ANTERO RESOURCES Corp - Quarter Report: 2014 September (Form 10-Q)

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, 2014


☐	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 262,067,246 shares of common stock outstanding as of October 31, 2014.

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TABLE OF CONTENTS


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		2
PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 4.	Controls and Procedures	44
PART II—OTHER INFORMATION		46
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 5.	Disclosure pursuant to Section 13(r) of the Securities Exchange Act of 1934	46
Item 6.	Exhibits	48
SIGNATURES		49

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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 (the “Securities Act”), 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 (this “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 this Form 10-Q. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

business strategy, including the proposed initial public offering of gathering and compression business;

reserves;

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

realized 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;

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 and conducting our midstream operations;

general economic conditions;

credit markets;

uncertainty regarding our future operating results; and

plans, objectives, expectations and intentions contained in this report that are not historical.

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 and sale of natural gas, NGLs, and oil. These risks include, but are not limited to, commodity price volatility, 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

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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 Annual Report on Form 10-K for the year ended December 31, 2013 (our “2013 Form 10-K”) on file with the Securities and Exchange Commission (the “SEC”) and in “Item 1A. Risk Factors” of this 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 way. 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 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 Form 10-Q.

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PART I—FINANCIAL INFORMATION

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2013 and September 30, 2014

(Unaudited)

(In thousands, except share amounts)


Assets	2013		2014
Current assets:
Cash and cash equivalents	$	17,487		6,308
Accounts receivable – trade, net of allowance for doubtful accounts of $1,251 in 2013 and 2014		30,610		66,755
Accrued revenue		96,825		144,014
Derivative instruments		183,000		280,959
Other		5,642		4,667
Total current assets		333,564		502,703
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,513,136		1,915,683
Proved properties		3,621,672		5,605,619
Fresh water distribution systems		231,684		390,966
Gathering systems and facilities		584,626		1,064,855
Other property and equipment		15,757		32,593
		5,966,875		9,009,716
Less accumulated depletion, depreciation, and amortization		(407,219)		(722,731)
Property and equipment, net		5,559,656		8,286,985
Derivative instruments		677,780		458,209
Other assets, net		42,581		67,983
Total assets	$	6,613,581		9,315,880

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2013 and September 30, 2014

(Unaudited)

(In thousands, except share amounts)


Liabilities and Stockholders' Equity	2013		2014
Current liabilities:
Accounts payable	$	370,640		598,538
Accrued liabilities		77,126		178,840
Revenue distributions payable		96,589		169,446
Deferred income tax liability		69,191		106,721
Derivative instruments		646		—
Other		8,037		10,491
Total current liabilities		622,229		1,064,036
Long-term liabilities:
Long-term debt		2,078,999		4,137,866
Deferred income tax liability		278,580		318,323
Derivative instruments		—		86
Other long-term liabilities		35,113		44,147
Total liabilities		3,014,921		5,564,458
Commitments and contingencies
Stockholders' equity:
Common stock, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 262,049,659 shares and 262,051,067 shares, respectively		2,620		2,621
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued		—		—
Additional paid-in capital		3,402,180		3,488,076
Accumulated earnings		193,860		260,725
Total stockholders' equity		3,598,660		3,751,422
Total liabilities and stockholders' equity	$	6,613,581		9,315,880

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, 2013 and 2014

(Unaudited)

(In thousands, except share and per share amounts)


	2013		2014
Revenue:
Natural gas sales	$	182,125		310,390
Natural gas liquids sales		31,956		91,111
Oil sales		8,473		29,304
Gathering, compression, and water distribution		—		4,875
Marketing		—		17,835
Commodity derivative fair value gains		161,968		308,975
Total revenue		384,522		762,490
Operating expenses:
Lease operating		2,697		8,680
Gathering, compression, processing, and transportation		58,383		128,531
Production and ad valorem taxes		11,851		21,726
Marketing		—		32,192
Exploration		5,372		7,476
Impairment of unproved properties		3,205		4,542
Depletion, depreciation, and amortization		65,697		124,624
Accretion of asset retirement obligations		266		320
General and administrative (including stock compensation expense of $24,210 in 2014)		14,443		53,000
Total operating expenses		161,914		381,091
Operating income		222,608		381,399
Other expenses:
Interest		(37,444)		(42,455)
Income from continuing operations before income taxes and discontinued operations		185,164		338,944
Provision for income tax expense		(67,370)		(135,035)
Income from continuing operations		117,794		203,909
Discontinued operations:
Income from sale of discontinued operations, net of income tax expense of $1,900 in 2013		3,100		—
Net income and comprehensive income	$	120,894		203,909

Earnings per common share:
Continuing operations	$	0.45		0.78
Discontinued operations		0.01		—
Total	$	0.46		0.78

Earnings per common share - assuming dilution
Continuing operations	$	0.45		0.78
Discontinued operations		0.01		—
Total	$	0.46		0.78

Weighted average number of shares outstanding:
Basic		262,049,659		262,049,948
Diluted		262,049,659		262,069,878

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income

Nine Months Ended September 30, 2013 and 2014

(Unaudited)

(In thousands, except per share amounts)


	2013		2014
Revenue:
Natural gas sales	$	476,403		936,877
Natural gas liquids sales		59,772		244,807
Oil sales		11,435		89,059
Gathering, compression, and water distribution		—		11,964
Marketing		—		23,048
Commodity derivative fair value gains (losses)		285,510		(63,720)
Total revenue		833,120		1,242,035
Operating expenses:
Lease operating		5,222		18,570
Gathering, compression, processing, and transportation		148,023		315,878
Production and ad valorem taxes		30,578		64,123
Marketing		—		58,119
Exploration		17,034		21,176
Impairment of unproved properties		9,564		7,895
Depletion, depreciation, and amortization		158,650		320,984
Accretion of asset retirement obligations		797		931
General and administrative (including stock compensation expense of $85,821 in 2014)		40,727		162,342
Total operating expenses		410,595		970,018
Operating income		422,525		272,017
Other expenses:
Interest		(100,840)		(111,057)
Loss on early extinguishment of debt		—		(20,386)
Total other expenses		(100,840)		(131,443)
Income from continuing operations before income taxes and discontinued operations		321,685		140,574
Provision for income tax expense		(120,695)		(75,919)
Income from continuing operations		200,990		64,655
Discontinued operations:
Income from sale of discontinued operations, net of income tax expense of $1,900 and $1,354, respectively		3,100		2,210
Net income and comprehensive income	$	204,090		66,865

Earnings per common share:
Continuing operations	$	0.77		0.25
Discontinued operations		0.01		0.01
Total	$	0.78		0.26

Earnings per common share - assuming dilution
Continuing operations	$	0.77		0.25
Discontinued operations		0.01		0.01
Total	$	0.78		0.26

Weighted average number of shares outstanding:
Basic		262,049,659		262,049,756
Diluted		262,049,659		262,066,632

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, 2014

(Unaudited)

(In thousands)


	Common		Additional	Accumulated	Total
	Stock		paid-in capital	earnings	equity
Balances, December 31, 2013	$	2,620	3,402,180	193,860	3,598,660
Issuance of common stock upon vesting of stock-based compensation awards, net of awards withheld for income taxes due upon vesting		1	—	—	1
Stock compensation		—	85,896	—	85,896
Net income and comprehensive income		—	—	66,865	66,865
Balances, September 30, 2014	$	2,621	3,488,076	260,725	3,751,422

See accompanying notes to condensed consolidated financial statements.

