ar_Current folio

Natural gas
MMbtu/day

Hedged
Differential

Three months ending December 31, 2016:

Year ending December 31, 2017:

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2016


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-36120

ANTERO RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		80-0162034
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1615 Wynkoop Street Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ☒ Yes ☐ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ☒		Accelerated filer ☐

Non-accelerated filer ☐		Smaller reporting company ☐
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) ☐ Yes ☒ No

The registrant had 313,937,299 shares of common stock outstanding as of October 21, 2016.

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TABLE OF CONTENTS


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		2
PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements (Unaudited)	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 4.	Controls and Procedures	59
PART II—OTHER INFORMATION		61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 5.	Other Information	62
Item 6.	Exhibits	63
SIGNATURES		64

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015 (our “2015 Form 10-K”) on file with the Securities and Exchange Commission (the “SEC”) and in “Item 1A. Risk Factors” of this Quarterly Report on Form 10-Q.

Forward-looking statements may include statements about our:

ability to successfully integrate the properties recently acquired from a third party with our own assets and realize the anticipated benefits of the transaction;

business strategy;

reserves;

financial strategy, liquidity, and capital required for our development program;

natural gas, natural gas liquids (“NGLs”), and oil prices;

timing and amount of future production of natural gas, NGLs, and oil;

hedging strategy and results;

ability to meet our minimum volume commitments and to utilize or monetize our firm transportation commitments;

future drilling plans;

competition and government regulations;

pending legal or environmental matters;

marketing of natural gas, NGLs, and oil;

leasehold or business acquisitions;

costs of developing our properties;

operations of Antero Midstream Partners LP;

general economic conditions;

credit markets;

uncertainty regarding our future operating results; and

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plans, objectives, expectations, and intentions.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering, processing, transportation, and sale of natural gas, NGLs, and oil. These risks include, but are not limited to, commodity price volatility and continued low commodity prices, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, marketing and transportation risks, regulatory changes, the uncertainty inherent in estimating natural gas, NGLs, and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in our 2015 Form 10-K on file with the SEC and in “Item 1A. Risk Factors” of this Quarterly Report on Form 10-Q.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities, or changes in commodity prices, may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs, and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

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PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2015 and September 30, 2016

(Unaudited)

(In thousands, except per share amounts)


	December 31, 2015		September 30, 2016
Assets
Current assets:
Cash and cash equivalents	$	23,473		18,512
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016		79,404		59,462
Accrued revenue		128,242		196,490
Derivative instruments		1,009,030		417,605
Other current assets		8,087		3,402
Total current assets		1,248,236		695,471
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,996,081		2,449,995
Proved properties		8,211,106		9,180,705
Water handling and treatment systems		565,616		681,062
Gathering systems and facilities		1,502,396		1,656,676
Other property and equipment		46,415		45,571
		12,321,614		14,014,009
Less accumulated depletion, depreciation, and amortization		(1,589,372)		(2,176,793)
Property and equipment, net		10,732,242		11,837,216
Derivative instruments		2,108,450		2,015,090
Other assets		26,565		81,476
Total assets	$	14,115,493		14,629,253

Liabilities and Equity
Current liabilities:
Accounts payable	$	364,160		172,293
Accrued liabilities		194,076		245,174
Revenue distributions payable		129,949		172,202
Derivative instruments		—		3,110
Other current liabilities		19,085		19,125
Total current liabilities		707,270		611,904
Long-term liabilities:
Long-term debt		4,668,782		4,759,904
Deferred income tax liability		1,370,686		1,215,240
Derivative instruments		—		40
Other liabilities		82,077		61,883
Total liabilities		6,828,815		6,648,971
Commitments and contingencies (notes 9 and 13)
Equity:
Stockholders' equity:
Preferred stock, $0.01 par value; authorized - 50,000 shares; none issued		—		—
Common stock, $0.01 par value; authorized - 1,000,000 shares; issued and outstanding 277,036 shares and 307,188 shares, respectively		2,770		3,072
Additional paid-in capital		4,122,811		5,131,909
Accumulated earnings		1,808,811		1,445,767
Total stockholders' equity		5,934,392		6,580,748
Noncontrolling interest in consolidated subsidiary		1,352,286		1,399,534
Total equity		7,286,678		7,980,282
Total liabilities and equity	$	14,115,493		14,629,253

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income

Three Months Ended September 30, 2015 and 2016

(Unaudited)

(In thousands, except per share amounts)


	Three Months Ended September 30,
	2015		2016
Revenue:
Natural gas sales	$	253,975		364,373
Natural gas liquids sales		50,092		106,958
Oil sales		20,138		14,793
Gathering, compression, and water handling and treatment		4,426		2,969
Marketing		35,633		97,076
Commodity derivative fair value gains		1,079,071		530,334
Total revenue		1,443,335		1,116,503
Operating expenses:
Lease operating		10,786		13,854
Gathering, compression, processing, and transportation		160,302		234,915
Production and ad valorem taxes		10,721		15,554
Marketing		61,799		114,611
Exploration		1,087		1,166
Impairment of unproved properties		8,754		11,753
Depletion, depreciation, and amortization		188,667		199,113
Accretion of asset retirement obligations		419		628
General and administrative (including equity-based compensation expense of $23,915 and $26,381 in 2015 and 2016, respectively)		59,685		57,577
Total operating expenses		502,220		649,171
Operating income		941,115		467,332
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—		1,543
Interest		(60,921)		(59,755)
Total other expenses		(60,921)		(58,212)
Income before income taxes		880,194		409,120
Provision for income tax expense		(335,460)		(140,924)
Net income and comprehensive income including noncontrolling interest		544,734		268,196
Net income and comprehensive income attributable to noncontrolling interest		10,892		29,941
Net income and comprehensive income attributable to Antero Resources Corporation	$	533,842		238,255


Earnings per common share—basic	$	1.93		0.78

Earnings per common share—assuming dilution	$	1.93		0.77

Weighted average number of shares outstanding:
Basic		277,007		306,785
Diluted		277,015		308,657

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2015 and 2016

(Unaudited)

(In thousands, except per share amounts)


	Nine Months Ended September 30,
	2015		2016
Revenue:
Natural gas sales	$	810,982		848,936
Natural gas liquids sales		188,403		274,736
Oil sales		55,627		41,712
Gathering, compression, and water handling and treatment		15,084		10,107
Marketing		143,242		287,194
Commodity derivative fair value gains		1,836,398		125,624
Total revenue		3,049,736		1,588,309
Operating expenses:
Lease operating		25,561		37,190
Gathering, compression, processing, and transportation		490,633		649,713
Production and ad valorem taxes		57,458		52,296
Marketing		214,201		378,521
Exploration		3,086		3,289
Impairment of unproved properties		43,670		47,223
Depletion, depreciation, and amortization		548,013		588,057
Accretion of asset retirement obligations		1,227		1,846
General and administrative (including equity-based compensation expense of $79,280 and $75,667 in 2015 and 2016, respectively)		177,925		173,966
Contract termination and rig stacking		10,902		—
Total operating expenses		1,572,676		1,932,101
Operating income (loss)		1,477,060		(343,792)
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—		2,027
Interest		(173,929)		(185,634)
Total other expenses		(173,929)		(183,607)
Income (loss) before income taxes		1,303,131		(527,399)
Provision for income tax (expense) benefit		(498,709)		230,755
Net income (loss) and comprehensive income (loss) including noncontrolling interest		804,422		(296,644)
Net income and comprehensive income attributable to noncontrolling interest		21,522		66,400
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	782,900		(363,044)


Earnings (loss) per common share—basic	$	2.87		(1.26)

Earnings (loss) per common share—assuming dilution	$	2.87		(1.26)

Weighted average number of shares outstanding:
Basic		273,145		288,607
Diluted		273,154		288,607

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Nine Months Ended September 30, 2016

(Unaudited)

(In thousands)


	Common Stock				Additional paid-		Accumulated		Noncontrolling		Total
	Shares		Amount		in capital		earnings		interest		equity
Balances, December 31, 2015		277,036	$	2,770		4,122,811		1,808,811		1,352,286		7,286,678
Issuance of common stock in public offering, net of offering costs		29,762		298		837,116		—		—		837,414
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes		390		4		(4,863)		—		—		(4,859)
Issuance of common units by Antero Midstream Partners LP, net of offering costs		—		—		—		—		19,605		19,605
Issuance of common units in Antero Midstream Partners LP upon vesting of equity-based compensation awards, net of units withheld for income taxes		—		—		(158)		—		141		(17)
Sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation, net of tax		—		—		107,257		—		6,419		113,676
Equity-based compensation		—		—		69,746		—		5,921		75,667
Net income (loss) and comprehensive income (loss)		—		—		—		(363,044)		66,400		(296,644)
Distributions to noncontrolling interests		—		—		—		—		(51,238)		(51,238)
Balances, September 30, 2016		307,188	$	3,072		5,131,909		1,445,767		1,399,534		7,980,282

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2015 and 2016

(Unaudited)

(In thousands)


	Nine Months Ended September 30,
	2015		2016
Cash flows from operating activities:
Net income (loss) including noncontrolling interest	$	804,422		(296,644)
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		549,240		589,903
Impairment of unproved properties		43,670		47,223
Derivative fair value gains		(1,836,398)		(125,624)
Gains on settled derivatives		586,639		813,559
Deferred income tax expense (benefit)		498,709		(230,755)
Equity-based compensation expense		79,280		75,667
Equity in earnings of unconsolidated affiliate		—		(2,027)
Other		12,129		(1,544)
Changes in current assets and liabilities:
Accounts receivable		15,299		10,077
Accrued revenue		75,765		(68,248)
Other current assets		4,127		4,685
Accounts payable		(1,302)		(7,415)
Accrued liabilities		34,091		54,484
Revenue distributions payable		(20,839)		42,253
Other current liabilities		(3,678)		103
Net cash provided by operating activities		841,154		905,697
Cash flows used in investing activities:
Additions to proved properties		—		(64,789)
Additions to unproved properties		(170,291)		(559,572)
Drilling and completion costs		(1,350,498)		(1,009,851)
Additions to water handling and treatment systems		(79,227)		(137,355)
Additions to gathering systems and facilities		(282,813)		(154,136)
Additions to other property and equipment		(5,225)		(1,747)
Investment in unconsolidated affiliate		—		(45,044)
Change in other assets		11,190		(2,173)
Proceeds from asset sales		40,000		—
Net cash used in investing activities		(1,836,864)		(1,974,667)
Cash flows from financing activities:
Issuance of common stock		537,832		837,414
Issuance of common units by Antero Midstream Partners LP		240,972		19,605
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		—		178,000
Issuance of senior notes		750,000		650,000
Repayments on bank credit facilities, net		(705,000)		(552,000)
Payments of deferred financing costs		(17,190)		(9,029)
Distributions to noncontrolling interest in consolidated subsidiary		(21,358)		(51,238)
Employee tax withholding for settlement of equity compensation awards		(4,554)		(4,876)
Other		(3,561)		(3,867)
Net cash provided by financing activities		777,141		1,064,009
Net decrease in cash and cash equivalents		(218,569)		(4,961)
Cash and cash equivalents, beginning of period		245,979		23,473
Cash and cash equivalents, end of period	$	27,410		18,512

Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	116,579		132,928
Supplemental disclosure of noncash investing activities:
Decrease in accounts payable and accrued liabilities for additions to property and equipment	$	(193,288)		(189,234)

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

(1)Organization

(a)Business and Organization

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

(2)Summary of Significant Accounting Policies

(a)Basis of Presentation

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC applicable to interim financial information and should be read in the context of the December 31, 2015 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2015 consolidated financial statements have been filed with the SEC in the Company’s 2015 Form 10-K.

The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information, and, accordingly, do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, the accompanying unaudited condensed 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 September 30, 2016, the results of its operations for the three and nine months ended September 30, 2015 and 2016, and its cash flows for the nine months ended September 30, 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. Operating results for the period ended September 30, 2016 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas, NGLs, and oil, natural production declines, the uncertainty of exploration and development drilling results, fluctuations in the fair value of derivative instruments, and other factors.

The Company’s exploration and production activities are accounted for under the successful efforts method.

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 the following items:

On October 7, 2016, the Company issued 6,730,769 shares of the Company’s common stock in a private placement, resulting in gross proceeds of approximately $175 million. The Company used the proceeds to repay a portion of outstanding borrowings under its revolving credit facility and for general corporate purposes.

On October 12, 2016, Antero Midstream declared a distribution of $0.265 per unit that will be paid in November 2016.

As discussed in note 4(a), in October 2016 the borrowing base under the Company’s revolving credit facility was increased from $4.5 billion to $4.75 billion.

(b)Principles of Consolidation

The accompanying condensed consolidated financial statements include the accounts of Antero, its wholly-owned subsidiaries, any entities in which the Company owns a controlling interest, and variable interest entities for which the Company is the primary beneficiary. The Company consolidates Antero Midstream as it determined that it is the primary beneficiary based on its significant ownership interest in Antero Midstream, the significance of the Company’s activities to

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Antero Midstream, 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 condensed consolidated financial statements. Noncontrolling interest in the Company’s condensed consolidated financial statements represents the interests in Antero Midstream which are owned by the public and Antero Midstream’s general partner. An affiliate of the Company owns the general partner interest in Antero Midstream. Noncontrolling interest is included as a component of equity in the Company’s condensed 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 condensed consolidated balance sheets. Income from such investments is included in equity in earnings of unconsolidated affiliate on the Company’s condensed 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 condensed 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)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 a portion of 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 condensed 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 condensed consolidated statements of operations. The Company’s derivatives have not been designated as hedges for accounting purposes.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

(f)Industry Segments and Geographic Information

Management has evaluated how the Company is organized and managed and has identified the following segments: (1) the exploration and production of natural gas, NGLs, and oil; (2) gathering and compression; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity.

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.

(g)Earnings (Loss) per Common Share

Earnings (loss) per common share—basic for each period is computed by dividing net income (loss) attributable to Antero by the basic weighted average number of shares outstanding during 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. 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):


	Three months ended September 30,		Nine months ended September 30,
	2015	2016	2015	2016
Basic weighted average number of shares outstanding	277,007	306,785	273,145	288,607
Add: Dilutive effect of non-vested restricted stock units	8	1,835	9	—
Add: Dilutive effect of outstanding stock options	—	—	—	—
Add: Dilutive effect of performance stock units	—	37	—	—
Diluted weighted average number of shares outstanding	277,015	308,657	273,154	288,607

Weighted average number of outstanding equity awards excluded from calculation of diluted earnings per common share(1):
Non-vested restricted stock and restricted stock units	2,483	1,251	2,240	6,899
Outstanding stock options	743	693	492	706
Performance stock units	—	660	—	577

(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.

(h)Adoption of 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.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

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 condensed consolidated statement of cash flows for the nine months ended September 30, 2015 is as follows (in thousands):


	As Previously Reported				As Adjusted
	Nine Months Ended September 30, 2015		Adjustment Effect		Nine Months Ended September 30, 2015
Changes in accrued liabilities	$	29,537		4,554		34,091
Employee tax withholding for settlement of equity compensation awards		—		(4,554)		(4,554)

(3)Antero Midstream Partners LP

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, owns the general partnership interest in Antero Midstream, which allows Midstream Management to manage the business and affairs of Antero Midstream. Midstream Management also holds 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 12).

