMBTU | 4.20 |
Swaps | Natural gas | CGTLA | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 420,000 |
Weighted average index price | $ / MMBTU | 4.37 |
Swaps | Natural gas | CCG | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 70,000 |
Weighted average index price | $ / MMBTU | 4.76 |
Swaps | Natural gas | CCG | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 70,000 |
Weighted average index price | $ / MMBTU | 4.38 |
Swaps | Natural gas | CCG | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 70,000 |
Weighted average index price | $ / MMBTU | 4.45 |
Swaps | Natural gas | CCG | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | 70,000 |
Weighted average index price | $ / MMBTU | 4.68 |
Swaps | Natural gas liquids | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 47,500 |
Swaps | Natural gas liquids | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 47,500 |
Swaps | Natural gas liquids | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 47,500 |
Swaps | Natural gas liquids | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 47,500 |
Swaps | Natural gas liquids | Year ending December 31, 2018 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 2,000 |
Swaps | Ethane | Mont Belvieu-Ethane | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 20,000 |
Weighted average index price | $ / gal | 0.25 |
Swaps | Ethane | Mont Belvieu-Ethane | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 20,000 |
Weighted average index price | $ / gal | 0.25 |
Swaps | Ethane | Mont Belvieu-Ethane | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 20,000 |
Weighted average index price | $ / gal | 0.25 |
Swaps | Ethane | Mont Belvieu-Ethane | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 20,000 |
Weighted average index price | $ / gal | 0.25 |
Swaps | Propane | Mont Belvieu-Propane | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 27,500 |
Weighted average index price | $ / gal | 0.40 |
Swaps | Propane | Mont Belvieu-Propane | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 27,500 |
Weighted average index price | $ / gal | 0.38 |
Swaps | Propane | Mont Belvieu-Propane | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 27,500 |
Weighted average index price | $ / gal | 0.39 |
Swaps | Propane | Mont Belvieu-Propane | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 27,500 |
Weighted average index price | $ / gal | 0.40 |
Swaps | Propane | Mont Belvieu-Propane | Year ending December 31, 2018 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 2,000 |
Weighted average index price | $ / gal | 0.65 |
Swaps | Oil | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Swaps | Oil | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Swaps | Oil | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Swaps | Oil | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Swaps | Oil | WTI-NYMEX member | Three months ending March 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Weighted average index price | $ / bbl | 54.75 |
Swaps | Oil | WTI-NYMEX member | Three months ending June 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Weighted average index price | $ / bbl | 54.75 |
Swaps | Oil | WTI-NYMEX member | Three months ending September 30, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Weighted average index price | $ / bbl | 54.75 |
Swaps | Oil | WTI-NYMEX member | Three months ending December 31, 2017 | |
Derivative Instruments | |
Notional amount (MMBtu/Bbls per day) | bbl / d | 3,000 |
Weighted average index price | $ / bbl | 54.75 |
Derivative Instruments - Fair v
Derivative Instruments - Fair value (Details) $ in Thousands | Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($) |
Fair value of derivative instruments | ||
Current portion of fair value of derivative assets | $ 73,022 | $ 1,009,030 |
Noncurrent portion of fair value of derivative assets | 1,731,063 | 2,108,450 |
Total asset derivatives | 1,804,085 | 3,117,480 |
Current portion of fair value of derivative liabilities | 203,635 | |
Noncurrent portion of fair value of derivative liabilities | 234 | |
Total liability derivatives | 203,869 | |
Net derivatives | $ 1,600,216 | $ 3,117,480 |
Derivatives designated as hedges for accounting purposes | ||
Fair value of derivative instruments | ||
Number of derivative instruments held designated as hedges | item | 0 |
Derivative Instruments - Assets
Derivative Instruments - Assets and liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Commodity derivative assets | ||
Gross amounts on balance sheet | $ 1,914,245 | $ 3,163,639 |
Gross amounts offset on balance sheet | (110,160) | (46,159) |
Total asset derivatives | 1,804,085 | $ 3,117,480 |
Commodity derivative liabilities | ||
Gross amounts on balance sheet | (324,667) | |
Gross amounts offset on balance sheet | 120,798 | |
Total liability derivatives | $ (203,869) |
Derivative Instruments - Fair60
Derivative Instruments - Fair value gains (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary of realized and unrealized gains (losses) on derivative instruments | |||
Commodity derivative fair value gains (losses) | $ (514,181) | $ 2,381,501 | $ 868,201 |
Revenue | |||
Summary of realized and unrealized gains (losses) on derivative instruments | |||
Commodity derivative fair value gains (losses) | $ (514,181) | $ 2,381,501 | $ 868,201 |
Contract Termination and Rig 61
Contract Termination and Rig Stacking (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Contract Termination and Rig Stacking Line Items | ||
Contract termination and rig stacking | $ 38,500 | $ 38,531 |
Income Taxes (Detail)
Income Taxes (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income tax expense from continuing operations | |||
Current income tax expense (benefit) | $ (10,984) | ||