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2013 and 2014

(Unaudited)

(In thousands)


	2013		2014
Cash flows from operating activities:
Net income	$	204,090		66,865
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		159,447		321,915
Impairment of unproved properties		9,564		7,895
Derivative fair value (gains) losses		(285,510)		63,720
Cash receipts for settled derivatives		109,311		57,333
Deferred income tax expense		120,695		75,919
Stock compensation expense		—		85,896
Loss on early extinguishment of debt		—		20,386
Gain on sale of discontinued operations		(5,000)		(3,564)
Deferred income tax expense - discontinued operations		1,900		1,354
Other		3,911		4,874
Changes in assets and liabilities:
Accounts receivable		(11,727)		(36,145)
Accrued revenue		(39,453)		(47,189)
Other current assets		1,702		975
Accounts payable		(4,602)		530
Accrued liabilities		44,720		105,278
Revenue distributions payable		22,889		72,857
Other		—		(153)
Net cash provided by operating activities		331,937		798,746
Cash flows used in investing activities:
Additions to unproved properties		(342,832)		(518,247)
Drilling and completion costs		(1,165,248)		(1,723,657)
Additions to fresh water distribution systems		(101,838)		(156,467)
Additions to gathering systems and facilities		(240,119)		(406,666)
Additions to other property and equipment		(3,225)		(12,539)
Change in other assets		(11,622)		(6,896)
Net cash used in investing activities		(1,864,884)		(2,824,472)
Cash flows from financing activities:
Issuance of senior notes		231,750		1,102,500
Repayment of senior notes		—		(260,000)
Borrowings on bank credit facility, net		1,295,500		1,217,000
Make-whole premium on debt extinguished		—		(17,383)
Payments of deferred financing costs		(8,334)		(27,570)
Other		6,626		—
Net cash provided by financing activities		1,525,542		2,014,547
Net decrease in cash and cash equivalents		(7,405)		(11,179)
Cash and cash equivalents, beginning of period		18,989		17,487
Cash and cash equivalents, end of period	$	11,584		6,308
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	70,221		67,299
Supplemental disclosure of noncash investing activities:
Increase in accounts payable for additions to property and equipment	$	134,525		227,368

See accompanying notes to condensed consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

(1)Organization

(a)Business and Organization

Antero Resources Corporation and its consolidated subsidiaries (collectively referred to as the “Company,” “we,” or “our”) are engaged in the exploitation, development, and acquisition of natural gas, natural gas liquids (“NGLs”), and oil properties in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. We target 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. We also have gathering and compression and fresh water distribution operations in the Appalachian Basin. Our corporate headquarters are in Denver, Colorado.

Our consolidated financial statements include the accounts of Antero Resources Corporation and its subsidiaries, Antero Resources Midstream LLC (“Antero Midstream”) and Antero Midstream LLC (“Midstream Operating”).

(b)Corporate Reorganization and Initial Public Offering

Prior to October 16, 2013, the Company’s predecessor, Antero Resources LLC, filed reports with the Securities and Exchange Commission. Antero Resources LLC was formed in October 2009 by members of the Company’s management team and its sponsor investors. Antero Resources LLC owned 100% of the outstanding shares of Antero Resources Appalachian Corporation, which was formed in March 2008 and renamed Antero Resources Corporation in June 2013. In connection with our initial public offering (“IPO”) completed on October 16, 2013, all of the ownership interests in Antero Resources LLC were exchanged for similar interests in a newly formed limited liability company, Antero Resources Investment LLC (“Antero Investment”), and Antero Resources LLC was merged into Antero Resources Corporation. As a result of this reorganization, Antero Investment owned 100% of the issued and outstanding 224,375,000 shares of common stock of Antero Resources Corporation prior to the IPO.

On October 16, 2013, Antero Resources Corporation issued 37,674,659 additional shares of its common stock at $44.00 per share in the IPO, resulting in proceeds to the Company, net of underwriter discounts and expenses of the offering, of approximately $1.6 billion.

In 2013, the Company formed a subsidiary, Antero Midstream. Prior to its initial public offering, the Company owned all of the common economic interest in Antero Midstream and Antero Investment indirectly owned a special membership interest. In connection with the initial public offering of Antero Midstream, the Company intends to contribute gathering and compression assets to Antero Midstream and intends to enter into commercial arrangements for services from Antero Midstream. Following the initial public offering, the special membership interest will entitle Antero Investment to own the general partner interest in the MLP, which will allow Antero Investment to manage Antero Midstream’s business and affairs. Antero Investment will also indirectly hold the incentive distribution rights in the MLP. Antero Midstream will have an option to purchase the Company’s fresh water distribution systems at fair market value.

In October 2014 Antero Midstream commenced the initial public offering and on November 4, 2014, Antero Midstream Partners LP (successor to Antero Midstream “the Partnership”) announced the pricing of its initial public offering of 40,000,000 common units representing limited partner interests in the Partnership at $25.00 per common unit. The Partnership has also granted the underwriters a 30-day option to purchase up to an additional 6,000,000 common units. The offering is expected to close on November 10, 2014, subject to the satisfaction of customary closing conditions. For more information, please refer to the Partnership’s final prospectus filed with the SEC.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

(c)Stock Compensation Charge in Connection with the Reorganization

In connection with its formation in October 2009, Antero Resources LLC issued profits interests to Antero Resources Employee Holdings LLC (“Employee Holdings”), which is owned solely by certain of our officers and employees. These profits interests provide for the participation in distributions upon liquidation events meeting certain requisite financial return thresholds. In turn, Employee Holdings issued membership interests to certain of our officers and employees. The Employee Holdings interests in Antero Resources LLC were exchanged for similar interests in Antero Investment in connection with the corporate reorganization on October 16, 2013.

The limited liability company agreement of Antero Investment provides a mechanism that demonstrates how the shares of the Company’s common stock will be allocated among the members of Antero Investment, including Employee Holdings. As a result of the adoption of the Antero Investment Limited Liability company agreement, the satisfaction of all performance and service conditions relative to the profits interests awards held by Employee Holdings in Antero Investment became probable. Accordingly, we recognized approximately $433 million of stock compensation expense for the vested profits interests from the date of the IPO through September 30, 2014 and will recognize approximately an additional $53 million over the remaining service period. Stock compensation expense for the profits interests during the three and nine months ended September 30, 2014 was $15.7 million and $68.5 million, respectively. Because consideration for the profits interests awards is deemed given by Antero Investment, the charge to stock compensation expense is accounted for as a capital contribution by Antero Investment to the Company and credited to additional paid-in capital.