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 three months ended September 30, 2016, the Partnership issued and sold 764,739 common units under the Distribution Agreement, resulting in net proceeds of $19.6 million after deducting commissions and other offering costs. The Partnership used the net proceeds from the

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

sales for general partnership purposes. As of September 30, 2016, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $229.8 million.

Antero owned approximately 66.3% and 61.5% of the limited partner interests of Antero Midstream at December 31, 2015 and September 30, 2016, respectively.

(4)Long-Term Debt

Long-term debt was as follows at December 31, 2015 and September 30, 2016 (in thousands):


	December 31, 2015		September 30, 2016
Antero:
Bank credit facility(a)	$	707,000		605,000
6.00% senior notes due 2020(b)		525,000		525,000
5.375% senior notes due 2021(c)		1,000,000		1,000,000
5.125% senior notes due 2022(d)		1,100,000		1,100,000
5.625% senior notes due 2023(e)		750,000		750,000
Net unamortized premium		6,513		5,698
Net unamortized debt issuance costs		(39,731)		(35,560)
Antero Midstream:
Bank credit facility(g)		620,000		170,000
5.375% senior notes due 2024 (h)		—		650,000
Net unamortized debt issuance costs		—		(10,234)
	$	4,668,782		4,759,904

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 September 30, 2016, the borrowing base was $4.5 billion and lender commitments were $4.0 billion. In October 2016, the borrowing base was increased to $4.75 billion, and lender commitments remain at $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 September 30, 2016.

As of September 30, 2016, Antero had a total outstanding balance under the Credit Facility of $605 million, with a weighted average interest rate of 2.31%, and outstanding letters of credit of $709 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 $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 November 19, 2012, Antero issued $300 million of 6.00% senior notes due December 1, 2020 (the “2020 notes”) at par. On February 4, 2013, Antero issued an additional $225 million of the 2020 notes at 103% of par. The 2020 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2020 notes rank pari passu to Antero’s other outstanding senior notes. The 2020 notes are guaranteed on a full

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2020 notes is payable on June 1 and December 1 of each year. Antero may redeem all or part of the 2020 notes at any time at redemption prices ranging from 104.50% currently to 100.00% on or after December 1, 2018. If Antero undergoes a change of control, the holders of the 2020 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2020 notes, plus accrued and unpaid interest.

On November 5, 2013, Antero issued $1 billion of 5.375% senior notes due November 21, 2021 (the “2021 notes”) at par. The 2021 notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2021 notes rank pari passu to Antero’s other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by Antero’s wholly-owned subsidiaries and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. Antero may redeem all or part of the 2021 notes at any time on or after November 1, 2016 at redemption prices ranging from 104.031% on or after November 1, 2016 to 100.00% on or after November 1, 2019. In addition, on or before November 1, 2016, Antero may redeem up to 35% of the aggregate principal amount of the 2021 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2021 notes, plus accrued and unpaid interest. At any time prior to November 1, 2016, Antero may also redeem the 2021 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2021 notes plus a “make-whole” premium and accrued and unpaid interest. If Antero undergoes a change of control, the holders of the 2021 notes will have the right to require Antero to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2021 notes, plus accrued 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 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

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

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)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 September 30, 2016, there were no outstanding borrowings under this note

Antero Midstream Partners LP

(g)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 September 30, 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 September 30, 2016.

As of September 30, 2016, Antero Midstream had an outstanding balance under the Midstream Facility of $170 million with a weighted average interest rate of 2.03%. 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 portion based on utilization.

(h)5.375% Senior Notes Due 2024 – Antero Midstream

On September 13, 2016, Antero Midstream and its wholly-owned subsidiary, Antero Midstream Finance Corporation (“Midstream Finance Corp.”) as co-issuers, issued $650 million in aggregate principal amount of 5.375% senior notes due September 15, 2024 (the “2024 Midstream notes”) at par. The 2024 Midstream notes are unsecured and effectively subordinated to the Midstream 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.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

(5)Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2016 (in thousands):


Asset retirement obligations—December 31, 2015	$	30,612
Obligations incurred for wells drilled and producing properties acquired		3,945
Accretion expense		1,846
Asset retirement obligations—September 30, 2016	$	36,403

Asset retirement obligations are included in other liabilities on the condensed consolidated balance sheets.

(6)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 7,809,464 shares were available for future grant under the Plan as of September 30, 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 non-employee directors of Antero Midstream’s general partner and certain officers, employees, and consultants of Antero Midstream’s general partner and its affiliates (which include Antero). A total of 7,737,934 common units were available for future grant under the Midstream Plan as of September 30, 2016.

The Company’s equity-based compensation expense was as follows for the three and nine months ended September 30, 2015 and 2016 (in thousands):


	Three months ended September 30,				Nine months ended September 30,
	2015		2016		2015		2016
Profits interests awards	$	8,140		—	$	35,221		—
Restricted stock unit awards		10,686		18,618		29,357		54,231
Stock options		743		638		1,514		1,939
Performance share unit awards		—		2,668		—		6,017
Antero Midstream phantom unit awards		4,271		3,977		12,963		11,978
Equity awards issued to directors		75		480		225		1,502
Total expense	$	23,915		26,381	$	79,280		75,667

Profits Interests Awards

The profits interest awards were fully vested as of December 31, 2015. All available profits interest awards were made prior to the date of the Company’s IPO, and no additional profits interest awards have been made since the Company’s IPO.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

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 nine months ended September 30, 2016 is as follows:


		Weighted average		Aggregate
	Number of shares	grant date fair value		intrinsic value (in thousands)
Total awarded and unvested—December 31, 2015	6,529,459	$	33.48	$	142,342
Granted	1,228,587	$	27.05
Vested	(533,512)	$	55.37
Forfeited	(270,382)	$	26.70
Total awarded and unvested—September 30, 2016	6,954,152	$	30.92	$	187,414

Intrinsic values are based on the closing price of the Company’s stock on the referenced dates. Unamortized expense of $149.4 million at September 30, 2016 is expected to be recognized over a weighted average period of approximately 2.2 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 nine months ended September 30, 2016 is as follows:


				Weighted
		Weighted average		average remaining	Intrinsic
	Stock options	exercise price		contractual life	value (in thousands)
Outstanding at December 31, 2015	720,887	$	50.44	9.14	$	—
Granted	—	$	—
Exercised	—		—
Forfeited	(31,625)	$	50.00
Expired	—		—
Outstanding at September 30, 2016	689,262	$	50.46	8.37	$	—
Vested or expected to vest as of September 30, 2016	689,262	$	50.46	8.37	$	—
Exercisable at September 30, 2016	203,590	$	50.95	8.19	$	—

Intrinsic value is based on the exercise price of the options and the closing price of the Company’s stock on the referenced dates.

As of September 30, 2016, there was $6.0 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 2.5 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. These PSUs vest 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

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

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.

Summary Information for Performance Share Unit Awards

A summary of PSU activity for the nine months ended September 30, 2016 is as follows:


	Number of units	Weighted average grant date fair value
Total awarded and unvested—December 31, 2015	—	$	—
Granted	790,890	$	29.77
Vested	—	$	—
Forfeited	(5,589)	$	32.97
Total awarded and unvested—September 30, 2016	785,301	$	29.75

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 nine months ended September 30, 2016 and the assumptions used to determine the fair values.


	Nine months ended September 30, 2016
Dividend yield		—	%
Volatility		45	%
Risk-free interest rate		1.01	%
Weighted average fair value of awards granted	$	29.77

As of September 30, 2016, there was $17.3 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 2.2 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 nine months ended September 30, 2016 is as follows:

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016


	Number of units	Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total awarded and unvested—December 31, 2015	1,667,832	$	28.97	$	38,060
Granted	290,254	$	21.24
Vested	(6,354)	$	24.98
Forfeited	(97,723)	$	28.63
Total awarded and unvested—September 30, 2016	1,854,009	$	27.79	$	49,502

Intrinsic values are based on the closing price of Antero Midstream’s common units on the referenced dates. Unamortized expense of $37.5 million at September 30, 2016 is expected to be recognized over a weighted average period of approximately 2.3 years.

(7)Financial Instruments

The carrying values of accounts receivable and accounts payable at December 31, 2015 and September 30, 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 September 30, 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 $3.4 billion at September 30, 2016. Based on Level 2 market data inputs, the fair value of Antero Midstream’s senior notes was approximately $656 million at September 30, 2016.

See note 8 for information regarding the fair value of derivative financial instruments.

(8)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 nine months ended September 30, 2015 and 2016. The Company enters into these swap contracts when management believes that favorable future sales prices for the Company’s production can be secured. Under these swap agreements, when actual commodity prices 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. 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.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

As of September 30, 2016, the Company’s fixed price natural gas and NGLs swap contracts from October 1, 2016 through December 31, 2022 were as follows (abbreviations in the table refer to the index to which the swap position is tied, as follows: TCO=Columbia Gas Transmission; NYMEX=Henry Hub; CGTLA=Columbia Gas Louisiana Onshore; CCG=Chicago City Gate; Mont Belvieu-Ethane=Mont Belvieu Purity Ethane; Mont Belvieu-Propane=Mont Belvieu Propane; NYMEX-WTI=West Texas Intermediate):


	Natural gas MMbtu/day	Oil Bbls/day	Natural Gas Liquids Bbls/day	Weighted average index price
Three months ending December 31, 2016:
TCO ($/MMBtu)	60,000		—	$	5.01
Dominion South ($/MMBtu)	272,500		—	$	5.47
NYMEX ($/MMBtu)	1,110,000		—	$	3.57
CGTLA ($/MMBtu)	170,000		—	$	4.20
Mont Belvieu-Propane ($/Gallon)	—		30,000	$	0.61
Total	1,612,500		30,000
Year ending December 31, 2017:
NYMEX ($/MMBtu)	1,370,000	—	—	$	3.39
CGTLA ($/MMBtu)	420,000	—	—	$	4.27
CCG ($/MMBtu)	70,000	—	—	$	4.57
NYMEX-WTI ($/Bbl)	—	1,000	—	$	51.90
Mont Belvieu-Ethane ($/Gallon)	—	—	20,000	$	0.25
Mont Belvieu-Propane ($/Gallon)	—	—	27,500	$	0.39
Total	1,860,000	1,000	47,500
Year ending December 31, 2018:
NYMEX ($/MMBtu)	2,002,500		—	$	3.91
Mont Belvieu-Propane ($/Gallon)	—		2,000	$	0.65
Total	2,002,500		2,000
Year ending December 31, 2019:
NYMEX ($/MMBtu)	2,330,000			$	3.70
Year ending December 31, 2020:
NYMEX ($/MMBtu)	1,377,500			$	3.66
Year ending December 31, 2021:
NYMEX ($/MMBtu)	660,000			$	3.35
Year ending December 31, 2022:
NYMEX ($/MMBtu)	470,000			$	3.26

As of September 30, 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:

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

As of September 30, 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:

(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 September 30, 2016. None of the Company’s derivative instruments are designated as hedges for accounting purposes.


	December 31, 2015			September 30, 2016
	Balance sheet location	Fair value		Balance sheet location	Fair value
		(In thousands)			(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	1,009,030	Current assets	$	417,605
Commodity contracts	Long-term assets		2,108,450	Long-term assets		2,015,090

Total asset derivatives			3,117,480			2,432,695

Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities		—	Current liabilities		3,110
Commodity contracts	Long-term liabilities		—	Long-term liabilities		40

Total liability derivatives			—			3,150

Net derivatives		$	3,117,480		$	2,429,545

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						September 30, 2016
	Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets on balance sheet		Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts of assets (liabilities) on balance sheet
Commodity derivative assets	$	3,163,639		(46,159)		3,117,480	$	2,578,640		(145,945)		2,432,695
Commodity derivative liabilities	$	—		—		—	$	(3,183)		33		(3,150)

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

The following is a summary of derivative fair value gains and where such values are recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2015 and 2016 (in thousands):


	Statement of operations	Three months ended September 30,				Nine months ended September 30,
	location	2015		2016		2015		2016
Commodity derivative fair value gains	Revenue	$	1,079,071		530,334	$	1,836,398		125,624

The fair value of commodity derivative instruments was determined using Level 2 inputs.

(9)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 September 30, 2016, the Company estimates that it is owed approximately $51 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 maintains that the index price is no longer appropriate under the contracts and that an undefined alternative index is more appropriate for the delivery point of the gas. The matter has been submitted to arbitration. The Company believes that there is no basis for WGL’s position and intends to vigorously dispute the WGL claim in arbitration.

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.

(10)Contract Termination and Rig Stacking

During the nine months ended September 30, 2015, the Company incurred $10.9 million of costs, respectively, for the delay or cancelation of drilling contracts with third-party contractors. There were no such costs incurred during the nine months ended September 30, 2016.

(11)Segment Information

See note 2(f) for a description of the Company’s determination of its reportable segments. Revenues from gathering and compression and water handling and treatment operations are primarily derived from intersegment transactions for services provided to the Company’s exploration and production operations. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.

Operating segments are evaluated based on their contribution to consolidated results, which is determined by the respective operating income of each segment. General and administrative expenses are allocated to the gathering and compression and water handling and treatment segments based on 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

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

taxes, and interest expense are primarily managed and evaluated on a consolidated basis. Intersegment sales are transacted at prices which approximate market. Accounting policies for each segment are the same as the Company’s accounting policies described in note 2 to the condensed consolidated financial statements.