Deferred income tax expense (benefit) | (485,392) | $ 575,890 | $ 445,672 |
Total income tax expense from continuing operations | $ (496,376) | $ 575,890 | $ 445,672 |
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 | $ (436,038) | $ 544,560 | $ 391,754 |
State income tax expense , net of federal benefit | (20,364) | 26,983 | 25,545 |
Nondeductible stock compensation | 3,691 | 16,441 | 29,141 |
Noncontrolling interest in Antero Midstream Partners LP | (34,780) | (13,521) | (787) |
Change in valuation allowance | (10,852) | 570 | (120) |
Other | 1,967 | 857 | 139 |
Total income tax expense from continuing operations | (496,376) | 575,890 | 445,672 |
Income tax expense (benefit) allocated to continuing and discontinued operations | |||
Total income tax expense from continuing operations | (496,376) | 575,890 | 445,672 |
Discontinued operations and sale of discontinued operations | 1,354 | ||
Total income tax expense (benefit) | (496,376) | 575,890 | $ 447,026 |
Deferred tax assets: | |||
Net operating loss carryforwards | 562,355 | 521,617 | |
Minimum tax credit carryforward | 11,000 | ||
Equity based compensation | 20,344 | 16,130 | |
Other | 16,483 | 18,633 | |
Total deferred tax assets | 599,182 | 567,380 | |
Valuation allowance | (16,357) | (27,209) | |
Net deferred tax assets | 582,825 | 540,171 | |
Deferred tax liabilities: | |||
Unrealized gains on derivative instruments | 605,487 | 1,167,983 | |
Oil and gas properties | 866,003 | 708,664 | |
Investment in Antero Midstream Partners LP | 54,052 | 34,210 | |
Other | 7,500 | ||
Total deferred tax liabilities | 1,533,042 | 1,910,857 | |
Net deferred tax liabilities | $ (950,217) | $ (1,370,686) |
Income Taxes - Unrecognized tax
Income Taxes - Unrecognized tax benefits (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Unrecognized tax benefits | |||
Balance at beginning of year | $ 11,000 | $ 11,000 | $ 11,000 |
Reductions for tax positions of prior years | (11,000) | 0 | 0 |
Balance at end of year | 0 | $ 11,000 | $ 11,000 |
U.S Federal | |||
Income Taxes | |||
Net operating loss carryforward | 1,500,000 | ||
State | |||
Income Taxes | |||
Net operating loss carryforward | $ 1,400,000 |
Commitments (Detail)
Commitments (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Future minimum payments | |||
2,017 | $ 1,122 | ||
2,018 | 1,342 | ||
2,019 | 1,403 | ||
2,020 | 1,354 | ||
2,021 | 1,315 | ||
Thereafter | 11,576 | ||
Total | 18,112 | ||
Firm transportation | |||
Future minimum payments | |||
2,017 | 626 | ||
2,018 | 935 | ||
2,019 | 1,086 | ||
2,020 | 1,105 | ||
2,021 | 1,084 | ||
Thereafter | 10,551 | ||
Total | 15,387 | ||
Gas processing, gathering and compression | |||
Future minimum payments | |||
2,017 | 373 | ||
2,018 | 289 | ||
2,019 | 243 | ||
2,020 | 241 | ||
2,021 | 223 | ||
Thereafter | 1,000 | ||
Total | 2,369 | ||
Drilling rigs and frac Services | |||
Future minimum payments | |||
2,017 | 109 | ||
2,018 | 105 | ||
2,019 | 64 | ||
Total | 278 | ||
Office and equipment | |||
Future minimum payments | |||
2,017 | 14 | ||
2,018 | 13 | ||
2,019 | 10 | ||
2,020 | 8 | ||
2,021 | 8 | ||
Thereafter | 25 | ||
Total | 78 | ||
Commitments | |||
Rental expense under operating leases | $ 9 | $ 9 | $ 10 |
Contingencies (Details)
Contingencies (Details) $ in Millions | Dec. 31, 2016USD ($) |
Contingencies | |
Additional accounts receivable | $ 55 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Sales and revenues: | |||||||||||
Sales and revenues | $ 156,216 | $ 1,116,503 | $ (249,198) | $ 721,004 | $ 905,122 | $ 1,443,335 | $ 376,714 | $ 1,229,687 | $ 1,744,525 | $ 3,954,858 | $ 2,720,632 |
Operating expenses: | |||||||||||
Lease operating | 50,090 | 36,011 | 29,341 | ||||||||
Gathering, compression, processing, and transportation | 882,838 | 659,361 | 461,413 | ||||||||
Depletion, depreciation, and amortization | 809,873 | 709,763 | 477,896 | ||||||||
General and administrative expense | 239,324 | 233,697 | 216,533 | ||||||||
Total operating expenses | 788,225 | 649,171 | 640,675 | 642,255 | 591,896 | 502,220 | 540,463 | 529,993 | 2,720,326 | 2,164,572 | 1,420,898 |
Operating income (loss) | (632,009) | $ 467,332 | $ (889,873) | $ 78,749 | 313,226 | $ 941,115 | $ (163,749) | $ 699,694 | (975,801) | 1,790,286 | 1,299,734 |
Segment assets | 14,255,550 | 14,115,493 | 14,255,550 | 14,115,493 | |||||||
Exploration and production | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 1,352,980 | 3,761,424 | 2,645,148 | ||||||||
Gathering and compression | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 307,944 | 230,592 | 95,746 | ||||||||
Fresh Water Distribution | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 282,267 | 156,732 | 171,925 | ||||||||
Marketing | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 393,049 | 176,229 | |||||||||
Operating segments | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 1,744,525 | 3,954,858 | 2,720,632 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 50,090 | 36,011 | 29,341 | ||||||||
Gathering, compression, processing, and transportation | 882,838 | 659,361 | 461,413 | ||||||||
Depletion, depreciation, and amortization | 809,873 | 709,763 | 477,896 | ||||||||
General and administrative expense | 239,324 | 233,697 | 216,533 | ||||||||
Other operating expenses | 738,201 | 525,740 | 235,715 | ||||||||
Total operating expenses | 2,720,326 | 2,164,572 | 1,420,898 | ||||||||
Operating income (loss) | (975,801) | 1,790,286 | 1,299,734 | ||||||||
Segment assets | 14,255,550 | 14,115,493 | 14,255,550 | 14,115,493 | 11,539,378 | ||||||
Capital expenditures for segment assets | 2,495,429 | 2,347,909 | 4,086,568 | ||||||||
Operating segments | Exploration and production | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 1,334,656 | 3,756,629 | 2,644,953 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 50,651 | 35,552 | 28,041 | ||||||||