(2)Summary of Significant Accounting Policies

(a)Basis of Presentation

These 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, 2013 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2013 consolidated financial statements have been filed with the SEC in the Company’s 2013 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 September 30, 2014, and the results of its operations for the three and nine months ended September 30, 2013 and 2014, and its cash flows for the nine months ended September 30, 2013 and 2014. The Company has no items of other comprehensive income or loss; therefore, our net income or loss is identical to our comprehensive income or loss. All significant intercompany accounts and transactions have been eliminated. Operating results for the period ended September 30, 2014 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, and other factors.

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

Income from discontinued operations for the nine months ended September 30, 2014 results from reducing certain liabilities recorded upon the sale of our Arkoma Basin assets in 2012 upon the resolution of such liabilities.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

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 an amendment to our senior secured revolving bank credit facility as described in note 3, and the pricing of the initial public offering of common units of Antero Midstream Partners LP as described in note 1 (b).

(b)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 and 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 gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, amortization, and impairment of oil and gas properties. Reserve estimates by their nature are inherently imprecise.

(c)Risks and Uncertainties

Historically, the market for natural gas, NGLs, and oil has experienced significant price fluctuations. The price fluctuations can result from variations in weather, levels of production in the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company’s future results of operations.

(d)Cash and Cash Equivalents

The Company considers all liquid investments purchased with an initial maturity of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

(e)Derivative Financial Instruments

In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, basis swap agreements, collar agreements, and other similar agreements relating to the price risk associated with a portion of its production. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.

The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues on the Company’s condensed consolidated statements of operations.

(f)Income Taxes

The Company recognizes deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties for tax-related matters as income tax expense.

(g)Fair Value Measurements

FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter commodity price swaps, and basis swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures.

(h)Industry Segments and Geographic Information

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

All of our assets are located in the United States and all of our revenues are attributable to customers located in the United States.

i)Marketing Revenues and Expenses

In 2014, the Company commenced activities to purchase and sell third-party natural gas and to market its excess firm transportation capacity in order to utilize this excess capacity. Marketing revenues include sales of purchased third-party gas and revenues from the release of firm transportation capacity to others. Marketing expenses include the cost of purchased third-party natural gas. The Company classifies firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity (excess capacity) as marketing expenses since it is marketing this excess capacity to third parties. Firm transportation for which the Company has sufficient production capacity (even though it may not use the transportation capacity because of alternative delivery points with more favorable pricing) is considered unutilized capacity. The costs of unutilized capacity are charged to transportation expense.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

(j)Reclassifications

Certain reclassifications have been made to prior periods’ financial information related to fresh water distribution assets to conform to the 2014 presentation.

(j)Earnings per common share.

Earnings per common share were calculated based on the weighted average number of shares outstanding of 262,049,948 and 262,049,756 for the three and nine months ended September 30, 2014, respectively. Earnings per common share—assuming dilution for the three months ended September 30, 2014 was calculated based on the diluted weighted average number of shares outstanding of 262,069,878, including 19,930 dilutive shares attributable to non-vested restricted stock and restricted stock unit awards and stock options. Earnings per common share—assuming dilution for the nine months ended September 30, 2014 was calculated based on the diluted weighted average number of shares outstanding of 262,066,632, including 16,876 dilutive shares attributable to non-vested restricted stock and restricted stock unit awards.

For the three months ended September 30, 2014, 1,906,778 non-vested shares of restricted stock and restricted stock unit awards and 60,000 stock options were anti-dilutive and therefore excluded from the calculation of diluted earnings per share. For the nine months ended September 30, 2014, 929,223 non-vested shares of restricted stock and restricted stock awards and 70,339 stock options were anti-dilutive and therefore excluded from the calculation of diluted earnings per share.

Earnings per common share and earnings per common share—assuming dilution for the three and nine months ended September 30, 2013 were calculated as if the shares issued in the corporate reorganization and IPO described in note 1 were outstanding as of January 1, 2013.

(3)Long-Term Debt

The Company had long-term debt outstanding as follows at December 31, 2013 and September 30, 2014 (in thousands):


	2013		2014
Bank credit facility(a)	$	288,000		1,505,000
7.25% senior notes due 2019(b)		260,000		—
6.00% senior notes due 2020(c)		525,000		525,000
5.375% senior notes due 2021(d)		1,000,000		1,000,000
5.125% senior notes due 2022(e)		—		1,100,000
Net unamortized premium		5,999		7,866
	$	2,078,999		4,137,866

(a)Senior Secured Revolving Credit Facility

The Company has a senior secured revolving bank credit facility (the “Credit Facility”) with a consortium of bank lenders. The maximum amount of the Credit Facility was $3.5 billion at September 30, 2014. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. At September 30, 2014, the borrowing base was $3.0 billion and lender commitments were $2.5 billion, including $500 million of commitments under the Midstream Facility described below.

On October 16, 2014, the maximum amount of the Credit Facility was increased from $3.5 billion to $4.0 billion, the borrowing base was increased from $3.0 billion to $4.0 billion, and lender commitments were increased from $2.5 billion to $3.0 billion,

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

including $500 million of commitments under the Midstream Facility described below. Lender commitments can be increased to the full amount of the borrowing base upon approval of the lending group. The maturity date of the Credit Facility is May 5, 2019. The next redetermination of the borrowing base is scheduled to occur in April 2015.

On February 28, 2014, the Company and Midstream Operating entered into a new midstream credit facility (the “Midstream Facility”) in order to provide for separate borrowings attributable to our midstream business which contains covenants that are substantially identical to those under the Credit Facility. In accordance with the Credit Facility and the Midstream Facility, borrowings under the Midstream Facility reduce availability under the Credit Facility on a dollar-for-dollar basis. The Midstream Facility will mature at the earlier of the closing of the MLP’s initial public offering or May 12, 2016. If the MLP’s initial public offering is completed, it is expected that the MLP will enter into its own revolving credit facility.

The Credit Facility and the Midstream Facility are ratably secured by mortgages on substantially all of the Company’s properties and guarantees from the Company or its subsidiaries, as applicable. The Credit Facility and the Midstream Facility contain certain covenants, including restrictions on indebtedness and dividends, and, in the case of the Credit Facility, requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2013 and September 30, 2014.

As of September 30, 2014, the Company had a total outstanding balance under the Credit Facility and Midstream Facility of $1.505 billion, with a weighted average interest rate of 2.44%, and outstanding letters of credit of $332 million. As of December 31, 2013, the Company had an outstanding balance under the Credit Facility of $288 million, with a weighted average interest rate of 1.61%, and outstanding letters of credit of $32 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% based on utilization.