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2015 and 2016 (in thousands):


	Exploration and production		Gathering and compression	Water handling	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2015:
Sales and revenues:
Third-party	$	1,403,275	3,468	959	35,633	—	1,443,335
Intersegment		398	55,790	21,487	—	(77,675)	—
Total	$	1,403,673	59,258	22,446	35,633	(77,675)	1,443,335

Operating expenses:
Lease operating	$	10,721	—	3,973	—	(3,908)	10,786
Gathering, compression, processing, and transportation		211,469	4,699	—	—	(55,866)	160,302
Depletion, depreciation, and amortization		166,900	15,282	6,485	—	—	188,667
General and administrative expense		46,165	11,265	2,577	—	(322)	59,685
Other operating expenses		28,044	(7,863)	800	61,799	—	82,780
Total		463,299	23,383	13,835	61,799	(60,096)	502,220
Operating income (loss)	$	940,374	35,875	8,611	(26,166)	(17,579)	941,115
Segment assets	$	11,940,524	1,410,920	487,734	5,847	(267,951)	13,577,074
Capital expenditures for segment assets	$	399,695	82,768	45,151	—	(17,579)	510,035


	Exploration and production		Gathering and compression	Water handling	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2016:
Sales and revenues:
Third-party	$	1,016,458	2,745	224	97,076	—	1,116,503
Intersegment		3,990	75,319	72,187	—	(151,496)	—
Total	$	1,020,448	78,064	72,411	97,076	(151,496)	1,116,503

Operating expenses:
Lease operating	$	13,710	—	28,978	—	(28,834)	13,854
Gathering, compression, processing, and transportation		303,753	6,400	—	—	(75,238)	234,915
Depletion, depreciation, and amortization		172,735	18,540	7,838	—	—	199,113
General and administrative expense		44,637	10,282	3,033	—	(375)	57,577
Other operating expenses		31,266	(1,708)	3,070	114,611	(3,527)	143,712
Total		566,101	33,514	42,919	114,611	(107,974)	649,171
Operating income (loss)	$	454,347	44,550	29,492	(17,535)	(43,522)	467,332
Segment assets	$	12,966,493	1,669,667	562,995	33,114	(603,016)	14,629,253
Capital expenditures for segment assets	$	909,837	56,836	58,730	—	(43,343)	982,060

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2015 and 2016 (in thousands):


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2015:
Sales and revenues:
Third-party	$	2,891,410	8,433	6,651	143,242	—	3,049,736
Intersegment		1,025	159,661	80,886	—	(241,572)	—
Total	$	2,892,435	168,094	87,537	143,242	(241,572)	3,049,736

Operating expenses:
Lease operating	$	24,981	—	16,576	—	(15,996)	25,561
Gathering, compression, processing, and transportation		630,708	19,792	—	—	(159,867)	490,633
Depletion, depreciation, and amortization		483,991	45,255	18,767	—	—	548,013
General and administrative expense		140,821	30,685	7,238	—	(819)	177,925
Other operating expenses		113,881	25	2,437	214,201	—	330,544
Total		1,394,382	95,757	45,018	214,201	(176,682)	1,572,676
Operating income (loss)	$	1,498,053	72,337	42,519	(70,959)	(64,890)	1,477,060
Segment assets	$	11,940,524	1,410,920	487,734	5,847	(267,951)	13,577,074
Capital expenditures for segment assets	$	1,590,904	282,813	79,227	—	(64,890)	1,888,054


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2016:
Sales and revenues:
Third-party	$	1,291,008	9,463	644	287,194	—	1,588,309
Intersegment		11,714	210,144	203,106	—	(424,964)	—
Total	$	1,302,722	219,607	203,750	287,194	(424,964)	1,588,309

Operating expenses:
Lease operating	$	37,299	—	104,009	—	(104,118)	37,190
Gathering, compression, processing, and transportation		838,936	20,567	—	—	(209,790)	649,713
Depletion, depreciation, and amortization		513,302	52,780	21,975	—	—	588,057
General and administrative expense		135,356	29,755	9,957	—	(1,102)	173,966
Other operating expenses		104,279	(809)	11,568	378,521	(10,384)	483,175
Total		1,629,172	102,293	147,509	378,521	(325,394)	1,932,101
Operating income (loss)	$	(326,450)	117,314	56,241	(91,327)	(99,570)	(343,792)
Segment assets	$	12,966,493	1,669,667	562,995	33,114	(603,016)	14,629,253
Capital expenditures for segment assets	$	1,734,914	154,136	137,355	—	(98,955)	1,927,450

(12)Subsidiary Guarantors

Antero’s wholly-owned subsidiaries each have fully and unconditionally guaranteed Antero’s senior notes. Antero Midstream and its subsidiaries have been designated unrestricted subsidiaries under the Credit Facility and the indentures governing Antero’s senior notes, and do not guarantee any of Antero’s obligations (see note 4). In the event a subsidiary guarantor is sold or disposed of (whether by merger, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

“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 September 30, 2016, and the related Condensed Consolidating Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2015 and 2016 and Condensed Consolidating Statements of Cash Flows for the nine months ended September 30, 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.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Balance Sheets

December 31, 2015

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	16,590		—		6,883		—		23,473
Accounts receivable, net		76,697		—		2,707		—		79,404
Intercompany receivables		2,138		—		65,712		(67,850)		—
Accrued revenue		128,242		—		—		—		128,242
Derivative instruments		1,009,030		—		—		—		1,009,030
Other current assets		8,087		—		—		—		8,087
Total current assets		1,240,784		—		75,302		(67,850)		1,248,236
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,996,081		—		—		—		1,996,081
Proved properties		8,243,901		—		—		(32,795)		8,211,106
Water handling and treatment systems		—		—		565,616		—		565,616
Gathering systems and facilities		16,561		—		1,485,835		—		1,502,396
Other property and equipment		46,415		—		—		—		46,415
		10,302,958		—		2,051,451		(32,795)		12,321,614
Less accumulated depletion, depreciation, and amortization		(1,431,747)		—		(157,625)		—		(1,589,372)
Property and equipment, net		8,871,211		—		1,893,826		(32,795)		10,732,242
Derivative instruments		2,108,450		—		—		—		2,108,450
Investments in subsidiaries		(302,336)		—		—		302,336		—
Contingent acquisition consideration		178,049		—		—		(178,049)		—
Other assets, net		15,661		—		10,904		—		26,565
Total assets	$	12,111,819		—		1,980,032		23,642		14,115,493

Liabilities and Equity
Current liabilities:
Accounts payable	$	303,197		—		60,963		—		364,160
Intercompany payable		65,712		—		2,138		(67,850)		—
Accrued liabilities		158,713		—		35,363		—		194,076
Revenue distributions payable		129,949		—		—		—		129,949
Other current liabilities		18,935		—		150		—		19,085
Total current liabilities		676,506		—		98,614		(67,850)		707,270
Long-term liabilities:
Long-term debt		4,048,782		—		620,000		—		4,668,782
Deferred income tax liability		1,370,686		—		—		—		1,370,686
Contingent acquisition consideration		—		—		178,049		(178,049)		—
Other liabilities		81,453		—		624		—		82,077
Total liabilities		6,177,427		—		897,287		(245,899)		6,828,815
Equity:
Stockholders' equity:
Partners' capital		—		—		1,082,745		(1,082,745)		—
Common stock		2,770		—		—		—		2,770
Additional paid-in capital		4,122,811		—		—		—		4,122,811
Accumulated earnings		1,808,811		—		—		—		1,808,811
Total stockholders' equity		5,934,392		—		1,082,745		(1,082,745)		5,934,392
Noncontrolling interest in consolidated subsidiary		—		—		—		1,352,286		1,352,286
Total equity		5,934,392		—		1,082,745		269,541		7,286,678
Total liabilities and equity	$	12,111,819		—		1,980,032		23,642		14,115,493

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Balance Sheet

September 30, 2016

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	9,291		—		9,221		—		18,512
Accounts receivable, net		58,219		—		1,243		—		59,462
Intercompany receivables		2,237		—		58,398		(60,635)		—
Accrued revenue		196,490		—		—		—		196,490
Derivative instruments		417,605		—		—		—		417,605
Other current assets		3,349		—		53		—		3,402
Total current assets		687,191		—		68,915		(60,635)		695,471
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		2,449,995		—		—		—		2,449,995
Proved properties		9,312,455		—		—		(131,750)		9,180,705
Water handling and treatment systems		—		—		681,062		—		681,062
Gathering systems and facilities		17,928		—		1,638,748		—		1,656,676
Other property and equipment		45,571		—		—		—		45,571
		11,825,949		—		2,319,810		(131,750)		14,014,009
Less accumulated depletion, depreciation, and amortization		(1,945,069)		—		(231,724)		—		(2,176,793)
Property and equipment, net		9,880,880		—		2,088,086		(131,750)		11,837,216
Derivative instruments		2,015,090		—		—		—		2,015,090
Investments in subsidiaries		(375,986)		—		—		375,986		—
Contingent acquisition consideration		188,433		—		—		(188,433)		—
Other assets, net		22,190		—		59,286		—		81,476
Total assets	$	12,417,798		—		2,216,287		(4,832)		14,629,253

Liabilities and Equity
Current liabilities:
Accounts payable	$	122,220		—		50,073		—		172,293
Intercompany payable		58,398		—		2,237		(60,635)		—
Accrued liabilities		235,560		—		9,614		—		245,174
Revenue distributions payable		172,202		—		—		—		172,202
Derivative instruments		3,110		—		—		—		3,110
Other current liabilities		18,928		—		197		—		19,125
Total current liabilities		610,418		—		62,121		(60,635)		611,904
Long-term liabilities:
Long-term debt		3,950,138		—		809,766		—		4,759,904
Deferred income tax liability		1,215,240		—		—		—		1,215,240
Contingent acquisition consideration		—		—		188,433		(188,433)		—
Derivative instruments		40		—		—		—		40
Other liabilities		61,214		—		669		—		61,883
Total liabilities		5,837,050		—		1,060,989		(249,068)		6,648,971
Equity:
Stockholders' equity:
Partners' capital		—		—		1,155,298		(1,155,298)		—
Common stock		3,072		—		—		—		3,072
Additional paid-in capital		5,131,909		—		—		—		5,131,909
Accumulated earnings		1,445,767		—		—		—		1,445,767
Total stockholders' equity		6,580,748		—		1,155,298		(1,155,298)		6,580,748
Noncontrolling interest in consolidated subsidiary		—		—		—		1,399,534		1,399,534
Total equity		6,580,748		—		1,155,298		244,236		7,980,282
Total liabilities and equity	$	12,417,798		—		2,216,287		(4,832)		14,629,253

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2015

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
Natural gas sales	$	253,975		—		—		—		253,975
Natural gas liquids sales		50,092		—		—		—		50,092
Oil sales		20,138		—		—		—		20,138
Gathering, compression, and water handling and treatment		958		—		59,258		(55,790)		4,426
Marketing		35,633		—		—		—		35,633
Commodity derivative fair value losses		1,079,071		—		—		—		1,079,071
Other income		324		—		—		(324)		—
Total revenue		1,440,191		—		59,258		(56,114)		1,443,335
Operating expenses:
Lease operating		10,786		—		—		—		10,786
Gathering, compression, processing, and transportation		211,469		—		4,699		(55,866)		160,302
Production and ad valorem taxes		18,584		—		(7,863)		—		10,721
Marketing		61,799		—		—		—		61,799
Exploration		1,087		—		—		—		1,087
Impairment of unproved properties		8,754		—		—		—		8,754
Depletion, depreciation, and amortization		173,592		—		15,075		—		188,667
Accretion of asset retirement obligations		419		—		—		—		419
General and administrative		48,666		—		11,267		(248)		59,685
Total operating expenses		535,156		—		23,178		(56,114)		502,220
Operating income		905,035		—		36,080		—		941,115
Other income (expenses):
Interest		(59,647)		—		(1,274)		—		(60,921)
Equity in net income of subsidiaries		23,913		—		—		(23,913)		—
Total other expenses		(35,734)		—		(1,274)		(23,913)		(60,921)
Income before income taxes		869,301		—		34,806		(23,913)		880,194
Provision for income tax expense		(335,460)		—		—		—		(335,460)
Net income and comprehensive income including noncontrolling interest		533,841		—		34,806		(23,913)		544,734
Net income and comprehensive income attributable to noncontrolling interest		—		—		—		10,892		10,892
Net income and comprehensive income attributable to Antero Resources Corporation	$	533,841		—		34,806		(34,805)		533,842

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2016

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
Natural gas sales	$	364,373		—		—		—		364,373
Natural gas liquids sales		106,958		—		—		—		106,958
Oil sales		14,793		—		—		—		14,793
Gathering, compression, and water handling and treatment		—		—		150,475		(147,506)		2,969
Marketing		97,076		—		—		—		97,076
Commodity derivative fair value losses		530,334		—		—		—		530,334
Other income		3,990		—		—		(3,990)		—
Total revenue		1,117,524		—		150,475		(151,496)		1,116,503
Operating expenses:
Lease operating		13,710		—		28,978		(28,834)		13,854
Gathering, compression, processing, and transportation		303,753		—		6,400		(75,238)		234,915
Production and ad valorem taxes		17,719		—		(2,165)		—		15,554
Marketing		114,611		—		—		—		114,611
Exploration		1,166		—		—		—		1,166
Impairment of unproved properties		11,753		—		—		—		11,753
Depletion, depreciation, and amortization		172,976		—		26,137		—		199,113
Accretion of asset retirement obligations		628		—		—		—		628
General and administrative		44,637		—		13,315		(375)		57,577
Accretion of contingent acquisition consideration		—		—		3,527		(3,527)		—
Total operating expenses		680,953		—		76,192		(107,974)		649,171
Operating income		436,571		—		74,283		(43,522)		467,332
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—		—		1,543		—		1,543
Interest		(54,631)		—		(5,303)		179		(59,755)
Equity in net income (loss) of subsidiaries		(2,761)		—		—		2,761		—
Total other expenses		(57,392)		—		(3,760)		2,940		(58,212)
Income before income taxes		379,179		—		70,523		(40,582)		409,120
Provision for income tax expense		(140,924)		—		—		—		(140,924)
Net income and comprehensive income including noncontrolling interest		238,255		—		70,523		(40,582)		268,196
Net income and comprehensive income attributable to noncontrolling interest		—		—		—		29,941		29,941
Net income and comprehensive income attributable to Antero Resources Corporation	$	238,255		—		70,523		(70,523)		238,255

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Operations and Comprehensive Income

Nine Months Ended September 30, 2015

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
Natural gas sales	$	810,982		—		—		—		810,982
Natural gas liquids sales		188,403		—		—		—		188,403
Oil sales		55,627		—		—		—		55,627
Gathering, compression, and water handling and treatment		6,651		—		168,094		(159,661)		15,084
Marketing		143,242		—		—		—		143,242
Commodity derivative fair value gains		1,836,398		—		—		—		1,836,398
Other income		824		—		—		(824)		—
Total revenue		3,042,127		—		168,094		(160,485)		3,049,736
Operating expenses:
Lease operating		25,561		—		—		—		25,561
Gathering, compression, processing, and transportation		630,708		—		19,792		(159,867)		490,633
Production and ad valorem taxes		57,433		—		25		—		57,458
Marketing		214,201		—		—		—		214,201
Exploration		3,086		—		—		—		3,086
Impairment of unproved properties		43,670		—		—		—		43,670
Depletion, depreciation, and amortization		503,265		—		44,748		—		548,013
Accretion of asset retirement obligations		1,227		—		—		—		1,227
General and administrative		147,858		—		30,685		(618)		177,925
Contract termination and rig stacking		10,902		—		—		—		10,902
Total operating expenses		1,637,911		—		95,250		(160,485)		1,572,676
Operating income		1,404,216		—		72,844		—		1,477,060
Other income (expenses):
Interest		(170,989)		—		(2,940)		—		(173,929)
Equity in net income of subsidiaries		48,381		—		—		(48,381)		—
Total other expenses		(122,608)		—		(2,940)		(48,381)		(173,929)
Income before income taxes		1,281,608		—		69,904		(48,381)		1,303,131
Provision for income tax expense		(498,709)		—		—		—		(498,709)
Net income and comprehensive income including noncontrolling interest		782,899		—		69,904		(48,381)		804,422
Net income and comprehensive income attributable to noncontrolling interest		—		—		—		21,522		21,522
Net income and comprehensive income attributable to Antero Resources Corporation	$	782,899		—		69,904		(69,903)		782,900