Gathering, compression, processing, and transportation | 1,146,221 | 852,573 | 536,879 | ||||||||
Depletion, depreciation, and amortization | 709,127 | 622,379 | 424,684 | ||||||||
General and administrative expense | 186,672 | 183,675 | 186,335 | ||||||||
Other operating expenses | 241,755 | 222,990 | 128,419 | ||||||||
Total operating expenses | 2,334,426 | 1,917,169 | 1,304,358 | ||||||||
Operating income (loss) | (981,446) | 1,844,255 | 1,340,790 | ||||||||
Segment assets | 12,512,973 | 12,426,518 | 12,512,973 | 12,426,518 | 9,886,214 | ||||||
Capital expenditures for segment assets | 2,220,688 | 1,954,256 | 3,455,079 | ||||||||
Operating segments | Gathering and compression | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 16,028 | 12,353 | 6,810 | ||||||||
Operating expenses: | |||||||||||
Gathering, compression, processing, and transportation | 28,098 | 25,305 | 13,497 | ||||||||
Depletion, depreciation, and amortization | 70,847 | 61,552 | 36,972 | ||||||||
General and administrative expense | 39,832 | 40,448 | 22,035 | ||||||||
Other operating expenses | (809) | 3,811 | 1,973 | ||||||||
Total operating expenses | 137,968 | 131,116 | 74,477 | ||||||||
Operating income (loss) | 169,976 | 99,476 | 21,269 | ||||||||
Segment assets | 1,750,354 | 1,470,691 | 1,750,354 | 1,470,691 | 1,411,470 | ||||||
Capital expenditures for segment assets | 231,044 | 360,287 | 558,037 | ||||||||
Operating segments | Fresh Water Distribution | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 792 | 9,647 | 15,265 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 136,386 | 49,859 | 34,737 | ||||||||
Depletion, depreciation, and amortization | 29,899 | 25,832 | 16,240 | ||||||||
General and administrative expense | 14,331 | 10,758 | 8,331 | ||||||||
Other operating expenses | 14,401 | 3,210 | 1,888 | ||||||||
Total operating expenses | 195,017 | 89,659 | 61,196 | ||||||||
Operating income (loss) | 87,250 | 67,073 | 110,729 | ||||||||
Segment assets | 615,687 | 525,004 | 615,687 | 525,004 | 422,885 | ||||||
Capital expenditures for segment assets | 188,188 | 131,051 | 196,675 | ||||||||
Operating segments | Marketing | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 393,049 | 176,229 | 53,604 | ||||||||
Operating expenses: | |||||||||||
Other operating expenses | 499,343 | 299,062 | 103,435 | ||||||||
Total operating expenses | 499,343 | 299,062 | 103,435 | ||||||||
Operating income (loss) | (106,294) | (122,833) | (49,831) | ||||||||
Segment assets | 37,890 | 16,123 | 37,890 | 16,123 | 10,456 | ||||||
Elimination of intersegment transaction | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | (591,715) | (370,119) | (245,791) | ||||||||
Operating expenses: | |||||||||||
Lease operating | (136,947) | (49,400) | (33,437) | ||||||||
Gathering, compression, processing, and transportation | (291,481) | (218,517) | (88,963) | ||||||||
General and administrative expense | (1,511) | (1,184) | (168) | ||||||||
Other operating expenses | (16,489) | (3,333) | |||||||||
Total operating expenses | (446,428) | (272,434) | (122,568) | ||||||||
Operating income (loss) | (145,287) | (97,685) | (123,223) | ||||||||
Segment assets | $ (661,354) | $ (322,843) | (661,354) | (322,843) | (191,647) | ||||||
Capital expenditures for segment assets | (144,491) | (97,685) | (123,223) | ||||||||
Elimination of intersegment transaction | Exploration and production | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 18,324 | 4,795 | 195 | ||||||||
Elimination of intersegment transaction | Gathering and compression | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | 291,916 | 218,239 | 88,936 | ||||||||
Elimination of intersegment transaction | Fresh Water Distribution | |||||||||||
Sales and revenues: | |||||||||||
Sales and revenues | $ 281,475 | $ 147,085 | $ 156,660 |
Subsidiary Guarantors - Balance
Subsidiary Guarantors - Balance Sheets (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Current assets: | ||||
Cash and cash equivalents | $ 31,610 | $ 23,473 | $ 245,979 | $ 17,487 |
Accounts receivable, net | 29,682 | 79,404 | ||
Accrued revenue | 261,960 | 128,242 | ||
Derivative instruments | 73,022 | 1,009,030 | ||
Other current assets | 6,313 | 8,087 | ||
Total current assets | 402,587 | 1,248,236 | ||
Unproved properties | 2,331,173 | 1,996,081 | ||
Proved properties | 9,549,671 | 8,211,106 | ||
Water handling and treatment systems | 744,682 | 565,616 | ||
Gathering systems and facilities | 1,723,768 | 1,502,396 | ||
Other property and equipment | 41,231 | 46,415 | ||
Property and equipment, gross | 14,390,525 | 12,321,614 | ||
Less accumulated depletion, depreciation, and amortization | (2,363,778) | (1,589,372) | ||
Property and equipment, net | 12,026,747 | 10,732,242 | ||
Derivative instruments | 1,731,063 | 2,108,450 | ||
Other assets, net | 95,153 | 26,565 | ||
Total assets | 14,255,550 | 14,115,493 | ||
Liabilities and Stockholders' Equity | ||||
Accounts payable | 38,627 | 69,911 | ||
Accrued liabilities | 393,803 | 488,325 | ||
Revenue distributions payable | 163,989 | 129,949 | ||
Derivative Liability, Current | 203,635 | |||
Other current liabilities | 17,334 | 19,085 | ||
Total current liabilities | 817,388 | 707,270 | ||
Long-term debt | 4,703,973 | 4,668,782 | ||
Deferred income tax liability | 950,217 | 1,370,686 | ||
Derivative instruments | 234 | |||
Other liabilities | 55,160 | 82,077 | ||
Total liabilities | 6,526,972 | 6,828,815 | ||
Common stock | 3,149 | 2,770 | ||
Additional paid-in capital | 5,299,481 | 4,122,811 | ||
Accumulated earnings | 959,995 | 1,808,811 | ||
Total stockholders' equity | 6,262,625 | 5,934,392 | ||
Noncontrolling interest in consolidated subsidiary | 1,465,953 | 1,352,286 | ||