(b)7.25% Senior Notes Due 2019

On May 23, 2014, the Company redeemed the outstanding 7.25% senior notes due 2019 (the “2019 notes”) having a principal balance of $260 million at a redemption price of 100% of the principal amount plus a make-whole premium of $17.4 million. The make-whole premium along with the write-off of $3 million of deferred financing costs was charged to Loss on early extinguishment of debt in the accompanying statement of operations. The redemption was financed using a portion of the proceeds from the offering of the Company’s 5.125% senior notes due 2022 (the “2022 notes”) described below.

On November 19, 2012, the Company issued $300 million of 6.00% senior notes due December 1, 2020 (the “2020 notes”) at par. On February 4, 2013, the Company issued an additional $225 million of 2020 notes at 103% of par. The 2020 notes are unsecured and effectively subordinated to the Company’s Credit Facility and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2020 notes rank pari passu to our other outstanding senior notes. The 2020 notes are guaranteed on a senior unsecured basis by Antero Resources Midstream LLC and Antero Midstream LLC and certain of its future restricted subsidiaries. Interest on the 2020 notes is payable on June 1 and December 1 of each year. The Company may redeem all or part of the 2020 notes at any time on or after December 1, 2015 at redemption prices ranging from 104.50% on or after December 1, 2015 to 100.00% on or after December 1, 2018. In addition, on or before December 1, 2015, the Company may redeem up to 35% of the aggregate principal amount of the 2020 notes, with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 106.00% of the principal amount of the 2020 notes, plus accrued interest. At any time prior to December 1, 2015, the Company may redeem the 2020 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2020 notes plus a “make-whole” premium and accrued interest. If the Company undergoes a change of control, the holders of the 2020 notes will have the right to require the

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

Company to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2020 notes, plus accrued interest.

(d)5.375% Senior Notes Due 2021

On November 5, 2013, the Company 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 and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2021 notes rank pari passu to our other outstanding senior notes. The 2021 notes are guaranteed on a full and unconditional and joint and several basis by Antero Resources Midstream LLC and Antero Midstream LLC and certain of its future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. The Company 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, the Company may redeem up to 35% of the aggregate principal amount of the 2021 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.375% of the principal amount of the 2021 notes, plus accrued interest. At any time prior to November 1, 2016, the Company may also redeem the 2021 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2021 notes plus a “make-whole” premium and accrued interest. If the Company undergoes a change of control prior to May 1, 2015, it may redeem all, but not less than all, of the 2021 notes at a redemption price equal to 110% of the principal amount of the 2021 notes. If the Company undergoes a change of control, it may be required to offer to purchase the 2021 notes from the holders at a price equal to 101% of the principal amount of the 2021 notes, plus accrued interest.

(e)5.125% Senior Notes Due 2022

On May 6, 2014, the Company issued $600 million of 5.125% senior notes due December 1, 2022 (the “2022 notes”) at par. On September 18, 2014, the Company 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 and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2022 notes rank pari passu to our other outstanding senior notes. The 2022 notes are guaranteed on a full and unconditional and joint and several basis by Antero Resources Midstream LLC and Antero Midstream LLC and certain of its future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. The Company 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, the Company may redeem up to 35% of the aggregate principal amount of the 2022 notes, with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 105.125% of the principal amount of the 2022 notes, plus accrued interest. At any time prior to June 1, 2017, the Company may also redeem the 2022 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2022 notes plus a “make-whole” premium and accrued interest. If the Company undergoes a change of control prior to December 1, 2015, it may redeem all, but not less than all, of the 2022 notes at a redemption price equal to 110% of the principal amount of the 2022 notes. If the Company undergoes a change of control, the holders of the 2022 notes will have the right to require the Company to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued interest.

(f)Treasury Management Facility

The Company has a stand-alone revolving note with a lender under the Credit Facility which provides for up to $25.0 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2015. At December 31, 2013 and September 30, 2014, there were no outstanding borrowings under this facility.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

(4)Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2014 (in thousands). This amount is included in other long-term liabilities on the accompanying condensed consolidated Balance Sheet


Asset retirement obligations—beginning of period	$	11,859
Obligations incurred		1,495
Accretion expense		931
Asset retirement obligations—end of period	$	14,285

(5)Stock-Based Compensation

The Company is authorized to grant up to 16,906,500 stock-based compensation awards to employees and directors of the Company under the Antero Resources Corporation Long-Term Incentive Plan (the “Plan”). The Plan allows stock-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 the Company’s Board of Directors. A total of 14,839,533 shares are available for future grant under the Plan as of September 30, 2014.

Our stock-based compensation expense is as follows for the nine months ended September 30, 2014 (in thousands):


Profits interests awards (see note 1)	$	68,456
Restricted stock awards		16,993
Stock options		372
Total expense	$	85,821

Restricted Stock and Restricted Stock Unit Awards

Restricted stock and restricted stock unit awards vest subject to the satisfaction of service requirements. We recognize expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service 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 during the nine months ended September 30, 2014 is as follows:


		Weighted average		Aggregate
	Number of shares	grant date fair value		intrinsic value (in thousands)
Total awarded and unvested, December 31, 2013	45,093	$	54.27	$	2,861
Granted	1,954,815	$	64.92	$	107,300
Vested	(139)	$	53.52	$	(8)
Forfeited	(4,549)	$	59.60	$	(250)
Total awarded and unvested—September 30, 2014	1,995,220	$	64.74	$	109,518

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

Unamortized expense of $111.8 million at September 30, 2014 is expected to be recognized over approximately 3 to 4 years. Intrinsic values are based on the closing price of the Company’s stock on the referenced dates.

Stock Options

Stock options granted under the Plan to date vest over periods from one to four years and have a maximum contractual life of 10 years. We recognize expense related to stock options on a straight-line basis over the requisite service period, less awards expected to be forfeited. Stock options are granted with an exercise price equal to the market price of our common stock on the date of grant. A summary of stock option activity for the nine months ended September 30, 2014 is as follows:


				Weighted
		Weighted average		average remaining	Intrinsic
	Stock options	exercise price		contractual life	value (in thousands)
Outstanding at December 31, 2013	70,339	$	54.15	9.79	$	653
Options granted	—		—	—		—
Options exercised	—		—	—		—
Options cancelled	—		—	—		—
Options expired	—		—	—		—
Outstanding at September 30, 2014	70,339	$	54.15	9.04	$	52
Expected to vest as of September 30, 2014	70,339	$	54.15	9.04	$	52
Exercisable at September 30, 2014	—		—	—		—

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

We use a Black-Scholes option-pricing model to determine the grant-date fair value of our stock options. Expected volatility was derived from the volatility of the historical stock prices of a peer group of similar publicly traded companies’ stock prices. The risk-free interest rate was determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term approximating the expected life of the options. We assumed no dividend yield.