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2016

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenue:
Natural gas sales	$	848,936		—		—		—		848,936
Natural gas liquids sales		274,736		—		—		—		274,736
Oil sales		41,712		—		—		—		41,712
Gathering, compression, and water handling and treatment		—		—		423,357		(413,250)		10,107
Marketing		287,194		—		—		—		287,194
Commodity derivative fair value gains		125,624		—		—		—		125,624
Other income		11,714		—		—		(11,714)		—
Total revenue		1,589,916		—		423,357		(424,964)		1,588,309
Operating expenses:
Lease operating		37,299		—		104,009		(104,118)		37,190
Gathering, compression, processing, and transportation		838,936		—		20,567		(209,790)		649,713
Production and ad valorem taxes		51,921		—		375		—		52,296
Marketing		378,521		—		—		—		378,521
Exploration		3,289		—		—		—		3,289
Impairment of unproved properties		47,223		—		—		—		47,223
Depletion, depreciation, and amortization		513,957		—		74,100		—		588,057
Accretion of asset retirement obligations		1,846		—		—		—		1,846
General and administrative		135,356		—		39,712		(1,102)		173,966
Accretion of contingent acquisition consideration		—		—		10,384		(10,384)		—
Total operating expenses		2,008,348		—		249,147		(325,394)		1,932,101
Operating income (loss)		(418,432)		—		174,210		(99,570)		(343,792)
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—		—		2,027		—		2,027
Interest		(173,364)		—		(12,885)		615		(185,634)
Equity in net income of subsidiaries		(2,003)		—		—		2,003		—
Total other expenses		(175,367)		—		(10,858)		2,618		(183,607)
Income (loss) before income taxes		(593,799)		—		163,352		(96,952)		(527,399)
Provision for income tax benefit		230,755		—		—		—		230,755
Net income (loss) and comprehensive income (loss) including noncontrolling interest		(363,044)		—		163,352		(96,952)		(296,644)
Net income and comprehensive income attributable to noncontrolling interest		—		—		—		66,400		66,400
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	(363,044)		—		163,352		(163,352)		(363,044)

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2015

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by operating activities	$	711,020		—		130,134		—		841,154
Cash flows used in investing activities:
Additions to unproved properties		(170,291)		—		—		—		(170,291)
Drilling and completion costs		(1,350,498)		—		—		—		(1,350,498)
Additions to water handling and treatment systems		(79,227)		—		—		—		(79,227)
Additions to gathering systems and facilities		(40,264)		—		(242,549)		—		(282,813)
Additions to other property and equipment		(5,225)		—		—		—		(5,225)
Change in other assets		307		—		10,883		—		11,190
Net distributions to guarantor subsidiary		(115,000)		—		—		115,000		—
Distributions from non-guarantor subsidiary		49,161		—		—		(49,161)		—
Proceeds from contribution of assets to non-guarantor subsidiary		804,630		—		—		(804,630)		—
Proceeds from asset sales		40,000		—		—		—		40,000
Net cash used in investing activities		(866,407)		—		(231,666)		(738,791)		(1,836,864)
Cash flows provided by (used in) financing activities:
Issuance of common stock		537,832		—		—		—		537,832
Issuance of common units by Antero Midstream Partners LP		—		—		240,972		—		240,972
Issuance of senior notes		750,000		—		—		—		750,000
Borrowings (repayments) on bank credit facility, net		(1,115,000)		(115,000)		525,000		—		(705,000)
Payments of deferred financing costs		(15,234)		—		(1,956)		—		(17,190)
Distributions		—		115,000		(875,149)		738,791		(21,358)
Employee tax withholding for settlement of equity compensation awards		(4,554)		—		—		—		(4,554)
Other		(3,544)		—		(17)		—		(3,561)
Net cash provided by (used in) financing activities		149,500		—		(111,150)		738,791		777,141
Net decrease in cash and cash equivalents		(5,887)		—		(212,682)		—		(218,569)
Cash and cash equivalents, beginning of period		15,787		—		230,192		—		245,979
Cash and cash equivalents, end of period	$	9,900		—		17,510		—		27,410

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2016

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations		Consolidated
Net cash provided by operating activities	$	745,517		—		259,135		(98,955)		905,697
Cash flows used in investing activities:
Additions to proved properties		(64,789)		—		—		—		(64,789)
Additions to unproved properties		(559,572)		—		—		—		(559,572)
Drilling and completion costs		(1,108,806)		—		—		98,955		(1,009,851)
Additions to water handling and treatment systems		—		—		(137,355)		—		(137,355)
Additions to gathering systems and facilities		(1,367)		—		(152,769)		—		(154,136)
Additions to other property and equipment		(1,747)		—		—		—		(1,747)
Investments in unconsolidated affiliates		—		—		(45,044)		—		(45,044)
Change in other assets		236		—		(2,409)		—		(2,173)
Net distributions from subsidiaries		78,514		—		—		(78,514)		—
Net cash used in investing activities		(1,657,531)		—		(337,577)		20,441		(1,974,667)
Cash flows provided by financing activities:
Issuance of common stock		837,414		—		—		—		837,414
Issuance of common units by Antero Midstream Partners LP		—		—		19,605		—		19,605
Sale of common units in Antero Midstream Partners LP by Antero Resources Corporation		178,000		—		—		—		178,000
Issuance of senior notes		—		—		650,000		—		650,000
Repayments on bank credit facility, net		(102,000)		—		(450,000)		—		(552,000)
Payments of deferred financing costs		(89)		—		(8,940)		—		(9,029)
Distributions		—		—		(129,752)		78,514		(51,238)
Employee tax withholding for settlement of equity compensation awards		(4,859)		—		(17)		—		(4,876)
Other		(3,751)		—		(116)		—		(3,867)
Net cash provided by financing activities		904,715		—		80,780		78,514		1,064,009
Net increase (decrease) in cash and cash equivalents		(7,299)		—		2,338		—		(4,961)
Cash and cash equivalents, beginning of period		16,590		—		6,883		—		23,473
Cash and cash equivalents, end of period	$	9,291		—		9,221		—		18,512

(13)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 September 30, 2016 (in millions):


	Firm transportation		Processing, gathering and compression		Drilling rigs and completion services		Office and equipment
	(a)		(b)		(c)		(d)		Total
Remainder of 2016	$	119		88		27		3		237
2017		709		370		101		13		1,193
2018		935		286		98		12		1,331
2019		1,086		230		60		9		1,385
2020		1,105		230		—		7		1,342
2021		1,084		224		—		7		1,315
Thereafter		10,469		951		—		25		11,445
Total	$	15,507		2,379		286		76		18,248

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2015 and September 30, 2016

(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.

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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, availability of acquisitions, our ability to close acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. For more information, please refer to the Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 24, 2016.

In this section, references to “Antero,” “the Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

Our Company

Antero Resources Corporation is an independent oil and natural gas company engaged in the exploration, development, and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year project inventory of drilling locations.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. As of September 30, 2016, we held approximately 618,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. Our corporate headquarters are in Denver, Colorado.

We operate in the following industry segments: (i) the exploration and production of natural gas, NGLs, and oil; (ii) gathering and compression; (iii) water handling and treatment; and (iv) marketing of excess firm transportation capacity. All of our operations are conducted in the United States.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are at 1615 Wynkoop Street, Denver, Colorado 80202. Our telephone number is (303) 357-7310. Our website is located at www.anteroresources.com.

We make available free of charge our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. These documents are located www.anteroresources.com under the “Investors Relations” link.

Information on our website is not incorporated into this Quarterly Report on Form 10-Q or our other filings with the SEC and is not a part of them.

2016 Developments and Highlights

Energy Industry Environment

In late 2014, global energy commodity prices declined precipitously as a result of several factors, including an increase in worldwide commodity supplies, a stronger U.S. dollar, relatively mild weather in large portions of the U.S. during winter months, and

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strong competition among oil producing countries for market share. These events continued throughout 2015 and into 2016 and, along with slower economic growth in China, have led to the continuation of low commodity prices. Spot prices for WTI declined significantly since June 2014 levels of approximately $106.00 per Bbl and have ranged from less than $30.00 per Bbl in February 2016 to approximately $45.00 per Bbl in September 2016. Spot prices for Henry Hub natural gas have also declined significantly from approximately $4.40 per MMBtu in January 2014 and have ranged from approximately $2.00 per MMBtu in March 2016 to approximately $3.00 per MMBtu in September 2016. Spot prices for propane, which is the largest portion of our NGLs sales, have declined from approximately $1.55 per gallon in January 2014 and have ranged from less than $0.35 per gallon in January 2016 to approximately $0.50 per gallon in September 2016.

In response to these market conditions and concerns about access to capital markets, many U.S. exploration and production companies significantly reduced their capital spending plans in 2015, and further reduced their capital spending plans for 2016. Our capital budget for drilling, completions, and land in 2016 is $1.4 billion, a 24% reduction from our 2015 capital expenditures. Our 2016 budget includes plans to operate an average of 7 drilling rigs in 2016 as compared to an average of 14 rigs in 2015, completion of 110 horizontal wells in the Marcellus and Utica Shales in 2016 as compared to 131 in 2015, and deferring the completion of 70 wells until 2017.

We believe that our 2016 capital budget will be fully funded through operating cash flows, available borrowing capacity under our revolving credit facility, and potential capital market transactions. We will continually monitor commodity prices and may revise the capital budget if conditions warrant. Additionally, given the current commodity price environment, we have evaluated the carrying value of our proved properties. See “—Critical Accounting Policies and Estimates” for a discussion of such evaluation.

Production and Financial Results

For the three months ended September 30, 2016, we generated cash flow from operations of $327 million, net income of $238 million, and Adjusted EBITDAX of $373 million. This compares to cash flow from operations of $246 million, net income of $534 million, and Adjusted EBITDAX of $291 million for the three months ended September 30, 2015. Net income of $238 million for the three months ended September 30, 2016 included (i) commodity derivative fair value gains of $530 million, comprised of gains on settled derivatives of $197 million and gains of $333 million on changes in the fair value of commodity derivatives, (ii) a noncash charge of $26 million for equity-based compensation, (iii) a noncash charge of $12 million for impairments of unproved properties, and (iv) a noncash deferred tax expense of $141 million. See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income.

For the three months ended September 30, 2016, our production totaled approximately 172 Bcfe, or 1,875 MMcfe per day, a 25% increase compared to 139 Bcfe, or 1,506 MMcfe per day, for the three months ended September 30, 2015. The average price received for production for the three months ended September 30, 2016 was $2.82 per Mcfe before the effects of gains on settled derivatives compared to $2.34 per Mcfe for the three months ended September 30, 2015. Average prices including the effects of gains on settled derivatives were $3.96 per Mcfe for the three months ended September 30, 2016 compared to $3.83 per Mcfe for the three months ended September 30, 2015.

For the nine months ended September 30, 2016, we generated cash flow from operations of $906 million, a net loss of $363 million, and Adjusted EBITDAX of $1.06 billion. This compares to cash flow from operations of $841 million, net income of $783 million, and Adjusted EBITDAX of $914 million for the nine months ended September 30, 2015. The net loss of $363 million for the nine months ended September 30, 2016 included (i) commodity derivative fair value gains of $126 million, comprised of gains on settled derivative of $814 million and a loss of $688 million on changes in the fair value of commodity derivatives, (ii) a noncash charge of $76 million for equity-based compensation, (iii) a noncash charge of $47 million for impairments of unproved properties, and (iv) a noncash deferred tax benefit of $231 million. See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income.

For the nine months ended September 30, 2016, our production totaled approximately 493 Bcfe, or 1,799 MMcfe per day, a 21% increase compared to 407 Bcfe, or 1,492 MMcfe per day, for the nine months ended September 30, 2015. The average price received for production for the nine months ended September 30, 2016 was $2.36 per Mcfe before the effects of gains on settled derivatives compared to $2.59 per Mcfe for the nine months ended September 30, 2015. Average prices including the effects of gains on settled derivatives were $4.02 per Mcfe for the nine months ended September 30, 2016 compared to $4.03 per Mcfe for the nine months ended September 30, 2015.

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Hedge Position

As of September 30, 2016, we had entered into hedging contracts for October 1, 2016 through December 31, 2022 for approximately 3.3 Tcf of our projected natural gas production at a weighted average index price of $3.69 per MMbtu, 568 million gallons of propane at a weighted average price of $0.45 per gallon, and 307 million gallons of ethane at a weighted average price of $0.25 per gallon. These hedging contracts include contracts for the remaining three months ended December 31, 2016 of approximately 148 Bcf of natural gas at a weighted average index price of $4.01 per Mcf and 116 million gallons of propane at a weighted average price of $0.61 per gallon.

Credit Facilities

As of September 30, 2016, the borrowing base under our revolving credit facility was $4.5 billion and lender commitments were $4.0 billion. The borrowing base under our revolving credit facility is redetermined semi-annually and is based on the estimated future cash flows from our proved oil and gas reserves and our commodity hedge positions. In October 2016, the borrowing base was increased to $4.75 billion, and lender commitments remain at $4.0 billion. The next redetermination is scheduled to occur in April 2017. At September 30, 2016, we had $605 million of borrowings and $709 million of letters of credit outstanding under the revolving credit facility. Our revolving credit facility matures in May 2019. See “—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of our revolving credit facility.

Our consolidated subsidiary, Antero Midstream, has a revolving credit facility agreement that provides for lender commitments of $1.5 billion. At September 30, 2016, Antero Midstream had $170 million of borrowings outstanding under its revolving credit facility. The facility will mature in November 2019. See “—Debt Agreements and Contractual Obligations—Midstream Credit Facility” for a description of this revolving credit facility.

Issuance of 5.375% Notes due 2024 by Antero Midstream

On September 13, 2016, Antero Midstream issued $650 million of 5.375% senior notes due September 15, 2024 at par. The proceeds from the issuance were used by Antero Midstream to pay down amounts outstanding under its revolving credit facility.

Equity Distribution Agreement

During the three months ended September 30, 2016, the Partnership issued and sold 764,739 common units under the Distribution Agreement, resulting in net proceeds of $19.6 million after deducting commissions and other offering expenses. As of September 30, 2016, Antero Midstream had the capacity to issue additional common units under the Distribution Agreement up to an aggregate sales price of $229.8 million.

2016 Capital Budget

Our capital budget for drilling, completions, and land for 2016 is $1.4 billion and includes: $1.3 billion for drilling and completion and $100 million for core leasehold acreage costs. We do not budget for acquisitions. Approximately 75% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 25% is allocated to the Utica Shale. Over the course of 2016, we plan to operate an average of 5 drilling rigs in the Marcellus Shale and 2 drilling rigs in the Utica Shale. Additionally, the capital budget for Antero Midstream for 2016 is $480 million. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices. For the nine months ended September 30, 2016, our consolidated capital expenditures were approximately $1.9 billion, including drilling and completion costs of $1.0 billion, $560 million of leasehold costs (including $518 million for an acquisition), $65 million for acquisitions of producing properties, gathering and compression costs of Antero Midstream of $154 million, water handling and treatment costs of Antero Midstream of $137 million, and other capital expenditures of $2 million.