Total equity | 7,728,578 | 7,286,678 | 5,473,830 | 3,598,660 |
Total liabilities and equity | 14,255,550 | 14,115,493 | ||
Eliminations | ||||
Current assets: | ||||
Intercompany receivables | (67,332) | (67,850) | ||
Total current assets | (67,332) | (67,850) | ||
Proved properties | (177,286) | (32,795) | ||
Property and equipment, gross | (177,286) | (32,795) | ||
Property and equipment, net | (177,286) | (32,795) | ||
Investment in subsidiaries | 420,429 | 302,336 | ||
Contingent acquisition consideration asset | (194,538) | (178,049) | ||
Total assets | (18,727) | 23,642 | ||
Liabilities and Stockholders' Equity | ||||
Intercompany payable | (67,332) | (67,850) | ||
Total current liabilities | (67,332) | (67,850) | ||
Contingent acquisition consideration liability | (194,538) | (178,049) | ||
Total liabilities | (261,870) | (245,899) | ||
Partners' capital | (1,222,810) | (1,082,745) | ||
Total stockholders' equity | (1,222,810) | (1,082,745) | ||
Noncontrolling interest in consolidated subsidiary | 1,465,953 | 1,352,286 | ||
Total equity | 243,143 | 269,541 | ||
Total liabilities and equity | (18,727) | 23,642 | ||
Antero Resources LLC | Reportable legal entity | ||||
Current assets: | ||||
Cash and cash equivalents | 17,568 | 16,590 | 15,787 | $ 17,487 |
Accounts receivable, net | 28,442 | 76,697 | ||
Intercompany receivables | 3,193 | 2,138 | ||
Accrued revenue | 261,960 | 128,242 | ||
Derivative instruments | 73,022 | 1,009,030 | ||
Other current assets | 5,784 | 8,087 | ||
Total current assets | 389,969 | 1,240,784 | ||
Unproved properties | 2,331,173 | 1,996,081 | ||
Proved properties | 9,726,957 | 8,243,901 | ||
Gathering systems and facilities | 17,929 | 16,561 | ||
Other property and equipment | 41,231 | 46,415 | ||
Property and equipment, gross | 12,117,290 | 10,302,958 | ||
Less accumulated depletion, depreciation, and amortization | (2,109,136) | (1,431,747) | ||
Property and equipment, net | 10,008,154 | 8,871,211 | ||
Derivative instruments | 1,731,063 | 2,108,450 | ||
Investment in subsidiaries | (420,429) | (302,336) | ||
Contingent acquisition consideration asset | 194,538 | 178,049 | ||
Other assets, net | 21,087 | 15,661 | ||
Total assets | 11,924,382 | 12,111,819 | ||
Liabilities and Stockholders' Equity | ||||
Accounts payable | 21,648 | 58,970 | ||
Intercompany payable | 64,139 | 65,712 | ||
Accrued liabilities | 332,162 | 402,940 | ||
Revenue distributions payable | 163,989 | 129,949 | ||
Derivative Liability, Current | 203,635 | |||
Other current liabilities | 17,134 | 18,935 | ||
Total current liabilities | 802,707 | 676,506 | ||
Long-term debt | 3,854,059 | 4,048,782 | ||
Deferred income tax liability | 950,217 | 1,370,686 | ||
Derivative instruments | 234 | |||
Other liabilities | 54,540 | 81,453 | ||
Total liabilities | 5,661,757 | 6,177,427 | ||
Common stock | 3,149 | 2,770 | ||
Additional paid-in capital | 5,299,481 | 4,122,811 | ||
Accumulated earnings | 959,995 | 1,808,811 | ||
Total stockholders' equity | 6,262,625 | 5,934,392 | ||
Total equity | 6,262,625 | 5,934,392 | ||
Total liabilities and equity | 11,924,382 | 12,111,819 | ||
Non-Guarantor Subsidiaries | Reportable legal entity | ||||
Current assets: | ||||
Cash and cash equivalents | 14,042 | 6,883 | $ 230,192 | |
Accounts receivable, net | 1,240 | 2,707 | ||
Intercompany receivables | 64,139 | 65,712 | ||
Other current assets | 529 | |||
Total current assets | 79,950 | 75,302 | ||
Water handling and treatment systems | 744,682 | 565,616 | ||
Gathering systems and facilities | 1,705,839 | 1,485,835 | ||
Property and equipment, gross | 2,450,521 | 2,051,451 | ||
Less accumulated depletion, depreciation, and amortization | (254,642) | (157,625) | ||
Property and equipment, net | 2,195,879 | 1,893,826 | ||
Other assets, net | 74,066 | 10,904 | ||
Total assets | 2,349,895 | 1,980,032 | ||
Liabilities and Stockholders' Equity | ||||
Accounts payable | 16,979 | 10,941 | ||
Intercompany payable | 3,193 | 2,138 | ||
Accrued liabilities | 61,641 | 85,385 | ||
Other current liabilities | 200 | 150 | ||
Total current liabilities | 82,013 | 98,614 | ||
Long-term debt | 849,914 | 620,000 | ||
Contingent acquisition consideration liability | 194,538 | 178,049 | ||
Other liabilities | 620 | 624 | ||
Total liabilities | 1,127,085 | 897,287 | ||
Partners' capital | 1,222,810 | 1,082,745 | ||
Total stockholders' equity | 1,222,810 | 1,082,745 | ||
Total equity | 1,222,810 | 1,082,745 | ||
Total liabilities and equity | $ 2,349,895 | $ 1,980,032 |
Subsidiary Guarantors - Stateme
Subsidiary Guarantors - Statements of Operations (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue: | |||||||||||
Natural gas sales | $ 1,260,750 | $ 1,039,892 | $ 1,301,349 | ||||||||
Natural gas liquids sales | 432,992 | 264,483 | 328,323 | ||||||||
Oil sales | 61,319 | 70,753 | 107,080 | ||||||||
Gathering, processing, and water handling and treatment | 12,961 | 22,000 | 22,075 | ||||||||
Marketing Revenue | 393,049 | 176,229 | 53,604 | ||||||||
Commodity derivative fair value gains (losses) | (514,181) | 2,381,501 | 868,201 | ||||||||
Gain on sale of assets | 97,635 | 40,000 | |||||||||
Total revenue and other | $ 156,216 | $ 1,116,503 | $ (249,198) | $ 721,004 | $ 905,122 | $ 1,443,335 | $ 376,714 | $ 1,229,687 | 1,744,525 | 3,954,858 | 2,720,632 |
Operating expenses: | |||||||||||
Lease operating | 50,090 | 36,011 | 29,341 | ||||||||
Gathering, compression, processing, and transportation | 882,838 | 659,361 | 461,413 | ||||||||
Production and ad valorem taxes | 66,588 | 78,325 | 87,918 | ||||||||
Marketing | 499,343 | 299,062 | 103,435 | ||||||||
Exploration | 6,862 | 3,846 | 27,893 | ||||||||
Impairment of unproved properties | 162,935 | 104,321 | 15,198 | ||||||||
Depletion, depreciation, and amortization | 809,873 | 709,763 | 477,896 | ||||||||