The following table presents information regarding the weighted average fair value for options granted and the assumptions used to determine fair value.


Dividend yield		—	%
Volatility		35	%
Risk-free interest rate		1.48	%
Expected life (years)		6.17
Weighted average fair value of options granted	$	20.20

As of September 30, 2014, there was $0.9 million of unrecognized stock-based compensation expense related to nonvested stock options. That expense is expected to be recognized over a weighted average period of 3 years.

(6)Financial Instruments

The carrying values of trade receivables and trade payables at December 31, 2013 and September 30, 2014 approximated market value because of their short-term nature. The carrying value of the bank credit facility at December 31, 2013 and September 30, 2014 approximated fair value because the variable interest rates are reflective of current market conditions.

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

Based on Level 2 market data inputs, the fair value of the Company’s senior notes was approximately $1.9 billion at December 31, 2013 and $2.6 billion at September 30, 2014.

See note 7 for information regarding the fair value of derivative financial instruments.

(7)Derivative Instruments

(a)Commodity Derivatives

The Company periodically enters into natural gas and oil derivative contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas 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 and oil recognized upon the ultimate sale of the natural gas and oil produced.

For the nine months ended September 30, 2013 and 2014, the Company was party to natural gas and oil fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price the Company receives the difference from the counterparty. In addition, the Company has entered into basis swap contracts hedging the difference between the NYMEX index price and a local index price. When the actual differential exceeds the fixed price provided by the basis swap contract, the Company receives the difference from the counterparty; when the differential is less than the fixed price provided by the basis swap contract, the Company pays the difference to the counterparty. The Company’s natural gas and oil swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in our statements of operations.

As of September 30, 2014, the Company’s fixed price natural gas and oil swaps positions from October 1, 2014 through December 31, 2019 were as follows (abbreviations in the table refer to the index to which the swap position is tied: TCO=Columbia Gas Transmission; NYMEX=Henry Hub; CGTLA=Columbia Gas Louisiana Onshore; CCG=Chicago City Gate; NYMEX-WTI=West Texas Intermediate):

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014


			Weighted
	Natural gas	Oil	average index
	MMbtu/day	Bbls/day	price
Three Months ending December 31, 2014
TCO	210,000		$	5.24
Dominion South	160,000		$	5.27
NYMEX	340,000		$	4.18
CGTLA	10,000		$	3.98
NYMEX-WTI	—	3,000	$	93.18
Total	720,000	3,000

Year ending December 31, 2015:
TCO	120,000		$	5.01
Dominion South	230,000		$	5.60
NYMEX	260,000		$	4.13
CGTLA	40,000		$	4.00
2015 Total	650,000

Year ending December 31, 2016:
TCO	60,000		$	4.91
Dominion South	272,500		$	5.35
NYMEX	140,000		$	4.17
CGTLA	170,000		$	4.09
2016 Total	642,500

Year ending December 31, 2017:
NYMEX	290,000		$	4.38
CGTLA	420,000		$	4.27
CCG	70,000		$	4.57
2017 Total	780,000

Year ending December 31, 2018:
NYMEX	1,062,500		$	4.50

Year ending December 31, 2019:
NYMEX	807,500		$	4.41

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

As of September 30, 2014, the Company’s natural gas basis swap positions, which settle on the pricing index to basis differential of TCO to the NYMEX Henry Hub natural gas price, are as follows:


	Natural gas MMbtu/day	Hedged Differential

Year ending December 31, 2015:	390,000	$	(0.35)

Year ending December 31, 2016:	190,000	$	(0.42)

Year ending December 31, 2017:	97,500	$	(0.50)

(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, 2013 and September 30, 2014. None of the Company’s derivative instruments are designated as hedges for accounting purposes.


	December 31, 2013			September 30, 2014
	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	$	183,000	Current assets	$	280,959
Commodity contracts	Long-term assets		677,780	Long-term assets		458,209

Total asset derivatives			860,780			739,168

Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities		646	Current liabilities		—
Commodity contracts	Long-term liabilities		—	Long-term liabilities		86

Total liability derivatives			646			86

Net derivatives		$	860,134		$	739,082

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value (in thousands):


	December 31, 2013				September 30, 2014
	Gross amounts on balance sheet		Gross amounts offset on balance sheet	Net amounts of assets (liabilities) 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	$	887,034	(26,254)	860,780	$	792,075	(52,907)	739,168
Commodity derivative liabilities	$	(646)	—	(646)	$	(2,677)	2,591	(86)

The following is a summary of derivative fair value gains (losses) and where such values are recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2013 and 2014 (in thousands):



	Statement of operations	Three Months Ended September 30,				Nine Months Ended September 30,
	location	2013		2014		2013		2014
Commodity derivative fair value gains (losses)	Revenue	$	161,968		308,975		285,510		(63,720)

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

(8)Contingencies

The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company believes 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 liquidity.

(9)Segment Information

The operating results and assets of the Company’s reportable segments were as follows for the three months ended September 30, 2013 and 2014 (in thousands):


	Exploration and		Gathering and	Fresh water	Elimination of intersegment	Consolidated
	production		compression	distribution	transactions	total
2013:
Sales and revenues:
Third-party	$	384,522	—	—	—	384,522
Intersegment		—	7,138	9,856	(16,994)	—
	$	384,522	7,138	9,856	(16,994)	384,522

Operating income	$	222,551	1,413	7,718	(9,074)	222,608
Segment assets	$	5,587,703	466,029	132,648	(514,172)	5,672,208
Capital expenditures for segment assets	$	526,998	88,382	64,871	(9,372)	670,879

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014


	Exploration and		Gathering and	Fresh water		Elimination of intersegment	Consolidated
	production		compression	distribution	Marketing	transactions	total
2014:
Sales and revenues:
Third-party	$	739,780	1,884	2,991	17,835	—	762,490
Intersegment		—	24,398	42,310	—	(66,708)	—
	$	739,780	26,282	45,301	17,835	(66,708)	762,490

Operating income (loss)	$	390,773	7,012	29,732	(14,357)	(31,761)	381,399
Segment assets	$	8,696,189	1,071,273	396,691	9,084	(857,357)	9,315,880
Capital expenditures for segment assets	$	936,059	144,999	56,540	—	(34,826)	1,102,772

The operating results and assets of the Company’s reportable segments were as follows for the nine months ended September 30, 2013 and 2014 (in thousands):


	Exploration and		Gathering and	Fresh water	Elimination of intersegment	Consolidated
	production		compression	distribution	transactions	total
2013:
Sales and revenues:
Third-party	$	833,120	—	—	—	833,120
Intersegment		—	12,630	22,662	(35,292)	—
	$	833,120	12,630	22,662	(35,292)	833,120