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Results of Operations

Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2016

The Company has four operating segments: (1) the exploration and production of natural gas, NGLs, and oil; (2) gathering and compression; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity. Revenues from the gathering and compression and water handling and treatment segments are primarily derived from intersegment transactions for services provided to our exploration and production segment by Antero Midstream. Intersegment transactions that are eliminated include revenues from water services provided by Antero Midstream which are capitalized as proved property development costs by Antero. 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. The operating results of the Company’s reportable segments were as follows for the three months ended September 30, 2015 and 2016 (in thousands):


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2015:
Sales and revenues:
Third-party	$	1,403,275	3,468	959	35,633	—	1,443,335
Intersegment		398	55,790	21,487	—	(77,675)	—
Total	$	1,403,673	59,258	22,446	35,633	(77,675)	1,443,335

Operating expenses:
Lease operating	$	10,721	—	3,973	—	(3,908)	10,786
Gathering, compression, processing, and transportation		211,469	4,699	—	—	(55,866)	160,302
Depletion, depreciation, and amortization		166,900	15,282	6,485	—	—	188,667
General and administrative expense (before equity-based compensation)		27,534	7,060	1,498	—	(322)	35,770
Equity-based compensation expense		18,631	4,205	1,079	—	—	23,915
Other operating expenses		28,044	(7,863)	800	61,799	—	82,780
Total		463,299	23,383	13,835	61,799	(60,096)	502,220
Operating income (loss)	$	940,374	35,875	8,611	(26,166)	(17,579)	941,115

Segment Adjusted EBITDAX (1)		263,015	55,362	16,175	(26,166)	(17,579)	290,807

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	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2016:
Sales and revenues:
Third-party	$	1,016,458	2,745	224	97,076	—	1,116,503
Intersegment		3,990	75,319	72,187	—	(151,496)	—
Total	$	1,020,448	78,064	72,411	97,076	(151,496)	1,116,503

Operating expenses:
Lease operating	$	13,710	—	28,978	—	(28,834)	13,854
Gathering, compression, processing, and transportation		303,753	6,400	—	—	(75,238)	234,915
Depletion, depreciation, and amortization		172,735	18,540	7,838	—	—	199,113
General and administrative expense (before equity-based compensation)		24,856	5,068	1,647	—	(375)	31,196
Equity-based compensation expense		19,781	5,214	1,386	—	—	26,381
Other operating expenses		31,266	(1,708)	3,070	114,611	(3,527)	143,712
Total		566,101	33,514	42,919	114,611	(107,974)	649,171
Operating income (loss)	$	454,347	44,550	29,492	(17,535)	(43,522)	467,332

Segment Adjusted EBITDAX (1)		323,261	68,304	42,243	(17,535)	(43,522)	372,751

(1)

See “—Non-GAAP Financial Measure” for a definition of Segment Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Segment Adjusted EBITDAX to operating income (loss).

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The following tables set forth selected operating data for the three months ended September 30, 2015 compared to the three months ended September 30, 2016:


	Three Months Ended September 30,				Amount of Increase		Percent
(in thousands)	2015		2016		(Decrease)		Change
Operating revenues:
Natural gas sales	$	253,975	$	364,373	$	110,398	43	%
NGLs sales		50,092		106,958		56,866	114	%
Oil sales		20,138		14,793		(5,345)	(27)	%
Gathering, compression, and water handling and treatment		4,426		2,969		(1,457)	(33)	%
Marketing		35,633		97,076		61,443	172	%
Commodity derivative fair value gains		1,079,071		530,334		(548,737)	(51)	%
Total operating revenues		1,443,335		1,116,503		(326,832)	(23)	%
Operating expenses:
Lease operating		10,786		13,854		3,068	28	%
Gathering, compression, processing, and transportation		160,302		234,915		74,613	47	%
Production and ad valorem taxes		10,721		15,554		4,833	45	%
Marketing		61,799		114,611		52,812	85	%
Exploration		1,087		1,166		79	7	%
Impairment of unproved properties		8,754		11,753		2,999	34	%
Depletion, depreciation, and amortization		188,667		199,113		10,446	6	%
Accretion of asset retirement obligations		419		628		209	50	%
General and administrative (before equity-based compensation)		35,770		31,196		(4,574)	(13)	%
Equity-based compensation		23,915		26,381		2,466	10	%
Total operating expenses		502,220		649,171		146,951	29	%
Operating income		941,115		467,332		(473,783)	(50)	%

Other earnings (expenses):
Equity in earnings of unconsolidated affiliate		—		1,543		1,543	*
Interest expense		(60,921)		(59,755)		1,166	(2)	%
Income before income taxes		880,194		409,120		(471,074)	(54)	%
Income tax expense		(335,460)		(140,924)		194,536	(58)	%
Net income and comprehensive income including noncontrolling interest		544,734		268,196		(276,538)	(51)	%
Net income and comprehensive income attributable to noncontrolling interest		10,892		29,941		19,049	175	%
Net income and comprehensive income attributable to Antero Resources Corporation	$	533,842	$	238,255	$	(295,587)	(55)	%

Adjusted EBITDAX (1)	$	290,807	$	372,751	$	81,944	28	%

(1)

See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income including noncontrolling interest and net cash provided by operating activities.

*Not meaningful or applicable.

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	Three Months Ended September 30,				Amount of Increase		Percent
	2015		2016		(Decrease)		Change
Production data:
Natural gas (Bcf)		110		128		18	16	%
C2 Ethane (MBbl)		—		1,801		1,801	*
C3+ NGLs (MBbl)		4,147		5,270		1,123	27	%
Oil (MBbl)		660		423		(237)	(36)	%
Combined (Bcfe)		139		172		33	25	%
Daily combined production (MMcfe/d)		1,506		1,875		369	25	%
Average prices before effects of derivative settlements(2):
Natural gas (per Mcf)	$	2.32	$	2.86	$	0.54	23	%
C2 Ethane (per Bbl)	$	—	$	8.00	$	*	*
C3+ NGLs (per Bbl)	$	12.08	$	17.56	$	5.48	45	%
Oil (per Bbl)	$	30.49	$	34.93	$	4.44	15	%
Combined (per Mcfe)	$	2.34	$	2.82	$	0.48	21	%
Average realized prices after effects of derivative settlements(2):
Natural gas (per Mcf)	$	3.99	$	4.30	$	0.31	8	%
C2 Ethane (per Bbl)	$	—	$	8.00	$	*	*
C3+ NGLs (per Bbl)	$	16.47	$	19.96	$	3.49	21	%
Oil (per Bbl)	$	38.18	$	34.93	$	(3.25)	(9)	%
Combined (per Mcfe)	$	3.83	$	3.96	$	0.13	3	%
Average Costs (per Mcfe):
Lease operating	$	0.08	$	0.08	$	—	*
Gathering, compression, processing, and transportation	$	1.16	$	1.36	$	0.20	17	%
Production and ad valorem taxes	$	0.08	$	0.09	$	0.01	13	%
Marketing, net	$	0.19	$	0.10	$	(0.09)	(47)	%
Depletion, depreciation, amortization, and accretion	$	1.37	$	1.16	$	(0.21)	(15)	%
General and administrative (before equity-based compensation)	$	0.26	$	0.18	$	(0.08)	(31)	%

(2)

Average sales prices shown in the table reflect both the before and after effects of our settled derivatives. Our calculation of such after effects includes gains on settlements of derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

Discussion of Consolidated Exploration and Production Results for the Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2016

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $324 million for the three months ended September 30, 2015 to $486 million for the three months ended September 30, 2016, an increase of $162 million, or 50%. Our production increased by 25% over that same period, from 139 Bcfe, or 1,506 MMcfe per day, for the three months ended September 30, 2015 to 172 Bcfe, or 1,875 MMcfe per day, for the three months ended September 30, 2016. Net equivalent prices before the effects of settled derivative gains increased from $2.34 per Mcfe for the three months ended September 30, 2015 to $2.82 for the three months ended September 30, 2016, an increase of 21%. Prices for natural gas, C3+ NGLs, and oil all increased from 2015. Net equivalent prices after the effects of gains on settled derivatives increased from $3.83 for the three months ended September 30, 2015 to $3.96 for the three months ended September 30, 2016, an increase of 3%.

Increased production volumes accounted for an approximate $80 million increase in year-over-year product revenues (calculated as the combined change in year-to-year volumes times the prior year average price), and changes in our equivalent prices accounted for an approximate $82 million increase in year-over-year product revenues (calculated as the change in year-to-year average price times current year production volumes). Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion program.

Commodity derivative fair value gains. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment, and all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the three months ended September 30, 2015 and 2016, our hedges resulted in derivative fair value gains of $1.1 billion and $530 million, respectively. The derivative fair value gains included $206 million and $197 million of gains on settled derivatives for the three months ended September 30, 2015 and 2016, respectively. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts

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are settled. Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas and NGLs futures prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Gathering, compression, and water handling and treatment revenues. Gathering, compression, and water handling and treatment revenues decreased from $4 million for the three months ended September 30, 2015 to $3 million for the three months ended September 30, 2016, primarily attributable to the provision of fresh water distribution services to wells in which we hold a higher working interest than the wells to which such services were provided in 2015. Fees for water distribution services provided to us by Antero Midstream are eliminated in consolidation. The amounts that are not eliminated represent the portion of such fees that are charged to outside working interest owners in Company-operated wells, as well as fees charged to other third parties for services provided by Antero Midstream.

Lease operating expense. Lease operating expenses increased from $11 million for the three months ended September 30, 2015 to $14 million for the three months ended September 30, 2016, an increase of 28%. The increase is primarily a result of an increase in the number of producing wells. On a per unit basis, lease operating expenses remained flat at $0.08 per Mcfe for the three months ended September 30, 2015 and 2016. Lease operating expenses are expected to slowly increase on a per unit basis as mature properties make up a larger proportion of our production base and average production per well declines.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expenses increased from $160 million for the three months ended September 30, 2015 to $235 million for the three months ended September 30, 2016. The increase in these expenses is a result of the increase in production and the related firm transportation costs and third-party gathering, compression, and processing expenses. On a per Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.16 per Mcfe for the three months ended September 30, 2015 to $1.36 for the three months ended September 30, 2016, primarily due to higher transportation costs incurred on new pipelines that were placed in service in late 2015. Substantially all of the new pipelines currently deliver our gas to better price indices or sales contracts resulting in higher realized gas prices for the period.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $11 million for the three months ended September 30, 2015 to $16 million for the three months ended September 30, 2016, primarily as a result of an increase in production revenues. On a per Mcfe basis, production and ad valorem taxes increased from $0.08 per Mcfe for the three months ended September 30, 2015 to $0.09 per Mcfe for the three months ended September 30, 2016. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging decreased from 3.3% for the three months ended September 30, 2015 to 3.2% for the three months ended September 30, 2016. The termination of the workman’s compensation portion of the West Virginia production tax resulted in an approximately $5 million reduction in production taxes for the three months ended September 30, 2016. Ad valorem taxes for the same period in 2015 were reduced for a change in estimated taxes due; as a result, total production and ad valorem taxes as a percent of revenues is relatively unchanged for 2016 compared to 2015.

Exploration expense. Exploration expense remained consistent at $1 million for the three months ended September 30, 2015 and 2016. These amounts represent expenses incurred for unsuccessful lease acquisitions.

Impairment of unproved properties. Impairment of unproved properties increased from $9 million for the months ended September 30, 2015 to $12 million for the three months ended September 30, 2016. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, or future plans to develop the acreage.

Depletion, depreciation, and amortization. Depletion, depreciation, and amortization (“DD&A”) increased from $189 million for the three months ended September 30, 2015 to $199 million for the three months ended September 30, 2016, primarily because of increased production. DD&A per Mcfe decreased by 15%, from $1.37 per Mcfe during the three months ended September 30, 2015 to $1.16 per Mcfe during the three months ended September 30, 2016, primarily due to decreases in our per-unit development costs, in part due to recent well cost reductions and drilling and completion efficiencies that we have achieved.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances (such as the decline in commodity prices since late 2014) indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeded the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we would further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. Due to the commodity price environment at September 30, 2016, we compared the carrying values of our proved properties to estimated future net cash

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flows. As estimated future net cash flows remained higher than the carrying value of our proved properties at September 30, 2016, we did not further evaluate our proved properties for impairment.

General and administrative and equity-based compensation expense. General and administrative expense (before equity-based compensation expense) decreased from $36 million for the three months ended September 30, 2015 to $31 million for the three months ended September 30, 2016, primarily as a result of decreases in legal costs that were incurred in connection with the sale of Antero’s water handling and treatment assets to Antero Midstream during the three months ended September 30, 2015. On a per unit basis, general and administrative expense before equity-based compensation decreased by 31%, from $0.26 per Mcfe during the three months ended September 30, 2015 to $0.18 per Mcfe during the three months ended September 30, 2016, primarily due to our 25% increase in production as well as the overall decreases in general and administrative costs. We had 482 employees as of September 30, 2015 and 516 employees as of September 30, 2016.

Noncash equity-based compensation expense increased from $24 million for the three months ended September 30, 2015 to $26 million for the three months ended September 30, 2016 as a result of an $8 million increase in equity-based compensation related to restricted stock unit awards and a $2 million increase in equity-based compensation related to performance share unit, stock option, and Antero Midstream phantom unit awards, partially offset by an $8 million decrease in amortization of expense related to the vesting of profits interests that became fully vested in October 2015. See note 6 to the condensed consolidated financial statements included elsewhere in this report for more information on equity-based compensation awards.

Equity in earnings of unconsolidated affiliate. In May 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline. Equity in earnings of unconsolidated affiliate of $1.5 million for the three months ended September 30, 2016 represents the portion of the pipeline’s net income which is allocated to Antero Midstream based on its equity interest in the pipeline. The Company did not hold any unconsolidated equity investments during the three months ended September 30, 2015.

Interest expense. Interest expense decreased slightly from $61 million for the three months ended September 30, 2015 to $60 million for the three months ended September 30, 2016, primarily due to decreased average indebtedness outstanding under our revolving credit facilities. Interest expense includes approximately $2.6 million and $2.9 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2015 and 2016, respectively.

Income tax expense. Income tax expense decreased from $335 million for the three months ended September 30, 2015 to $141 million for the three months ended September 30, 2016 because of the decrease in our pre-tax income compared to the prior year period. The effect of state tax rates, state tax apportionment, and the noncontrolling interest in Antero Midstream largely account for the difference between the federal tax rate of 35% and the rate at which income tax expense was provided for the three months ended September 30, 2016.

At December 31, 2015, we had approximately $1.4 billion of U.S. federal NOLs and approximately $1.2 billion of state NOLs, which expire from 2024 through 2035. From time to time there has been proposed legislation in the U.S. Congress to eliminate or limit future deductions for intangible drilling costs. Such legislation could significantly affect our future taxable position, if passed. The impact of any change will be recorded in the period that any such legislation might be enacted.

Adjusted EBITDAX. Adjusted EBITDAX increased by 28%, from $291 million for the three months ended September 30, 2015 to $373 million for the three months ended September 30, 2016. The increase in Adjusted EBITDAX was primarily due to a 25% increase in production, as well as a 3% increase in the average per Mcfe price received after the impact of cash settled derivatives, partially offset by increases in cash operating and gathering, compression, processing, and transportation expenses. See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income from continuing operations including noncontrolling interest and net cash provided by operating activities.

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Discussion of Segment Results for the Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2016

Gathering and Compression. Revenue for the gathering and compression segment increased from $59 million for the three months ended September 30, 2015 to $78 million for the three months ended September 30, 2016, an increase of $19 million, or 32%. Gathering revenues increased by $13 million from the prior year period and compression revenues increased by $6 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and compression segment increased from $23 million for the three months ended September 30, 2015 to $34 million for the three months ended September 30, 2016 primarily as a result of increased throughput volumes and increases in depreciation expense due to a larger base of gathering and compression assets.