Accretion of asset retirement obligations | 2,473 | 1,655 | 1,271 | ||||||||
General and administrative | 239,324 | 233,697 | 216,533 | ||||||||
Contract termination and rig stacking | 38,500 | 38,531 | |||||||||
Total operating expenses | 788,225 | 649,171 | 640,675 | 642,255 | 591,896 | 502,220 | 540,463 | 529,993 | 2,720,326 | 2,164,572 | 1,420,898 |
Operating income (loss) | (632,009) | 467,332 | (889,873) | 78,749 | 313,226 | 941,115 | (163,749) | 699,694 | (975,801) | 1,790,286 | 1,299,734 |
Equity in earnings of unconsolidated affiliate | 485 | ||||||||||
Interest | (253,552) | (234,400) | (160,051) | ||||||||
Loss on early extinguishment of debt | (16,956) | (20,386) | |||||||||
Total other expenses | (270,023) | (234,400) | (180,437) | ||||||||
Income (loss) before income taxes | (1,245,824) | 1,555,886 | 1,119,297 | ||||||||
Provision for income tax (expense) benefit | 496,376 | (575,890) | (445,672) | ||||||||
Income (loss) from continuing operations | (749,448) | 979,996 | 673,625 | ||||||||
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 | (452,804) | 268,196 | (575,490) | 10,650 | 175,574 | 544,734 | (139,483) | 399,171 | (749,448) | 979,996 | 675,835 |
Net income and comprehensive income attributable to noncontrolling interest | 32,968 | 29,941 | 20,754 | 15,705 | 17,110 | 10,892 | 5,890 | 4,740 | 99,368 | 38,632 | 2,248 |
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ (485,772) | $ 238,255 | $ (596,244) | $ (5,055) | $ 158,464 | $ 533,842 | $ (145,373) | $ 394,431 | (848,816) | 941,364 | 673,587 |
Reportable legal entity | Antero Resources LLC | |||||||||||
Revenue: | |||||||||||
Natural gas sales | 1,260,750 | 1,039,892 | 1,301,349 | ||||||||
Natural gas liquids sales | 432,992 | 264,483 | 328,323 | ||||||||
Oil sales | 61,319 | 70,753 | 107,080 | ||||||||
Gathering, processing, and water handling and treatment | 6,651 | 20,284 | |||||||||
Marketing Revenue | 393,049 | 176,229 | 53,604 | ||||||||
Commodity derivative fair value gains (losses) | (514,181) | 2,381,501 | 868,201 | ||||||||
Other income | 18,324 | 4,594 | 143 | ||||||||
Gain on sale of assets | 93,776 | 40,000 | |||||||||
Total revenue and other | 1,746,029 | 3,944,103 | 2,718,984 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 50,651 | 36,132 | 29,341 | ||||||||
Gathering, compression, processing, and transportation | 1,146,221 | 852,573 | 480,367 | ||||||||
Production and ad valorem taxes | 69,485 | 77,074 | 85,945 | ||||||||
Marketing | 499,343 | 299,062 | 103,435 | ||||||||
Exploration | 6,862 | 3,846 | 27,893 | ||||||||
Impairment of unproved properties | 162,935 | 104,321 | 15,198 | ||||||||
Depletion, depreciation, and amortization | 710,012 | 641,860 | 471,372 | ||||||||
Accretion of asset retirement obligations | 2,473 | 1,655 | 1,271 | ||||||||
General and administrative | 186,672 | 190,712 | 212,316 | ||||||||
Contract termination and rig stacking | 38,531 | ||||||||||
Total operating expenses | 2,834,654 | 2,245,766 | 1,427,138 | ||||||||
Operating income (loss) | (1,088,625) | 1,698,337 | 1,291,846 | ||||||||
Interest | (232,455) | (228,568) | (159,585) | ||||||||
Loss on early extinguishment of debt | (16,956) | (20,386) | |||||||||
Equity in net income of subsidiaries | (7,156) | 47,485 | 5,174 | ||||||||
Total other expenses | (256,567) | (181,083) | (174,797) | ||||||||
Income (loss) before income taxes | (1,345,192) | 1,517,254 | 1,117,049 | ||||||||
Provision for income tax (expense) benefit | 496,376 | (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 | (848,816) | 941,364 | 673,587 | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | (848,816) | 941,364 | 673,587 | ||||||||
Reportable legal entity | Non-Guarantor Subsidiaries | |||||||||||
Revenue: | |||||||||||
Gathering, processing, and water handling and treatment | 586,352 | 299,787 | 25,178 | ||||||||
Gain on sale of assets | 3,859 | ||||||||||
Total revenue and other | 590,211 | 299,787 | 25,178 | ||||||||
Operating expenses: | |||||||||||
Lease operating | 136,387 | 33,283 | |||||||||
Gathering, compression, processing, and transportation | 28,097 | 25,305 | 4,460 | ||||||||
Production and ad valorem taxes | (2,897) | 1,251 | 1,973 | ||||||||
Depletion, depreciation, and amortization | 99,861 | 67,903 | 6,524 | ||||||||
General and administrative | 54,163 | 43,968 | 4,333 | ||||||||
Accretion of contingent acquisition consideration | 16,489 | 3,333 | |||||||||
Total operating expenses | 332,100 | 175,043 | 17,290 | ||||||||
Operating income (loss) | 258,111 | 124,744 | 7,888 | ||||||||
Equity in earnings of unconsolidated affiliate | 485 | ||||||||||
Interest | (21,893) | (5,832) | (466) | ||||||||
Total other expenses | (21,408) | (5,832) | (466) | ||||||||
Income (loss) before income taxes | 236,703 | 118,912 | 7,422 | ||||||||
Income (loss) from continuing operations | 7,422 | ||||||||||
Discontinued operations: | |||||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | 236,703 | 118,912 | 7,422 | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | 236,703 | 118,912 | 7,422 | ||||||||
Eliminations | |||||||||||
Revenue: | |||||||||||
Gathering, processing, and water handling and treatment | (573,391) | (284,438) | (23,387) | ||||||||
Other income | (18,324) | (4,594) | (143) | ||||||||
Total revenue and other | (591,715) | (289,032) | (23,530) | ||||||||
Operating expenses: | |||||||||||
Lease operating | (136,948) | (33,404) | |||||||||
Gathering, compression, processing, and transportation | (291,480) | (218,517) | (23,414) | ||||||||
General and administrative | (1,511) | (983) | (116) | ||||||||
Accretion of contingent acquisition consideration | (16,489) | (3,333) | |||||||||
Total operating expenses | (446,428) | (256,237) | (23,530) | ||||||||