Operating income (loss)	$	425,679	(380)	17,414	(20,188)	422,525
Segment assets	$	5,587,703	466,029	132,648	(514,172)	5,672,208
Capital expenditures for segment assets	$	1,532,150	240,119	101,838	(20,845)	1,853,262


	Exploration and		Gathering and	Fresh water		Elimination of intersegment	Consolidated
	production		compression	distribution	Marketing	transactions	total
2014:
Sales and revenues:
Third-party	$	1,207,023	4,831	7,133	23,048	—	1,242,035
Intersegment		—	50,147	103,445	—	(153,592)	—
	$	1,207,023	54,978	110,578	23,048	(153,592)	1,242,035

Operating income (loss)	$	305,084	8,251	67,847	(35,071)	(74,094)	272,017
Segment assets	$	8,696,189	1,071,273	396,691	9,084	(857,357)	9,315,880
Capital expenditures for segment assets	$	2,335,936	406,666	156,467	—	(81,493)	2,817,576

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

(10)Subsidiary Guarantors

Antero Resources Midstream LLC and Antero Midstream LLC have fully and unconditionally guaranteed the Company’s outstanding senior notes. The following Condensed Consolidating Balance Sheets as of December 31, 2013 and September 30, 2014 present financial information for Antero Resources Corporation as the Parent on a stand-alone basis (carrying its investment in subsidiaries using the equity method), combined financial information for the subsidiary guarantors (Antero Resources Midstream LLC and Antero Midstream LLC) as a group, and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis. The guarantor subsidiaries had no revenues, expenses, or cash flow during the year ended December 31, 2013 or the three and nine months ended September 30, 2014. The guarantor subsidiaries are not restricted from making distributions to the Company.

Condensed Consolidating Balance Sheets

December 31, 2013

(In thousands)


	Parent		Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	17,487		—		—		17,487
Other		316,077		1		(1)		316,077
Total current assets		333,564		1		(1)		333,564

Property and equipment, net		5,559,656		—		—		5,559,656
Other long-term assets		720,361		—		—		720,361
Investment in subsidiary		1		—		(1)		—
	$	6,613,582		1		(2)		6,613,581

Liabilities and Stockholders’ Equity

Current liabilities	$	622,229		—		—		622,229
Long-term debt		2,078,999		—		—		2,078,999
Other long-term liabilities		313,693		—		—		313,693
Due to subsidiary		1		—		(1)		—
Total liabilities		3,014,922		—		(1)		3,014,921

Stockholders’ equity		3,598,660		1		(1)		3,598,660
Total liabilities and equity	$	6,613,582		1		(2)		6,613,581

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ANTERO RESOURCES CORPORATION

Notes to Condensed Consolidated Financial Statements

December 31, 2013 and September 30, 2014

September 30, 2014

(In thousands)


	Parent		Guarantor Subsidiaries		Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	6,308		—		—		6,308
Other		496,395		1		(1)		496,395
Total current assets		502,703		1		(1)		502,703

Property and equipment, net		8,286,985		—		—		8,286,985
Other long-term assets		526,192		—		—		526,192
Investment in subsidiary		1		—		(1)		—
	$	9,315,881		1		(2)		9,315,880

Liabilities and Stockholders’ Equity

Current liabilities	$	1,064,036		—		—		1,064,036
Long-term debt		4,137,866		—		—		4,137,866
Other long-term liabilities		362,556		—		—		362,556
Due to subsidiary		1		—		(1)		—
Total liabilities		5,564,459		—		(1)		5,564,458

Stockholders’ equity		3,751,422		1		(1)		3,751,422
Total liabilities and equity	$	9,315,881		1		(2)		9,315,880

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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, 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.

In this section, references to “Antero,” “Antero Resources,” “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 exploitation, 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. As of September 30, 2014, we held approximately 516,000 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.

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.

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 June 30, 2014, our estimated proved reserves were approximately 9.1 Tcfe, consisting of 7.9 Tcf of natural gas, 186 MMBbl of NGLs, and 16 MMBbl of oil. This represents a 19% increase from proved reserve volumes at December 31, 2013. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of June 30, 2014, we had approximately 5,011 potential horizontal well locations on our existing leasehold acreage, both proven and unproven.

We believe we have secured sufficient long-term firm takeaway capacity on major pipelines that are operating or are currently under construction in each of our core operating areas to accommodate our current development plans.

We operate in the following industry segments: (i) the exploration, development and production of natural gas, NGLs, and oil, (ii) gathering and compression, (iii) fresh water distribution, 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 our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. These documents are located www.anteroresources.com under the “Investors Relations” link.

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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.

2014 Developments and Highlights

Production and Financial Results

For the three months ended September 30, 2014, we generated cash flow from operations of $301 million, net income from continuing operations of $204 million, and Adjusted EBITDAX of $292 million. Net income from continuing operations of $204 million for the three months ended September 30, 2014 included $309 million of net commodity derivative gains, of which $57 million related to cash settled derivative gains, deferred tax expense of $135 million, and stock compensation expense of $24 million. This compares to cash flow from operations of $140 million, net income from continuing operations of $118 million, and Adjusted EBITDAX of $183 million for the three months ended September 30, 2013. 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, 2014, we generated cash flow from operations of $799 million, net income from continuing operations of $65 million, and Adjusted EBITDAX of $832 million. Net income from continuing operations of $65 million for the nine months ended September 30, 2014 included $64 million of commodity derivative losses, net of $57 million of cash settled derivative gains, a $20 million loss on the early extinguishment of debt, deferred tax expense of $76 million, and stock compensation expense of $86 million. This compares to cash flow from operations of $332 million, net income from continuing operations of $201 million, and Adjusted EBITDAX of $434 million for the nine months ended September 30, 2013. 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).

For the three months ended September 30, 2014, our production totaled approximately 99 Bcfe, or 1.08 Bcfe per day, a 91% increase compared to 52 Bcfe, or 566 MMcfe per day, for the three months ended September 30, 2013. The average price received for production for the three months ended September 30, 2014 was $4.33 per Mcfe before the effects of cash settled commodity hedges compared to $4.27 per Mcfe for the three months ended September 30, 2013. Average prices after the effects of cash settled commodity hedges were $4.91 per Mcfe for the three months ended September 30, 2014 compared to $5.18 per Mcfe for the three months ended September 30, 2013.

For the nine months ended September 30, 2014, our production totaled approximately 251 Bcfe, or 920 MMcfe per day, a 96% increase compared to 128 Bcfe, or 470 MMcfe per day, for the nine months ended September 30, 2013. The average price received for production for the nine months ended September 30, 2014 was $5.06 per Mcfe before the effects of cash settled commodity hedges compared to $4.27 per Mcfe for the nine months ended September 30, 2013. Average prices after the effects of cash settled commodity hedges were $5.29 per Mcfe for the nine months ended September 30, 2014 compared to $5.12 per Mcfe for the nine months ended September 30, 2013.