Water Handling and Treatment. Revenue for the water handling and treatment segment increased from $22 million for the three months ended September 30, 2015 to $72 million for the three months ended September 30, 2016, an increase of $50 million, or 223%. The increase was primarily due to revenues generated from waste water treatment services that commenced in the fourth quarter of 2015, as well as increased use of the water systems as a result of increased completion activity. The volume of water delivered through the systems increased from 6.2 MMBbls for the three months ended September 30, 2015 to 12.9 MMBbls for the three months ended September 30, 2016. Operating expenses for the water handling and treatment segment increased from $14 million for the three months ended September 30, 2015 to $43 million for the three months ended September 30, 2016 as a result of expenses related to waste water treatment services, accretion expense related to the contingent acquisition consideration payable by Antero Midstream in connection with Antero’s dropdown of its water handling and treatment assets to Antero Midstream in September 2015, and an increase in depreciation expense due to an increase in fresh water distribution assets.

Marketing. Where permitted, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Marketing revenues of $36 million and $97 million and expenses of $62 million and $115 million for the three months ended September 30, 2015 and 2016, respectively, relate to these activities. Net losses on our marketing activities were $26 million and $18 million for the three months ended September 30, 2015 and 2016, respectively. Marketing costs include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs. This includes firm transportation costs of $30 million and $24 million for the three months ended September 30, 2015 and 2016, respectively, related to unutilized excess capacity which decreased due to our release of certain unutilized firm transportation capacity to a third party beginning July 1, 2016, partially offset by costs incurred under new transportation agreements. Based on current projections for our 2016 annual production levels, we estimate that we could incur total annual net marketing expense of $100 million to $130 million in 2016 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials between various indices. In years subsequent to 2016, our commitments and obligations under firm transportation agreements continue to increase. As a result, our net marketing expense could continue to increase depending on our utilization of our transportation capacity based on future production and how much, if any, future excess transportation can be marketed to third parties.

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Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2016

The Company has four operating segments: (1) the exploration and production of natural gas, NGLs, and oil; (2) gathering and compression; (3) water handling and treatment; and (4) marketing of excess firm transportation capacity. Revenues from the gathering and compression and water handling and treatment segments are primarily derived from intersegment transactions for services provided to our exploration and production segment by Antero Midstream. Intersegment transactions that are eliminated include revenues from water services provided by Antero Midstream which are capitalized as proved property development costs by Antero. 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. The operating results of the Company’s reportable segments, including Segment Adjusted EBITDAX, were as follows for the nine months ended September 30, 2015 and 2016 (in thousands):


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2015:
Sales and revenues:
Third-party	$	2,891,410	8,433	6,651	143,242	—	3,049,736
Intersegment		1,025	159,661	80,886	—	(241,572)	—
Total	$	2,892,435	168,094	87,537	143,242	(241,572)	3,049,736

Operating expenses:
Lease operating	$	24,981	—	16,576	—	(15,996)	25,561
Gathering, compression, processing, and transportation		630,708	19,792	—	—	(159,867)	490,633
Depletion, depreciation, and amortization		483,991	45,255	18,767	—	—	548,013
General and administrative expense (before equity-based compensation)		79,204	16,467	3,793	—	(819)	98,645
Equity-based compensation expense		61,617	14,218	3,445	—	—	79,280
Other operating expenses		113,881	25	2,437	214,201	—	330,544
Total		1,394,382	95,757	45,018	214,201	(176,682)	1,572,676
Operating income (loss)	$	1,498,053	72,337	42,519	(70,959)	(64,890)	1,477,060

Segment Adjusted EBITDAX (1)		852,918	131,810	64,731	(70,959)	(64,890)	913,610


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2016:
Sales and revenues:
Third-party	$	1,291,008	9,463	644	287,194	—	1,588,309
Intersegment		11,714	210,144	203,106	—	(424,964)	—
Total	$	1,302,722	219,607	203,750	287,194	(424,964)	1,588,309

Operating expenses:
Lease operating	$	37,299	—	104,009	—	(104,118)	37,190
Gathering, compression, processing, and transportation		838,936	20,567	—	—	(209,790)	649,713
Depletion, depreciation, and amortization		513,302	52,780	21,975	—	—	588,057
General and administrative expense (before equity-based compensation)		79,055	14,853	5,493	—	(1,102)	98,299
Equity-based compensation expense		56,301	14,902	4,464	—	—	75,667
Other operating expenses		104,279	(809)	11,568	378,521	(10,384)	483,175
Total		1,629,172	102,293	147,509	378,521	(325,394)	1,932,101
Operating income (loss)	$	(326,450)	117,314	56,241	(91,327)	(99,570)	(343,792)

Segment Adjusted EBITDAX (1)		973,101	184,996	93,064	(91,327)	(99,570)	1,060,264

(1)

See “—Non-GAAP Financial Measure” for a definition of Segment Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Segment Adjusted EBITDAX to operating income.

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The following tables set forth selected operating data for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2016:


	Nine Months Ended September 30,				Amount of Increase		Percent
(in thousands)	2015		2016		(Decrease)		Change
Operating revenues:
Natural gas sales	$	810,982	$	848,936	$	37,954	5	%
NGLs sales		188,403		274,736		86,333	46	%
Oil sales		55,627		41,712		(13,915)	(25)	%
Gathering, compression, and water handling and treatment		15,084		10,107		(4,977)	(33)	%
Marketing		143,242		287,194		143,952	100	%
Commodity derivative fair value gains		1,836,398		125,624		(1,710,774)	(93)	%
Total operating revenues		3,049,736		1,588,309		(1,461,427)	(48)	%
Operating expenses:
Lease operating		25,561		37,190		11,629	45	%
Gathering, compression, processing, and transportation		490,633		649,713		159,080	32	%
Production and ad valorem taxes		57,458		52,296		(5,162)	(9)	%
Marketing		214,201		378,521		164,320	77	%
Exploration		3,086		3,289		203	7	%
Impairment of unproved properties		43,670		47,223		3,553	8	%
Depletion, depreciation, and amortization		548,013		588,057		40,044	7	%
Accretion of asset retirement obligations		1,227		1,846		619	50	%
General and administrative (before equity-based compensation)		98,645		98,299		(346)	*
Equity-based compensation		79,280		75,667		(3,613)	(5)	%
Contract termination and rig stacking		10,902		—		(10,902)	*
Total operating expenses		1,572,676		1,932,101		359,425	23	%
Operating income (loss)		1,477,060		(343,792)		(1,820,852)	*

Other earnings (expenses):
Equity in earnings of unconsolidated affiliate		—		2,027		2,027	*
Interest expense		(173,929)		(185,634)		(11,705)	7	%
Income (loss) before income taxes		1,303,131		(527,399)		(1,830,530)	*
Income tax (expense) benefit		(498,709)		230,755		729,464	*
Net income (loss) and comprehensive income (loss) including noncontrolling interest		804,422		(296,644)		(1,101,066)	*
Net income and comprehensive income attributable to noncontrolling interest		21,522		66,400		44,878	209	%
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation	$	782,900	$	(363,044)	$	(1,145,944)	*

Adjusted EBITDAX (1)	$	913,610	$	1,060,264	$	146,654	16	%

(1)

See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income (loss) including noncontrolling interest and net cash provided by operating activities.

*Not meaningful or applicable.

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	Nine Months Ended September 30,				Amount of Increase		Percent
	2015		2016		(Decrease)		Change
Production data:
Natural gas (Bcf)		332		369		37	11	%
C2 Ethane (MBbl)		—		4,463		4,463	*
C3+ NGLs (MBbl)		11,042		14,722		3,680	33	%
Oil (MBbl)		1,549		1,373		(176)	(11)	%
Combined (Bcfe)		407		493		86	21	%
Daily combined production (MMcfe/d)		1,492		1,799		307	21	%
Average prices before effects of derivative settlements(2):
Natural gas (per Mcf)	$	2.45	$	2.30	$	(0.15)	(6)	%
C2 Ethane (per Bbl)	$	—	$	7.81	$	*	*
C3+ NGLs (per Bbl)	$	17.06	$	16.29	$	(0.77)	(5)	%
Oil (per Bbl)	$	35.91	$	30.38	$	(5.53)	(15)	%
Combined (per Mcfe)	$	2.59	$	2.36	$	(0.23)	(9)	%
Average realized prices after effects of derivative settlements(2):
Natural gas (per Mcf)	$	4.07	$	4.38	$	0.31	8	%
C2 Ethane (per Bbl)	$	—	$	7.81	$	*	*
C3+ NGLs (per Bbl)	$	20.34	$	19.30	$	(1.04)	(5)	%
Oil (per Bbl)	$	42.90	$	30.38	$	(12.52)	(29)	%
Combined (per Mcfe)	$	4.03	$	4.02	$	(0.01)	*
Average Costs (per Mcfe):
Lease operating	$	0.06	$	0.08	$	0.02	33	%
Gathering, compression, processing, and transportation	$	1.20	$	1.32	$	0.12	10	%
Production and ad valorem taxes	$	0.14	$	0.11	$	(0.03)	(21)	%
Marketing, net	$	0.17	$	0.19	$	0.02	12	%
Depletion, depreciation, amortization, and accretion	$	1.35	$	1.20	$	(0.15)	(11)	%
General and administrative (before equity-based compensation)	$	0.24	$	0.20	$	(0.04)	(17)	%

(2)

Discussion of Consolidated Exploration and Production Results for the Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2016

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $1.1 billion for the nine months ended September 30, 2015 to $1.2 billion for the nine months ended September 30, 2016, an increase of $110 million, or 10%. Our production increased by 21% over that same period, from 407 Bcfe, or 1,492 MMcfe per day, for the nine months ended September 30, 2015 to 493 Bcfe, or 1,799 MMcfe per day, for the nine months ended September 30, 2016. Net equivalent prices before the effects of settled derivative gains decreased from $2.59 per Mcfe for the nine months ended September 30, 2015 to $2.36 for the nine months ended September 30, 2016, a decrease of 9%. Prices for natural gas, NGLs, and oil all declined from 2015. Net equivalent prices after the effects of gains on settled derivatives decreased from $4.03 for the nine months ended September 30, 2015 to $4.02 for the nine months ended September 30, 2016.

Increased production volumes accounted for an approximate $222 million increase in year-over-year product revenues (calculated as the combined change in year-to-year volumes times the prior year average price), and changes in our equivalent prices accounted for an approximate $112 million decrease in year-over-year product revenues (calculated as the change in year-to-year average price times current year production volumes). Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion program.

Commodity derivative fair value gains. To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment, and all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. For the nine months ended September 30, 2015 and 2016, our hedges resulted in derivative fair value gains of $1.8 billion and $126 million, respectively. The derivative fair value gains included $587 million and $814 million of gains on settled derivatives for the nine months ended September 30, 2015 and 2016, respectively. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts

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Gathering, compression, and water handling and treatment revenues. Gathering, compression, and water handling and treatment revenues decreased from $15 million for the nine months ended September 30, 2015 to $10 million for the nine months ended September 30, 2016, primarily attributable to the provision of fresh water distribution services to wells in which we hold a higher working interest than the wells to which such services were provided in 2015. Fees for water distribution services provided to us by Antero Midstream are eliminated in consolidation. The amounts that are not eliminated represent the portion of such fees that are charged to outside working interest owners in Company-operated wells, as well as fees charged to other third parties for services provided by Antero Midstream.

Lease operating expense. Lease operating expenses increased from $26 million for the nine months ended September 30, 2015 to $37 million for the nine months ended September 30, 2016, an increase of 45%. The increase is primarily a result of an increase in the number of producing wells. On a per unit basis, lease operating expenses increased from $0.06 per Mcfe for the nine months ended September 30, 2015 to $0.08 for the nine months ended September 30, 2016 as a larger proportion of wells have been on production for longer periods of time compared to the prior year. Lease operating expenses are expected to slowly increase on a per unit basis as mature properties make up a larger proportion of our production base and average production per well declines.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expenses increased from $491 million for the nine months ended September 30, 2015 to $650 million for the nine months ended September 30, 2016. The increase in these expenses is a result of the increase in production and the related firm transportation costs and third-party gathering, compression, and processing expenses. On a per Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.20 per Mcfe for the nine months ended September 30, 2015 to $1.32 for the nine months ended September 30, 2016, primarily due to higher transportation costs incurred on new pipelines that were placed in service in late 2015. Substantially all of the new pipelines currently deliver our gas to better price indices or sales contracts resulting in higher realized gas prices for the period.

Production and ad valorem tax expense. Total production and ad valorem taxes decreased from $57 million for the nine months ended September 30, 2015 to $52 million for the nine months ended September 30, 2016, primarily as a result of the termination of the workman’s compensation portion of the West Virginia production tax effective July 1, 2016. On a per Mcfe basis, production and ad valorem taxes deccreased from $0.14 per Mcfe for the nine months ended September 30, 2015 to $0.11 per Mcfe for the three months ended September 30, 2016. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging decreased from 5.4% for the nine months ended September 30, 2015 to 4.5% for the nine months ended September 30, 2016. Also as production in Ohio increased at a higher rate than West Virginia, severance taxes as a percentage of revenue decreased due to lower severance tax rates in Ohio as compared to West Virginia.

Exploration expense. Exploration expense remained consistent at $3 million for the nine months ended September 30, 2015 and 2016. These amounts represent expenses incurred for unsuccessful lease acquisitions.

Impairment of unproved properties. Impairment of unproved properties increased from $44 million for the nine months ended September 30, 2015 to $47 million for the nine months ended September 30, 2016. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, or future plans to develop the acreage.

DD&A. DD&A increased from $548 million for the nine months ended September 30, 2015 to $588 million for the nine months ended September 30, 2016, primarily because of increased production. DD&A per Mcfe decreased by 11%, from $1.35 per Mcfe during the nine months ended September 30, 2015 to $1.20 per Mcfe during the nine months ended September 30, 2016, primarily due to decreases in our per-unit development costs, in part due to recent well cost reductions and drilling and completion efficiencies that we have achieved.

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flows. As estimated future net cash flows remained higher than the carrying value of our proved properties at September 30, 2016, we did not further evaluate our proved properties for impairment.

General and administrative and equity-based compensation expense. General and administrative expense (before equity-based compensation expense) decreased from $99 million for the nine months ended September 30, 2015 to $98 million for the nine months ended September 30, 2016. On a per unit basis, general and administrative expense before equity-based compensation decreased by 17%, from $0.24 per Mcfe during the nine months ended September 30, 2015 to $0.20 per Mcfe during the nine months ended September 30, 2016, primarily due to our 21% increase in production. We had 482 employees as of September 30, 2015 and 516 employees as of September 30, 2016.

Noncash equity-based compensation expense decreased from $79 million for the nine months ended September 30, 2015 to $76 million for the nine months ended September 30, 2016 as a result of a $35 million decrease in amortization of expense related to the vesting of profits interests that became fully vested in October 2015, partially offset by a $25 million increase in equity-based compensation related to restricted stock unit awards and a $7 million increase in equity-based compensation related to other equity awards. See note 6 to the condensed consolidated financial statements included elsewhere in this report for more information on equity-based compensation awards.

Contract termination and rig stacking. We incurred contract termination and rig stacking costs of $11 million during the nine months ended September 30, 2015. These costs represent fees incurred upon the delay or cancellation of drilling contracts with third-party contractors. We undertook these actions in order to align our drilling and completion activity level for 2015 with our 2015 capital budget. There were no such costs incurred during the nine months ended September 30, 2016.

Equity in earnings of unconsolidated affiliate. In May 2016, Antero Midstream purchased a 15% equity interest in a regional gathering pipeline. Equity in earnings of unconsolidated affiliate of $2.0 million for the nine months ended September 30, 2016 represents the portion of the pipeline’s net income which is allocated to Antero Midstream based on its equity interest in the pipeline. The Company did not hold any unconsolidated equity investments during the nine months ended September 30, 2015.