Operating income (loss) | (145,287) | (32,795) | |||||||||
Interest | 796 | ||||||||||
Equity in net income of subsidiaries | 7,156 | (47,485) | (5,174) | ||||||||
Total other expenses | 7,952 | (47,485) | (5,174) | ||||||||
Income (loss) before income taxes | (137,335) | (80,280) | (5,174) | ||||||||
Income (loss) from continuing operations | (5,174) | ||||||||||
Discontinued operations: | |||||||||||
Net income (loss) and comprehensive income (loss) including noncontrolling interest | (137,335) | (80,280) | (5,174) | ||||||||
Net income and comprehensive income attributable to noncontrolling interest | 99,368 | 38,632 | 2,248 | ||||||||
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ (236,703) | $ (118,912) | $ (7,422) |
Subsidiary Guarantors - Cash Fl
Subsidiary Guarantors - Cash Flows (Details) - USD ($) $ in Thousands | Mar. 30, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Condensed consolidated statement of cash flows | ||||
Net cash provided by operating activities | $ 1,241,256 | $ 1,015,812 | $ 998,263 | |
Cash flows used in investing activities: | ||||
Additions to proved properties | (134,113) | (64,066) | ||
Additions to unproved properties | (611,631) | (198,694) | (777,422) | |
Drilling and completion costs | (1,327,759) | (1,651,282) | (2,477,150) | |
Additions to water handling and treatment systems | (188,188) | (131,051) | (196,675) | |
Additions to gathering systems and facilities | (231,044) | (360,287) | (558,037) | |
Additions to other property and equipment | (2,694) | (6,595) | (13,218) | |
Investment in unconsolidated affiliate | (75,516) | |||
Change in other assets | 3,977 | 9,750 | (3,082) | |
Proceeds from asset sales | 171,830 | 40,000 | ||
Net cash used in investing activities | (2,395,138) | (2,298,159) | (4,089,650) | |
Cash flows from financing activities: | ||||
Issuance of common stock | 1,012,431 | 537,832 | ||
Issuance of common units by Antero Midstream Partners LP | 65,395 | 240,703 | 1,087,224 | |
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | 178,000 | |||
Issuance of senior notes | 1,250,000 | 750,000 | 1,102,500 | |
Repayment of senior notes | (525,000) | (260,000) | ||
Borrowings (repayments) on bank credit facility, net | (677,000) | (403,000) | 1,442,000 | |
Make-whole premium on debt extinguished | (15,750) | (17,383) | ||
Payments of deferred financing costs | (18,759) | (17,293) | (31,543) | |
Distributions to noncontrolling interest in consolidated subsidiary | (75,082) | (34,129) | ||
Employee tax withholding for settlement of equity compensation awards | (26,895) | (9,431) | (142) | |
Other | (5,321) | (4,841) | (2,777) | |
Net cash provided by financing activities | 1,162,019 | 1,059,841 | 3,319,879 | |
Net increase (decrease) in cash and cash equivalents | 8,137 | (222,506) | 228,492 | |
Cash and cash equivalents, beginning of period | 23,473 | 245,979 | 17,487 | |
Cash and cash equivalents, end of period | 31,610 | 23,473 | 245,979 | |
Antero Resources LLC | ||||
Cash flows from financing activities: | ||||
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | $ 178,000 | |||
Reportable legal entity | Antero Resources LLC | ||||
Condensed consolidated statement of cash flows | ||||
Net cash provided by operating activities | 1,007,140 | 853,548 | 992,930 | |
Cash flows used in investing activities: | ||||
Additions to proved properties | (134,113) | (64,066) | ||
Additions to unproved properties | (611,631) | (198,694) | (777,422) | |
Drilling and completion costs | (1,472,250) | (1,684,077) | (2,477,150) | |
Additions to water handling and treatment systems | 32 | (80,064) | (196,675) | |
Additions to gathering systems and facilities | (2,944) | (40,285) | (543,196) | |
Additions to other property and equipment | (2,694) | (6,595) | (13,218) | |
Change in other assets | 304 | 2,570 | (2,928) | |
Net distributions (to) from guarantor subsidiary | (115,000) | 115,000 | ||
Distributions from non-guarantor subsidiary | 107,364 | 73,119 | 332,500 | |
Proceeds from contribution of assets to non-guarantor subsidiary | 801,116 | |||
Proceeds from asset sales | 161,830 | 40,000 | ||
Net cash used in investing activities | (1,954,102) | (1,207,910) | (3,627,155) | |
Cash flows from financing activities: | ||||
Issuance of common stock | 1,012,431 | 537,832 | ||
Proceeds from sale of common units in Antero Midstream Partners LP by Antero Resources Corporation | 178,000 | |||
Issuance of senior notes | 600,000 | 750,000 | 1,102,500 | |
Repayment of senior notes | (525,000) | (260,000) | ||
Borrowings (repayments) on bank credit facility, net | (267,000) | (908,000) | 1,837,000 | |
Make-whole premium on debt extinguished | (15,750) | (17,383) | ||
Payments of deferred financing costs | (8,324) | (15,234) | (26,673) | |
Employee tax withholding for settlement of equity compensation awards | (21,260) | (4,625) | (142) | |
Other | (5,157) | (4,808) | (2,777) | |
Net cash provided by financing activities | 947,940 | 355,165 | 2,632,525 | |
Net increase (decrease) in cash and cash equivalents | 978 | 803 | (1,700) | |
Cash and cash equivalents, beginning of period | 16,590 | 15,787 | 17,487 | |
Cash and cash equivalents, end of period | 17,568 | 16,590 | 15,787 | |
Reportable legal entity | Guarantor Subsidiary | ||||
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 | 378,607 | 195,059 | 5,333 | |
Cash flows used in investing activities: | ||||
Additions to water handling and treatment systems | (188,220) | (50,987) | ||
Additions to gathering systems and facilities | (228,100) | (320,002) | (14,841) | |
Investment in unconsolidated affiliate | (75,516) | |||
Change in other assets | 3,673 | 7,180 | (154) | |
Proceeds from asset sales | 10,000 | |||
Net cash used in investing activities | (478,163) | (363,809) | (14,995) | |