2014 Capital Budget

During the nine months ended September 30, 2014, our total capital expenditures were approximately $2.8 billion, including drilling and completion costs of $1.7 billion, gathering and compression project costs of $407 million, fresh water distribution project costs of $156 million, leasehold acquisition costs of $518 million, and other capital expenditures of $13 million. Our revised capital expenditure budget for 2014 is $3.7 billion and includes the following: $2.4 billion for drilling and completion; $850 million for the expansion of gathering and compression facilities, including $200 million for fresh water distribution infrastructure, and $450 million for core leasehold acreage acquisitions. We do not budget for producing property acquisitions. Substantially all of the $2.4 billion allocated for drilling and completion is allocated to our operated drilling in rich gas areas. Approximately 76% of our drilling and completion budget is allocated to the Marcellus Shale, and the remaining 24% is allocated to the Utica Shale. Our revised 2014 capital budget assumes a drilling and completion program that averages 21 rigs during the year. We periodically review capital expenditures and adjust our budget based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Credit Facility Amendment

On October 16, 2014, our revolving credit facility (the “Credit Facility”) was amended to increase maximum borrowings under the facility from $3.5 billion to $4.0 billion, increase the borrowing base from $3.0 billion to $4.0 billion, and increase lender

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commitments from $2.5 billion to $3.0 billion, including $500 million of commitments under the Midstream Facility. Lender commitments can be increased to the full amount of the borrowing base upon approval of the lending group. The maturity date of the facility is May 5, 2019. The borrowing base under the Credit Facility is redetermined semiannually and is based on the lenders’ judgment of the volume of our proved oil and gas reserves, the estimated future cash flows from these reserves, and the value of our hedge positions. The next redetermination is scheduled to occur in April 2015.

Issuance of 5.125% Notes due 2022

On September 18, 2014, we issued an additional $500 million of the 2022 notes at 100.5% of par. The proceeds from the additional issuance of 2022 notes were used to pay down amounts outstanding under our Credit Facility.

Our outstanding senior notes totaling $2.625 billion now have interest rates ranging from 5.125% to 6.00% and have due dates ranging from December 1, 2020 to December 1, 2022.

Hedge Position

As of September 30, 2014, we had entered into hedging contracts for October 1, 2014 through December 31, 2019 for 1.5 Tcf of our projected natural gas production at a weighted average index price of $4.55 per MMbtu and 276,000 Bbls of oil at a weighted average price of $93.18 per Bbl. These hedging contracts include contracts for the year ended December 31, 2014 of approximately 66 Bcf of natural gas at a weighted average index price of $4.73 per Mcf and 276,000 Bbls of oil at $93.18 per Bbl.

In addition, we had entered into natural gas basis differential positions for 2015 through 2017 for 247 Bcf at a weighted average index price of $0.39 which settle on the pricing index to basis differential of Columbia Gas (TCO) to the NYMEX Henry Hub natural gas price.

Pending Midstream MLP IPO

On February 7, 2014, our subsidiary, Antero Resources Midstream LLC filed a Registration Statement on Form S-1 with the SEC relating to an initial public offering of common units representing limited partner interests. If the offering is closed, Antero Resources Midstream LLC will convert from a limited liability company into a Delaware master limited partnership (Antero Midstream Partners LP, or the “Partnership”) and we intend to contribute midstream assets to the Partnership as well as the right to develop additional midstream infrastructure to service our growing production. On November 4, 2014, the Partnership announced the pricing of its initial public offering of 40,000,000 common units representing limited partner interests in the Partnership at $25.00 per common unit. The Partnership has also granted the underwriters a 30-day option to purchase up to an additional 6,000,000 common units. The offering is expected to close on November 10, 2014, subject to the satisfaction of customary closing conditions. For more information, please refer to the Partnership’s final prospectus filed with the SEC.

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Results of Operations

Three months ended September 30, 2013 Compared to Three months ended September 30, 2014

The following table sets forth selected operating data for the three months ended September 30, 2013 compared to the three months ended September 30, 2014:



	Three Months Ended September 30,				Amount of Increase
(in thousands, except per unit and production data)	2013		2014		(Decrease)		Percent Change
Operating revenues:
Natural gas sales	$	182,125		310,390		128,265	70	%
NGL sales		31,956		91,111		59,155	185	%
Oil sales		8,473		29,304		20,831	246	%
Gathering, compression, and water distribution		—		4,875		4,875	*
Marketing		—		17,835		17,835	*
Commodity derivative fair value gains		161,968		308,975		147,007	*
Total operating revenues		384,522		762,490		377,968	98	%
Operating expenses:
Lease operating		2,697		8,680		5,983	222	%
Gathering, compression, processing, and transportation		58,383		128,531		70,148	120	%
Production and ad valorem taxes		11,851		21,726		9,875	83	%
Marketing		—		32,192		32,192	*
Exploration		5,372		7,476		2,104	39	%
Impairment of unproved properties		3,205		4,542		1,337	42	%
Depletion, depreciation, and amortization		65,697		124,624		58,927	90	%
Accretion of asset retirement obligations		266		320		54	20	%
General and administrative (before stock compensation)		14,443		28,790		14,347	99	%
Stock compensation		—		24,210		24,210	*
Total operating expenses		161,914		381,091		219,177	135	%
Operating income		222,608		381,399		158,791	71	%

Other Expenses:
Interest expense		(37,444)		(42,455)		(5,011)	13	%
Income before income taxes and discontinued operations		185,164		338,944		153,780	83	%
Income tax expense		(67,370)		(135,035)		(67,665)	100	%
Income from continuing operations		117,794		203,909		86,115	73	%
Income from discontinued operations		3,100		—		(3,100)	*
Net income	$	120,894		203,909		83,015	69	%

Adjusted EBITDAX (1)	$	182,834		291,572		108,738	59	%

Production data:
Natural gas (Bcf)		48		86		38	79	%
NGLs (MBbl)		637		1,953		1,316	206	%
Oil (MBbl)		87		348		261	299	%
Combined (Bcfe)		52		99		47	91	%
Daily combined production (MMcfe/d)		566		1,080		514	91	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.82	$	3.63	$	(0.19)	(5)	%
NGLs (per Bbl)	$	50.13	$	46.66	$	(3.47)	(7)	%
Oil (per Bbl)	$	97.10	$	84.17	$	(12.93)	(13)	%
Combined (per Mcfe)	$	4.27	$	4.33	$	0.06	1	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	4.81	$	4.31	$	(0.50)	(10)	%
NGLs (per Bbl)	$	50.13	$	46.66	$	(3.47)	(7)	%
Oil (per Bbl)	$	94.71	$	82.47	$	(12.24)	(13)	%
Combined (per Mcfe)	$	5.18	$	4.91	$	(0.27)	(5)	%
Average Costs (per Mcfe):
Lease operating	$	0.05	$	0.09	$	0.04	80	%
Gathering, compression, processing, and transportation	$	1.12	$	1.29	$	0.17	15	%
Production and ad valorem taxes	$	0.23	$	0.22	$	(0.01)	(4)	%
Depletion, depreciation, amortization, and accretion	$	1.27	$	1.26	$	(0.01)	(1)	%
General and administrative (before stock compensation)	$	0.28	$	0.29	$	0.01	4	%

(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).