Interest expense. Interest expense increased from $174 million for the nine months ended September 30, 2015 to $186 million for the nine months ended September 30, 2016, primarily due to increased average indebtedness. Interest expense includes approximately $7.4 million and $8.5 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2015 and 2016, respectively.

Income tax (expense) benefit. Income tax (expense) benefit changed from a deferred tax expense of $499 million for the nine months ended September 30, 2015 to a deferred tax benefit of $231 million for the nine months ended September 30, 2016. The deferred tax benefit in 2016 results from the loss incurred for financial reporting purposes during the nine months ended September 30, 2016, resulting in a decrease in deferred tax liabilities. The effect of state tax rates, state tax apportionment, and the noncontrolling interest in Antero Midstream largely account for the difference between the federal tax rate of 35% and the rate at which the income tax benefit was provided for the nine months ended September 30, 2016.

Adjusted EBITDAX. Adjusted EBITDAX increased by 16%, from $914 million for the nine months ended September 30, 2015 to $1.06 billion for the nine months ended September 30, 2016. The increase in Adjusted EBITDAX was primarily due to a 21% increase in production, which was partially offset by a slight decrease in the average per Mcfe price received after the impact of cash settled derivatives, as well as increases in cash operating and gathering, compression, processing, and transportation expenses. See “—Non-GAAP Financial Measure” for a definition of Adjusted EBITDAX (a non-GAAP measure) and a reconciliation of Adjusted EBITDAX to net income from continuing operations including noncontrolling interest and net cash provided by operating activities.

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Discussion of Segment Results for the Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2016

Gathering and Compression. Revenue for the gathering and compression segment increased from $168 million for the nine months ended September 30, 2015 to $220 million for the nine months ended September 30, 2016, an increase of $52 million, or 31%. Gathering revenues increased by $38 million from the prior year period and compression revenues increased by $14 million as additional wells on production increased throughput volumes. Total operating expenses related to the gathering and compression segment increased from $96 million for the nine months ended September 30, 2015 to $102 million for the nine months ended September 30, 2016 primarily as a result of increases in depreciation expense due to a larger base of gathering and compression assets.

Water Handling and Treatment. Revenue for the water handling and treatment segment increased from $88 million for the nine months ended September 30, 2015 to $204 million for the nine months ended September 30, 2016, an increase of $116 million, or 133%. The increase was primarily due to revenues generated from waste water treatment services that commenced in the fourth quarter of 2015, as well as increased use of the water systems as a result of increased completion activity. The volume of water delivered through the systems increased from 24.0 MMBbls for the nine months ended September 30, 2015 to 31.3 MMBbls for the nine months ended September 30, 2016. Operating expenses for the water handling and treatment segment increased from $45 million for the nine months ended September 30, 2015 to $148 million for the nine months ended September 30, 2016 as a result of expenses related to waste water treatment services, accretion expense related to the contingent acquisition consideration payable by Antero Midstream in connection with Antero’s dropdown of its water handling and treatment assets to Antero Midstream in September 2015, and an increase in depreciation expense due to an increase in fresh water distribution assets.

Marketing. Where permitted, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets. Marketing revenues of $143 million and $287 million and expenses of $214 million and $379 million for the nine months ended September 30, 2015 and 2016, respectively, relate to these activities. Net losses on our marketing activities were $71 million and $92 million for the nine months ended September 30, 2015 and 2016, respectively. Marketing costs include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs. This includes firm transportation costs of $74 million and $96 million for the nine months ended September 30, 2015 and 2016, respectively, related to unutilized excess capacity which increased due to new firm transportation agreements. Based on current projections for our 2016 annual production levels, we estimate that we could incur total annual net marketing expense of $100 million to $130 million in 2016 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third party gas and capture positive basis differentials between various indices. In years subsequent to 2016, our commitments and obligations under firm transportation agreements continue to increase. As a result, our net marketing expense could continue to increase depending on our utilization of our transportation capacity based on future production and how much, if any, future excess transportation can be marketed to third parties.

Capital Resources and Liquidity

Historically, our primary sources of liquidity have been issuances of debt and equity securities, borrowings under our revolving credit facility, asset sales, and net cash provided by operating activities. Our primary use of cash has been for the exploration, development, and acquisition of natural gas, NGLs, and oil properties, as well as for development of gathering, compression, and water handling and treatment infrastructure. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.

We believe that funds from operating cash flows and available borrowings under our revolving credit facility, or capital market transactions, will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months. For more information on our outstanding indebtedness, see note 4 to the condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

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The following table summarizes our cash flows for the nine months ended September 30, 2015 and 2016 (in thousands):


	Nine Months Ended September 30,
(in thousands)	2015		2016
Net cash provided by operating activities		841,154		905,697
Net cash used in investing activities		(1,836,864)		(1,974,667)
Net cash provided by financing activities		777,141		1,064,009
Net decrease in cash and cash equivalents		(218,569)		(4,961)

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $841 million and $906 million for the nine months ended September 30, 2015 and 2016, respectively. The increase in cash flows from operations from the nine months ended September 30, 2015 to the nine months ended September 30, 2016 was primarily the result of increases in total realized revenues from production and settled derivatives, partially offset by increases in cash operating costs and interest expense.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs, and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives. Prices for natural gas, NGLs, and oil are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, and other variables influence the market conditions for these products. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk” below.

Cash Flow Used in Investing Activities

During the nine months ended September 30, 2016, we used cash totaling $2.0 billion in investing activities, including $1.0 billion for drilling and completion costs, $560 million for undeveloped leasehold additions, $65 million for acquisitions of producing properties, $137 million by Antero Midstream for water handling and treatment systems, $154 million by Antero Midstream for gathering and compression systems, and $2 million for other property and equipment. During the nine months ended September 30, 2015, we used cash totaling $1.8 billion in investing activities, including $1.4 billion for drilling and completion costs, $170 million for undeveloped leasehold additions, $79 million for water handling systems, $283 million for gathering and compression systems, and $5 million for other property and equipment.

Our board of directors has approved a capital budget of $1.4 billion for 2016, which does not include the capital budget of $480 million for Antero Midstream, our consolidated subsidiary. Our capital budget may be adjusted as business conditions warrant. The amount, timing, and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline below our acceptable levels or costs increase above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow, and other factors both within and outside our control.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2016 of $1.1 billion consisted of net proceeds of $837 million from the issuance of common stock, proceeds of $178 million from the sale of Antero Midstream common units owned by Antero, proceeds of $650 million from the issuance of the 2024 Midstream Notes, and proceeds of $20 million from the sale of common units by Antero Midstream under the Distribution Agreement, partially offset by net repayments on our revolving credit facilities of $552 million, distributions of $51 million to noncontrolling interest owners in Antero Midstream, and other items totaling $18 million. Net cash provided by financing activities for the nine months ended September 30, 2015 of $777 million consisted of the issuance of $750 million of our 5.625% Senior Notes due 2023, net proceeds of $538 million from the issuance of common stock, and net proceeds of $241 million from the issuance of common units by Antero Midstream, partially offset by net repayments on our revolving credit facilities of $705 million and other items totaling $47 million.

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Debt Agreements and Contractual Obligations

Senior Secured Revolving Credit Facility. We have 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 our assets and are subject to regular semiannual redeterminations. At September 30, 2016, the borrowing base was $4.5 billion and lender commitments were $4.0 billion. In October 2016, the borrowing base was increased to $4.75 billion, and lender commitments remain at $4.0 billion. The next redetermination of the borrowing base is scheduled to occur in April 2017. At September 30, 2016, we had $605 million of borrowings and $709 million of letters of credit outstanding under the Credit Facility, with a weighted average interest rate of 2.31%. At December 31, 2015, we had $707 million of borrowings and $702 million of letters of credit outstanding under the Credit Facility, with a weighted average interest rate of 2.32%. The Credit Facility matures on May 5, 2019.

The Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios:

a current ratio, which is the ratio of our current assets (including any unused borrowing base under the facilities and excluding derivative assets) to our current liabilities (excluding derivative liabilities), of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

a minimum interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

We were in compliance with such covenants and ratios as of December 31, 2015 and September 30, 2016. The actual borrowing capacity available to us may be limited by the financial ratio covenants. At September 30, 2016, our current ratio was 5.69 to 1.0 (based on the $4.5 billion borrowing base as of September 30, 2016) and our interest coverage ratio was 7.63 to 1.0.

Midstream Credit Facility. Antero Midstream has a secured revolving credit facility (the “Midstream Facility”) among Antero Midstream, certain lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent, letter of credit issuer, and swing line lender. The Midstream Facility provides for lender commitments of $1.5 billion and for a letter of credit sublimit of $150 million. At September 30, 2016, Antero Midstream had a total outstanding balance under the Midstream Facility of $170 million, with a weighted average interest rate of 2.03%. At 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%. The Midstream Facility matures on November 10, 2019.

Senior Notes. Please refer to Note 4 to the condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, 2015 for information on our senior notes.

We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved may be material.

For more information on the terms, conditions, and restrictions under the Credit Facility, the Midstream Facility, and senior unsecured notes, please refer to our Annual Report on Form 10-K for the year ended December 31, 2015 on file with the SEC.

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Contractual Obligations. A summary of our contractual obligations as of September 30, 2016 is provided in the table below. Contractual obligations listed exclude minimum fees that we will pay to Antero Midstream, our consolidated subsidiary, under gathering and compression, and water services agreements.


	Remainder		Year Ended December 31,
(in millions)	of 2016		2017		2018		2019		2020		2021		Thereafter		Total
Antero Resources Credit Facility(1)	$	—		—		—		605		—		—		—		605
Antero Midstream Facility(1)		—		—		—		170		—		—		—		170
Antero Resources senior notes—principal(2)		—		—		—		—		525		1,000		1,850		3,375
Antero Resources senior notes—interest(2)		92		184		184		184		184		125		120		1,073
Antero Midstream senior notes—principal(2)		—		—		—		—		—		—		650		650
Antero Midstream senior notes—interest(2)		—		35		35		35		35		35		105		280
Drilling rig and completion service commitments(3)		27		101		98		60		—		—		—		286
Firm transportation (4)		119		709		935		1,086		1,105		1,084		10,469		15,507
Processing, gathering, and compression services (5)		88		370		286		230		230		224		951		2,379
Office and equipment leases		3		13		12		9		7		7		25		76
Asset retirement obligations(6)		—		—		—		—		—		—		36		36
Total	$	329		1,412		1,550		2,379		2,086		2,475		14,206		24,437

(1)

Includes outstanding principal amounts at September 30, 2016. This table does not include future commitment fees, interest expense or other fees on our Credit Facility or the Midstream Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

(2)

Antero Resources senior notes include the 6.00% notes due 2020, the 5.375% notes due 2021, the 5.125% notes due 2022, and the 5.625% notes due 2023. Antero Midstream senior notes include the 5.375% notes due 2024.

(3)

Includes contracts for the services of drilling rigs and hydraulic fracturing fleets, which expire at various dates from October 2016 through December 2019. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(4)

Includes firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit us 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 reflect our minimum daily volumes at the reservation fee rates. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(5)

Contractual commitments for processing, gathering and compression services agreements represent minimum commitments under long-term agreements. Includes Antero Midstream’s commitments for the construction of its advanced waste water treatment complex. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest. The table does not include intracompany commitments.

(6)

Represents the present value of our estimated asset retirement obligations. Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, and gain or loss on sale of assets, and excluding equity in earnings of unconsolidated affiliates. “Adjusted EBITDAX,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital

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expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:

is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure, and the method by which assets were acquired, among other factors;

helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and

is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, and as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation. Adjusted EBITDAX, as defined by our Credit Facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing our senior notes.

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.

“Segment Adjusted EBITDAX” is also used by our management team for various purposes, including as a measure of operating performance and as a basis for strategic planning and forecasting. Segment Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income before derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairments, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, gain or loss on sale of assets, and gain or loss on contingent acquisition consideration accretion. Operating income represents net income, including noncontrolling interest, before interest expense, income taxes, and equity in earnings of unconsolidated affiliates, and is the most directly comparable GAAP financial measure to Segment Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis. The following tables represent a reconciliation of our operating income to Segment Adjusted EBITDAX for the three and nine months ended September 30, 2015 and 2016 (in thousands):


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2015:
Operating income (loss)		940,374	35,875	8,611	(26,166)	(17,579)	941,115
Commodity derivative fair value gains		(1,079,071)	—	—	—	—	(1,079,071)
Gains on settled derivatives		205,919	—	—	—	—	205,919
Depletion, depreciation, amortization, and accretion		167,319	15,282	6,485	—	—	189,086
Impairment of unproved properties		8,754	—	—	—	—	8,754
Exploration expense		1,087	—	—	—	—	1,087
Equity-based compensation expense		18,631	4,205	1,079	—	—	23,915
State franchise taxes		2	—	—	—	—	2
Segment and consolidated Adjusted EBITDAX	$	263,015	55,362	16,175	(26,166)	(17,579)	290,807

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	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Three months ended September 30, 2016:
Operating income (loss)		454,347	44,550	29,492	(17,535)	(43,522)	467,332
Commodity derivative fair value gains		(530,334)	—	—	—	—	(530,334)
Gains on settled derivatives		196,712	—	—	—	—	196,712
Depletion, depreciation, amortization, and accretion		173,363	18,540	7,838	—	—	199,741
Impairment of unproved properties		11,753	—	—	—	—	11,753
Exploration expense		1,166	—	—	—	—	1,166
Expense (income) from accretion of contingent acquisition consideration		(3,527)	—	3,527	—	—	—
Equity-based compensation expense		19,781	5,214	1,386	—	—	26,381
Segment and consolidated Adjusted EBITDAX	$	323,261	68,304	42,243	(17,535)	(43,522)	372,751


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2015:
Operating income (loss)		1,498,053	72,337	42,519	(70,959)	(64,890)	1,477,060
Commodity derivative fair value gains		(1,836,398)	—	—	—	—	(1,836,398)
Gains on settled derivatives		586,639	—	—	—	—	586,639
Depletion, depreciation, amortization, and accretion		485,218	45,255	18,767	—	—	549,240
Impairment of unproved properties		43,670	—	—	—	—	43,670
Exploration expense		3,086	—	—	—	—	3,086
Equity-based compensation expense		61,617	14,218	3,445	—	—	79,280
State franchise taxes		131	—	—	—	—	131
Contract termination and rig stacking		10,902	—	—	—	—	10,902
Segment and consolidated Adjusted EBITDAX	$	852,918	131,810	64,731	(70,959)	(64,890)	913,610


	Exploration and production		Gathering and compression	Water handling and treatment	Marketing	Elimination of intersegment transactions	Consolidated total
Nine months ended September 30, 2016:
Operating income (loss)		(326,450)	117,314	56,241	(91,327)	(99,570)	(343,792)
Commodity derivative fair value gains		(125,624)	—	—	—	—	(125,624)
Gains on settled derivatives		813,559	—	—	—	—	813,559
Depletion, depreciation, amortization, and accretion		515,148	52,780	21,975	—	—	589,903
Impairment of unproved properties		47,223	—	—	—	—	47,223
Exploration expense		3,289	—	—	—	—	3,289
Expense (income) from accretion of contingent acquisition consideration		(10,384)	—	10,384	—	—	—
Equity-based compensation expense		56,301	14,902	4,464	—	—	75,667
State franchise taxes		39	—	—	—	—	39
Segment and consolidated Adjusted EBITDAX	$	973,101	184,996	93,064	(91,327)	(99,570)	1,060,264