Cash flows from financing activities: | ||||
Issuance of common units by Antero Midstream Partners LP | 65,395 | 240,703 | 1,087,224 | |
Issuance of senior notes | 650,000 | |||
Borrowings (repayments) on bank credit facility, net | (410,000) | 620,000 | (510,000) | |
Payments of deferred financing costs | (10,435) | (2,059) | (4,870) | |
Distributions to noncontrolling interest in consolidated subsidiary | (182,446) | (908,364) | (332,500) | |
Employee tax withholding for settlement of equity compensation awards | (5,635) | (4,806) | ||
Other | (164) | (33) | ||
Net cash provided by financing activities | 106,715 | (54,559) | 239,854 | |
Net increase (decrease) in cash and cash equivalents | 7,159 | (223,309) | 230,192 | |
Cash and cash equivalents, beginning of period | 6,883 | 230,192 | ||
Cash and cash equivalents, end of period | 14,042 | 6,883 | 230,192 | |
Eliminations | ||||
Condensed consolidated statement of cash flows | ||||
Net cash provided by operating activities | (144,491) | (32,795) | ||
Cash flows used in investing activities: | ||||
Drilling and completion costs | 144,491 | 32,795 | ||
Net distributions (to) from guarantor subsidiary | 115,000 | (115,000) | ||
Distributions from non-guarantor subsidiary | (107,364) | (73,119) | (332,500) | |
Proceeds from contribution of assets to non-guarantor subsidiary | (801,116) | |||
Net cash used in investing activities | 37,127 | (726,440) | (447,500) | |
Cash flows from financing activities: | ||||
Distributions to noncontrolling interest in consolidated subsidiary | 107,364 | 759,235 | 447,500 | |
Net cash provided by financing activities | $ 107,364 | $ 759,235 | $ 447,500 |
Quarterly Financial Informati70
Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($)$ / shares | Sep. 30, 2016USD ($)$ / shares | Jun. 30, 2016USD ($)$ / shares | Mar. 31, 2016USD ($)$ / shares | Dec. 31, 2015USD ($)$ / shares | Sep. 30, 2015USD ($)$ / shares | Jun. 30, 2015USD ($)$ / shares | Mar. 31, 2015USD ($)$ / shares | Dec. 31, 2016USD ($)MMcfe$ / shares | Dec. 31, 2015USD ($)MMcfe$ / shares | Dec. 31, 2014USD ($)MMcfe$ / shares | |
Selected Quarterly Financial Information [Abstract] | |||||||||||
Total revenue | $ 156,216 | $ 1,116,503 | $ (249,198) | $ 721,004 | $ 905,122 | $ 1,443,335 | $ 376,714 | $ 1,229,687 | $ 1,744,525 | $ 3,954,858 | $ 2,720,632 |
Total operating expenses | 788,225 | 649,171 | 640,675 | 642,255 | 591,896 | 502,220 | 540,463 | 529,993 | 2,720,326 | 2,164,572 | 1,420,898 |
Operating income (loss) | (632,009) | 467,332 | (889,873) | 78,749 | 313,226 | 941,115 | (163,749) | 699,694 | (975,801) | 1,790,286 | 1,299,734 |
Income (loss) from continuing operations | (749,448) | 979,996 | 673,625 | ||||||||
Income from sale of discontinued operations, net of income tax expense | 2,210 | ||||||||||
Net income (loss) including noncontrolling interest | (452,804) | 268,196 | (575,490) | 10,650 | 175,574 | 544,734 | (139,483) | 399,171 | (749,448) | 979,996 | 675,835 |
Net Income (Loss) Attributable to Noncontrolling Interest | 32,968 | 29,941 | 20,754 | 15,705 | 17,110 | 10,892 | 5,890 | 4,740 | 99,368 | 38,632 | 2,248 |
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation | $ (485,772) | $ 238,255 | $ (596,244) | $ (5,055) | $ 158,464 | $ 533,842 | $ (145,373) | $ 394,431 | $ (848,816) | $ 941,364 | $ 673,587 |
Earnings (loss) per common share - basic: | |||||||||||
Continuing operations - basic | $ / shares | $ (2.88) | $ 3.43 | $ 2.56 | ||||||||
Discontinued operations - basic | $ / shares | 0.01 | ||||||||||
Earnings (loss) per common share - basic | $ / shares | $ (1.55) | $ 0.78 | $ (2.12) | $ (0.02) | $ 0.57 | $ 1.93 | $ (0.52) | $ 1.49 | (2.88) | 3.43 | 2.57 |
Earnings (loss) per share - diluted: | |||||||||||
Continuing operations - diluted | $ / shares | (2.88) | 3.43 | 2.56 | ||||||||
Discontinued operations - diluted | $ / shares | 0.01 | ||||||||||
Earnings (loss) per common share - diluted | $ / shares | $ (1.55) | $ 0.77 | $ (2.12) | $ (0.02) | $ 0.57 | $ 1.93 | $ (0.52) | $ 1.49 | $ (2.88) | $ 3.43 | $ 2.57 |
Increase (decrease) in proved reserves resulting from price revisions | MMcfe | (47,000) | (202,000) | 2 |
Supplemental Information on O71
Supplemental Information on Oil and Gas Producing Activities (Unaudited) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Capitalized Costs Relating to Oil and Gas Producing Activities | |||
Proved properties | $ 9,549,671 | $ 8,211,106 | |
Unproved properties | 2,331,173 | 1,996,081 | |
Total | 11,880,844 | 10,207,187 | |
Accumulated depletion and depreciation | (2,089,500) | (1,415,005) | |
Net capitalized costs | 9,791,344 | 8,792,182 | |
Costs Incurred in Certain Oil and Gas Activities | |||
Proved property | 134,113 | $ 64,066 | |
Unproved property | 611,631 | 198,694 | 777,422 |
Development costs | 1,000,903 | 1,039,301 | 1,536,193 |
Exploration costs | 326,856 | 611,981 | 940,957 |
Total costs incurred | 2,073,503 | 1,849,976 | 3,318,638 |
Results of Operations for Oil and Gas Producing Activities | |||
Revenues | 1,755,061 | 1,375,128 | 1,736,752 |
Operating expenses: | |||
Production expenses | 999,516 | 773,697 | 578,672 |
Exploration expenses | 6,862 | 3,846 | 27,893 |
Depletion and depreciation | 700,274 | 614,700 | 418,744 |
Impairment of unproved properties | 162,935 | 104,321 | 15,198 |
Results of operations before income tax expense (benefit) | (114,526) | (121,436) | 696,245 |
Income tax expense | 43,334 | 45,497 | (263,126) |
Results of operations | $ (71,192) | $ (75,939) | $ 433,119 |
Supplemental Information on O72
Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Proved reserves (Details) MMcfe in Thousands | 12 Months Ended | ||
Dec. 31, 2016MMcfeBcfMMBbls | Dec. 31, 2015MMcfeBcfMMBbls | Dec. 31, 2014MMcfeBcfMMBbls | |
Proved developed and undeveloped reserves: | |||
Balance at the beginning of the period | MMcfe | 13,215 | 12,683 | 7,632 |
Revisions | MMcfe | (404) | (1,801) | (1,054) |
Extensions, discoveries and other additions | MMcfe | 2,637 | 2,878 | 6,444 |
Production | MMcfe | (676) | (545) | (368) |
Purchase of reserves | MMcfe | 624 | 29 | |
Sales of reserves in place | MMcfe | (10) | ||
Proved Developed and Undeveloped Reserve, Net (Energy), Ending Balance | MMcfe | 15,386 | 13,215 | 12,683 |
Oil and Gas Reserves | |||
Proved developed reserves | MMcfe | 6,914 | 5,838 | 3,803 |
Proved undeveloped reserves | MMcfe | 8,472 | 7,377 | 8,880 |
Natural gas | |||
Proved developed and undeveloped reserves: | |||
Balance at the beginning of the period | Bcf | 9,533 | 10,535 | 6,753 |
Revisions | Bcf | (2,069) | (2,816) | (1,025) |
Extensions, discoveries and other additions | Bcf | 1,990 | 2,253 | 5,095 |
Production | Bcf | (505) | (439) | (317) |
Purchase of reserves | Bcf | 475 | 29 | |
Sales of reserves in place | Bcf | (10) | ||
Balance at the end of the period | Bcf | 9,414 | 9,533 | 10,535 |
Oil and Gas Reserves | |||
Proved developed reserves | Bcf | 4,426 | 3,627 | 3,285 |
Proved undeveloped reserves | Bcf | 4,988 | 5,906 | 7,250 |
NGLS | |||
Proved developed and undeveloped reserves: | |||
Balance at the beginning of the period | 587 | 330 | 137 |
Revisions | 275 | 176 | (6) |
Extensions, discoveries and other additions | 99 | 97 | 206 |
Production | (27) | (16) | (7) |
Purchase of reserves | 23 | ||
Balance at the end of the period | 957 | 587 | 330 |
Oil and Gas Reserves | |||
Proved developed reserves | 401 | 360 | 80 |
Proved undeveloped reserves | 556 | 227 | 250 |
Oil and condensate | |||
Proved developed and undeveloped reserves: | |||
Balance at the beginning of the period | 26 | 28 | 10 |
Revisions | 3 | (8) | |
Extensions, discoveries and other additions | 9 | 8 | 19 |
Production | (2) | (2) | (1) |
Purchase of reserves | 2 | ||
Balance at the end of the period | 38 | 26 | 28 |
Oil and Gas Reserves | |||
Proved developed reserves | 13 | 8 | 6 |
Proved undeveloped reserves | 25 | 18 | 22 |
Supplemental Information on O73
Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Discounted future cash flows (Detail) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2016USD ($)MMcfe | Dec. 31, 2015USD ($)MMcfebbl | Dec. 31, 2014USD ($)MMcfeitem | Dec. 31, 2013USD ($) | |
Supplemental Information on Oil and Gas Producing Activities (Unaudited) | ||||
Increase in proved reserves due to ethane recovery | MMcfe | 1,359,000 | 1,091,000 | ||
Ethane recovery quantity assumption | bbl | 11,500 | |||
Decrease in proved reserves due to reclassifications related to five-year rule | MMcfe | (2,478,000) | (2,332,000) | (1,417,000) | |
Increase (decrease) in proved reserves resulting from price revisions | MMcfe | (47,000) | (202,000) | 2 | |
Increase (decrease) in proved reserves due to performance revisions | MMcfe | 762,000 | (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 | $ 36,800 | $ 35,179 | $ 63,632 | |
Future production costs | (21,275) | (17,393) | (21,722) | |
Future development costs | (3,902) | (5,217) | (8,212) | |
Future net cash flows before income tax | 11,623 | 12,569 | 33,698 | |
Future income tax expense | (1,042) | (1,708) | (10,726) | |
Future net cash flows | 10,581 | 10,861 | 22,972 | |
10% annual discount for estimated timing of cash flows | (7,294) | (7,628) | (15,337) | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | $ 3,287 | $ 3,233 | $ 7,635 | $ 4,510 |
Supplemental Information on O74
Supplemental Information on Oil and Gas Producing Activities (Unaudited) - Changes in standardized measure of discounted future net cash flow (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)$ / MMcfe | Dec. 31, 2015USD ($)$ / MMcfe | Dec. 31, 2014USD ($)$ / MMcfe | |
Supplemental Information on Oil and Gas Producing Activities (Unaudited) | |||
Weighted average price of equivalent reserves (in dollar per share) | $ / MMcfe | 2.39 | 2.66 | 5.02 |
Changes in Standardized Measure of Discounted Future Net Cash Flow | |||
Sales of oil and gas, net of productions costs | $ (756) | $ (601) | $ (1,158) |
Net changes in prices and production costs | (1,540) | (9,416) | (184) |
Development costs incurred during the period | 733 | 769 | 564 |
Net changes in future development costs | 212 | 671 | (102) |
Extensions, discoveries and other additions | 673 | 861 | 5,759 |
Acquisitions | 66 | 42 | |
Divestitures | (7) | ||
Revisions of previous quantity estimates | 461 | (1,167) | (828) |
Accretion of discount | 363 | 1,132 | 600 |
Net change in income taxes | 12 | 3,284 | (2,198) |
Other changes | (163) | 65 | 630 |
Net increase (decrease) | 54 | (4,402) | 3,125 |
Beginning of period | 3,233 | 7,635 | 4,510 |
End of period | $ 3,287 | $ 3,233 | $ 7,635 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ in Thousands | Feb. 06, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | May 26, 2016 |
Subsequent Events | ||||
Issuance of common stock | $ 1,012,431 | $ 537,832 | ||
Antero Midstream Partners LP | ||||
Subsequent Events | ||||
Ownership percentage | 15.00% | |||
Antero Midstream Partners LP | Subsequent event | ||||
Subsequent Events | ||||
Number of additional shares of common stock issued (in shares) | 6,900,000 | |||
Issuance of common stock | $ 223,000 | |||
Antero Midstream Partners LP | Subsequent event | Appalachia joint venture | ||||
Subsequent Events | ||||
Ownership percentage | 50.00% | |||
Percentage of interest held by joint venture in third party fractionator in Ohio | 33.33% | |||
Contribution to joint venture | $ 155,000 | |||
Antero Midstream Partners LP | Subsequent event | Appalachia joint venture | MarkWest | ||||
Subsequent Events | ||||
Ownership percentage | 50.00% |