The following table represents a reconciliation of our net income from continuing operations, including noncontrolling interest, to total Segment and consolidated Adjusted EBITDAX from continuing operations and a reconciliation of our total Segment and

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consolidated Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the periods presented:


	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2015		2016		2015		2016
Net income (loss) including noncontrolling interest	$	544,734		268,196		804,422		(296,644)
Commodity derivative fair value gains(1)		(1,079,071)		(530,334)		(1,836,398)		(125,624)
Gains on settled derivatives(1)		205,919		196,712		586,639		813,559
Interest expense		60,921		59,755		173,929		185,634
Income tax expense (benefit)		335,460		140,924		498,709		(230,755)
Depletion, depreciation, amortization, and accretion		189,086		199,741		549,240		589,903
Impairment of unproved properties		8,754		11,753		43,670		47,223
Exploration expense		1,087		1,166		3,086		3,289
Equity-based compensation expense		23,915		26,381		79,280		75,667
Equity in earnings of unconsolidated affiliate		—		(1,543)		—		(2,027)
State franchise taxes		2		—		131		39
Contract termination and rig stacking		—		—		10,902		—
Total Segment and consolidated Adjusted EBITDAX		290,807		372,751		913,610		1,060,264
Interest expense		(60,921)		(59,755)		(173,929)		(185,634)
Exploration expense		(1,087)		(1,166)		(3,086)		(3,289)
Changes in current assets and liabilities		9,119		17,327		103,463		35,939
State franchise taxes		(2)		—		(131)		(39)
Other non-cash items		8,130		(2,166)		1,227		(1,544)
Net cash provided by operating activities	$	246,046		326,991		841,154		905,697

(1)

The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation of Adjusted EBITDAX only reflects derivatives which settled during the period.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities, estimates of natural gas, NGLs, and oil reserve quantities and standardized measures of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in our 2015 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements. Also, see note 2 of the notes to our audited consolidated financial statements, included in our 2015 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

We evaluate the carrying amount of our 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. Under GAAP for successful efforts accounting, if the carrying amount exceeded the estimated undiscounted future net cash flows (measured using futures prices), we would further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties. Given the rapid decline in the market prices of natural gas, NGLs, and oil that occurred during the fourth quarter of 2014 and continued lower prices through 2015 and into 2016, at September 30, 2016, we compared estimated undiscounted future net cash flows using futures pricing for our Utica and Marcellus Basin properties to the carrying value of those properties. Estimated undiscounted future net cash flows exceeded the carrying values at September 30, 2016 and thus, no further evaluation of the fair value of the properties for impairment is required under GAAP. As a result, we have not

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recorded any impairment expenses associated with our Utica and Marcellus Basin proved properties during the three or nine months ended September 30, 2016. Additionally, we did not record any impairment expenses for proved properties during the year ended December 31, 2015. Based on current futures commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future. We are unable, however, to predict commodity prices with any greater precision than the futures market.

New Accounting Pronouncements

On May 28, 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. Additionally, on May 3, 2016, the FASB issued ASU No. 2016-11, which rescinds SEC accounting guidance regarding the use of the entitlements method for recognition of natural gas revenues. The new standards become effective for the Company on January 1, 2018. Early application is not permitted. The standards permit the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 and ASU No. 2016-11 will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standards on its ongoing financial reporting.

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases, which requires all leasing arrangements to be presented in the balance sheet as liabilities along with a corresponding asset. The ASU will replace most existing leases guidance in GAAP when it becomes effective. The new standard becomes effective for the Company on January 1, 2019. Although early application is permitted, the Company does not plan to early adopt the ASU. The standard requires the use of the modified retrospective transition method. The Company is evaluating the effect that ASU 2016-02 will have on its consolidated financial statements and related disclosures and has not yet determined the effect of the standard on its ongoing financial reporting.

Off-Balance Sheet Arrangements

As of September 30, 2016, we did not have any off-balance sheet arrangements other than operating leases and contractual commitments for drilling rig and hydraulic fracturing services, firm transportation, gas processing, and gathering and compression services. See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for commitments under operating leases, drilling rig and hydraulic fracturing service agreements, firm transportation, gas processing, and gathering and compression service agreements.

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Item 3.Quantitative and Qualitative Disclosures About Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs, and oil prices, as well as interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive derivative instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas, NGLs, and oil production. Realized pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for crude oil. Pricing for natural gas, NGLs, and oil production has, historically, been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate some of the potential negative impact on our cash flow caused by changes in commodity prices, we enter into derivative instruments to receive fixed prices for a portion of our natural gas, NGLs, and oil production when management believes that favorable future prices can be secured. We hedge part of our production at fixed prices for our sales points to mitigate the risk of differentials to the sales point prices. Part of our production is also hedged at NYMEX prices.

Our financial hedging activities are intended to support natural gas, NGLs, and oil prices at targeted levels and to manage our exposure to natural gas, NGLs, and oil price fluctuations. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the counterparty, commodity price swaps whereby we will pay a fixed price to the contract counterparty and receive a variable market price, cashless price collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments, and do not require or allow for physical delivery of the hedged commodity. The Company was not party to any collars as of or during the nine months ended September 30, 2016.

At September 30, 2016, we had in place natural gas and NGLs swaps covering portions of our projected production from 2016 through 2022. Our commodity hedge position as of September 30, 2016 is summarized in note 8 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. The Credit Facility allows us to hedge up to 75% of our projected production for the next five years, and 65% of our subsequent estimated proved reserves through December 31, 2023. Based on our production and our fixed price swap contracts which settled during the nine months ended September 30, 2016, our income before taxes would have decreased by approximately $5.1 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices.

All derivative instruments, other than those that meet the normal purchase and normal sale exception, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations. We present total gains or losses on commodity derivatives (both settled derivatives and derivative positions which remain open) within operating revenues as “Commodity derivative fair value gains (losses).”

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative instrument contracts are settled by making or receiving payments to or from the counterparty. At September 30, 2016, the estimated fair value of our commodity derivative instruments was a net asset of $2.4 billion comprised of current and noncurrent assets and current and noncurrent liabilities. At December 31, 2015, the estimated fair value of our commodity derivative instruments was a net asset of $3.1 billion comprised of current and noncurrent assets. None of these commodity derivative instruments were entered into for trading or speculative purposes.

By removing price volatility from a portion of our expected production through December 2022, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

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Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivative contracts ($2.4 billion at September 30, 2016), the sale of our oil and gas production ($163 million at September 30, 2016) which we market to energy companies, end users and refineries, and joint interest receivables ($43 million at September 30, 2016).

By using derivative instruments that are not traded on an exchange to hedge our exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions which management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have commodity hedges in place with fifteen different counterparties, all of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately $2.4 billion at September 30, 2016 includes the following values by bank counterparty: Morgan Stanley - $671 million; Barclays - $513 million; JP Morgan - $439 million; Wells Fargo - $215 million; Scotiabank - $181 million; Citigroup - $162 million; BNP Paribas - $68 million; Toronto Dominion - $56 million; Canadian Imperial Bank of Commerce - $64 million; Fifth Third - $22 million; Bank of Montreal - $23 million; SunTrust - $9 million; Capital One - $6 million; and Natixis - $1 million. The credit ratings of certain of these banks were downgraded in recent years because of their exposure to the sovereign debt crisis in Europe or various other factors. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2016 for each of the European and American banks. We believe that all of these institutions, currently, are acceptable credit risks. Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of September 30, 2016, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.

We are also subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs, and oil. We generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.

Joint interest receivables arise from our billing of entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we drill. We have minimal control over deciding who participates in our wells.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility and the Midstream Facility of our consolidated subsidiary, Antero Midstream. Each of these credit facilities has a floating interest rate. The average annualized interest rate incurred on this indebtedness during the nine months ended September 30, 2016 was approximately 2.14%. A 1.0% increase in each of the applicable average interest rates for the nine months ended September 30, 2016 would have resulted in an estimated $9.0 million increase in interest expense.

Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2016 at a reasonable assurance level.

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Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

In March 2011, we received orders for compliance from federal regulatory agencies, including the U.S. Environmental Protection Agency relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. No fine or penalty relating to these matters has been proposed at this time, but we believe that these actions will result in monetary sanctions exceeding $100,000. We are unable to estimate the total amount of such monetary sanctions or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date, and management does not expect these matters to have a material adverse effect on our financial condition, results of operations, or cash flows.

We are party to various other legal proceedings and claims in the ordinary course of our business. We believe 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 our consolidated financial condition, results of operations, or cash flows.

Item 1A. Risk Factors.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in our 2015 Form 10-K. The risks described in our 2015 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. There have been no material changes to the risks described in our 2015 Form 10-K. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities

The following table sets forth our share purchase activity for each period presented:


Period	Total Number of Shares Purchased		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans		Maximum Number of Shares that May Yet be Purchased Under the Plan
July 1, 2016 - July 31, 2016		2,165	$	26.37		—		N/A
August 1, 2016 - August 31, 2016		—	$	—		—		N/A
September 1, 2016 - September 30, 2016		—	$	—		—		N/A

Shares purchased represent shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of restricted stock and restricted stock units held by our employees.

Item 5.Other Information.

Amendment to Long-Term Incentive Plan Awards

Effective October 24, 2016, the board of directors of the Company approved an amendment to certain outstanding awards granted pursuant to the Plan (the “Amendment”). The Amendment provides for 100% vesting of the service-based vesting conditions with regard to outstanding awards held by our named executive officers upon a Change in Control, as defined in the Plan, provided that the officer remains continuously employed through the date of the Change in Control. The preceding description of the Amendment is qualified in its entirety by reference to the Amendment, a copy of which is attached as Exhibit 10.1 hereto and incorporated by reference herein.

Credit Agreement Amendment

On October 24, 2016, Antero entered into a Twentieth Amendment (the “Twentieth Amendment”) to its Credit Facility. The Twentieth Amendment amended the Credit Facility to, among other things, (i) increase the face amount of the Credit Facility to $5 billion, (ii) increase the borrowing base to $4.75 billion and (iii) extend by one year, to December 31, 2023, the period of time through which we may hedge a portion of our estimated proved reserves.

A copy of the Twentieth Amendment is filed as Exhibit 10.3 hereto and is incorporated by reference. The description of the Twentieth Amendment contained herein is qualified in its entirety by the full text of such instrument.

Relationships

Certain parties to the Twentieth Amendment, or their respective affiliates (collectively, the “Banks”), perform and have performed commercial and investment banking and advisory services for the Company from time to time for which they receive and have received customary fees and expenses. In addition, Wells Fargo Bank, National Association, is the trustee for each outstanding series of the Company’s senior notes. The Banks may, from time to time, engage in transactions with and perform services for the Company in the ordinary course of their business, for which they will receive fees and expenses.

Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934

Pursuant to Section 13(r) of the Securities Exchange Act of 1934, we, Antero Resources Corporation, may be required to disclose in our annual and quarterly reports to the Securities and Exchange Commission (the “SEC”), whether we or any of our “affiliates” knowingly engaged in certain activities, transactions or dealings relating to Iran or with certain individuals or entities targeted by U.S. economic sanctions. Disclosure is generally required even where the activities, transactions or dealings were conducted in compliance with applicable law. Because the SEC defines the term “affiliate” broadly, it includes any entity under common “control” with us (and the term “control” is also construed broadly by the SEC).

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The description of the activities below has been provided to us by Warburg Pincus LLC (“WP”), affiliates of which: (i) beneficially own more than 10% of our outstanding common stock and/or are members of our board of directors, (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Santander Asset Management Investment Holdings Limited (“SAMIH”). SAMIH may therefore be deemed to be under common “control” with us; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by SAMIH and its affiliates. The disclosure does not relate to any activities conducted by us or by WP and does not involve our or WP’s management. Neither we nor WP has had any involvement in or control over the disclosed activities, and neither we nor WP has independently verified or participated in the preparation of the disclosure. Neither we nor WP is representing as to the accuracy or completeness of the disclosure nor do we or WP undertake any obligation to correct or update it.

We understand that one or more SEC-reporting affiliates of SAMIH intends to disclose in its next annual or quarterly SEC report that:

(a)Santander UK plc (“Santander UK”) holds two savings accounts and one current account for two customers resident in the United Kingdom (“UK”) who are currently designated by the United States (“US”) under the Specially Designated Global Terrorist (“SDGT”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(b)Santander UK held a savings account for a customer resident in the UK who is currently designated by the US under the SDGT sanctions program. The savings account was closed on July 26, 2016. Revenue generated by Santander UK on this account in the nine months ended September 30, 2016 was negligible relative to the overall revenues of Banco Santander SA.

(c)Santander UK holds two frozen current accounts for two UK nationals who are designated by the US under the SDGT sanctions program. The accounts held by each customer have been frozen since their designation and have remained frozen through the nine months ended September 30, 2016. The accounts are in arrears (£1,844.73 in debit combined) and are currently being managed by Santander UK Collections & Recoveries department. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(d)Santander UK holds three current accounts and a savings account for two customers resident in the UK who are currently designated by the US under the Transnational Criminal Organizations (“TCO”) sanctions program. Revenues and profits generated by Santander UK on these accounts in the nine months ended September 30, 2016 were negligible relative to the overall revenues and profits of Banco Santander SA.

(e)In addition, during the nine months ended September 30, 2016, Santander UK had an OFAC match on a power of attorney account. A party listed on the account is currently designated by the US under the SDGT sanctions program and the Iranian Financial Sanctions Regulations. The power of attorney was removed from the account on July 29, 2016. During the nine months ended September 30, 2016, related revenues and profits generated by Santander UK were negligible relative to the overall revenues and profits of Banco Santander SA.

Item 6.Exhibits.

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Quarterly Report on Form 10-Q and are incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


ANTERO RESOURCES CORPORATION

By:	/s/ GLEN C. WARREN, JR.
	Glen C. Warren, Jr.
	President, Chief Financial Officer and Secretary

Date:	October 26, 2016

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EXHIBIT INDEX


Exhibit Number		Description of Exhibit
3.1		Amended and Restated Certificate of Incorporation of Antero Resources Corporation (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
3.2		Amended and Restated Bylaws of Antero Resources Corporation (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
4.1*		Registration Rights Agreement, dated as of October 7, 2016, by and among Antero Resources Corporation and the Purchaser named therein.
10.1*		Global Amendment to grant Notices and Award Agreements Under the Antero Resources Corporation Long-Term Incentive Plan.
10.2*		Common Stock Subscription Agreement, dated as of October 3, 2016, by and between Antero Resources Corporation and the Purchaser named on Schedule A thereto.
10.3*		Twentieth Amendmnet to Fourth Amended and Restated Credit Agreement, dated as of October 24, 2016, by and among Antero Resources Corporation, certain subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
31.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*		Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*		Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
101*		The following financial information from this Quarterly Report on Form 10-Q of Antero Resources Corporation for the quarter ended September 30, 2016 formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Condensed Consolidated Statements of Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

The exhibits marked with the asterisk symbol (*) are filed or furnished with this Quarterly Report on Form 10-Q.