(2)

Average sales prices shown in the table reflect both of the before and after effects of our cash settled derivatives. Our calculation of such after effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL 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.

*Not meaningful or applicable

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Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $223 million for the three months ended September 30, 2013 to $431 million for the three months ended September 30, 2014, an increase of $208 million, or 94%. Our production increased by 91% over that same period, from 52 Bcfe, or 566 MMcfe per day, for the three months ended September 30, 2013 to 99 Bcfe, or 1.08 Bcfe per day, for the three months ended September 30, 2014. Net equivalent prices before the effects of realized hedge gains increased from $4.27 per Mcfe for the three months ended September 30, 2013 to $4.33 for the three months ended September 30, 2014, an increase of 1%. The 1% increase in net equivalent prices for the three months ended September 30, 2014 compared to the prior year quarter resulted from an increase in the mix of production of NGLs and oil compared to the prior year quarter, which was partially offset by decreases in the prices of natural gas, NGLs, and oil. Increased production volumes accounted for an approximate $202 million increase in year-over year revenues (calculated as the change in year-to-year volumes times the prior year average price), and increases in our equivalent prices accounted for an approximate $6 million increase in year-over-year 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 ongoing drilling program.

Commodity derivative fair value gains. To achieve more predictable cash flows, and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas and oil production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge 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, 2013 and 2014, our hedges resulted in derivative fair value gains of $162 million and $309 million, respectively. The derivative fair value gains included $47 million and $57 million of cash settlements received on derivatives for the three months ended September 30, 2013 and 2014, respectively. Commodity derivative fair value gains or losses will vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled. Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas and oil strip 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.

Gathering, compression, and water distribution. Beginning in the fourth quarter of 2013, we began to recognize our midstream gathering, compression, and water distribution operations as reportable segments. Gathering, compression, and water distribution fees of $4.9 million during the three months ended September 30, 2014 represent the portion of such fees that are charged to outside working interest owners and other third parties. Such fees were immaterial in the prior year period and were netted against gathering expenses and capital expenditures.

Marketing. In 2014, we began to purchase and sell third-party natural gas and market our excess firm transportation capacity in order to utilize our excess firm transportation capacity. Marketing revenues of $18 million and expenses of $32 million for the three months ended September 30, 2014 relate to these activities. Marketing costs include firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity and the cost of third-party purchased gas. This includes firm transportation costs of $11 million for the three months ended September 30, 2014 related to an ethane transportation contract which is not being utilized because we are not currently recovering ethane. We enter into long-term firm transportation agreements for a significant part of our current and expected future production in order to secure guaranteed capacity on major pipelines.

Lease operating expenses. Lease operating expenses increased from $2.7 million for the three months ended September 30, 2013 to $8.7 million for the three months ended September 30, 2014, an increase of 222%. The increase is a result of the increase in the number of producing wells. On a per unit basis, lease operating expenses increased from $0.05 per Mcfe for the three months ended September 30, 2013 to $0.09 for the three months ended September 30, 2014. Lease operating expenses per unit have increased as an increased proportion of wells have been on production for longer periods of time compared to the prior year period. Lease operating expenses are expected to increase on a per unit basis as properties mature and production declines on a per well basis.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $58 million for the three months ended September 30, 2013 to $129 million for the three months ended September 30, 2014. The increase in these expenses is a result of the increase in production, firm transportation commitments, and third-party gathering and compression expenses. On a per-Mcfe basis, total gathering, compression, processing and transportation expenses increased from $1.12 per Mcfe for the three months ended September 30, 2013 to $1.29 for the three months ended September 30, 2014 as a larger proportion of our gas was processed compared to the prior year quarter.

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Production and ad valorem tax expense. Total production and ad valorem taxes increased from $12 million for the three months ended September 30, 2013 to $22 million for the three months ended September 30, 2014, primarily as a result of increased production and midstream assets subject to ad valorem taxes. Legislative proposals in the State of Ohio to increase severance taxes on production from horizontally drilled wells could increase our future production tax rates, if such legislation is enacted.

Exploration expense. Exploration expense of $5.4 million for the three months ended September 30, 2013 increased to $7.5 million for the three months ended September 30, 2014 primarily because of an increase in the cost of unsuccessful lease acquisitions due to an increase in lease acquisition efforts.

Impairment of unproved properties. Impairment of unproved properties was approximately $3.2 million for the three months ended September 30, 2013 compared to $4.5 million for the three months ended September 30, 2014. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage, and recognize impairment costs accordingly.

DD&A. DD&A increased from $66 million for three months ended September 30, 2013 to $125 million for the three months ended September 30, 2014, primarily because of increased production. DD&A per Mcfe decreased by 1%, from $1.27 per Mcfe during the three months ended September 30, 2013 to $1.26 per Mcfe during the three months ended September 30, 2014, primarily due to an increase in our proved developed reserves.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the three months ended September 30, 2013 or 2014 for proved properties.

General and administrative and stock compensation expense. General and administrative expense (before stock compensation expense) increased from $14 million for the three months ended September 30, 2013 to $29 million for the three months ended September 30, 2014, primarily as a result of increased staffing levels and related salary and benefits expenses, as well as increases in legal and other general corporate expenses, all of which are due to our growth in development activities and production levels. On a per unit basis, general and administrative expense before stock compensation increased by only 4%, from $0.28 per Mcfe during the three months ended September 30, 2013 to $0.29 per Mcfe during the three months ended September 30, 2014 because a 91% increase in production largely offset the increase in expenses. We had 204 employees as of September 30, 2013 and 384 employees as of September 30, 2014.

Noncash stock compensation expense of $24 million for the three months ended September 30, 2014 included a charge of $16 million for the amortization of expense related to the vesting of profits interests issued upon the completion of our IPO in 2013. See note 1 to the consolidated financial statements included elsewhere in this report for more information on the vested profits interest charge.

Interest expense. Interest expense increased from $37 million for the three months ended September 30, 2013 to $42 million for the three months ended September 30, 2014, primarily due to increased indebtedness. Interest expense includes approximately $2 million of non-cash amortization of deferred financing costs for each of the three months ended September 30, 2013 and 2014.

Income tax expense. Income tax expense increased from $67 million for the three months ended September 30, 2013 to $135 million for the three months ended September 30, 2014 because of the increase in pre-tax income compared to the prior year quarter. Stock compensation expense of $16 million related to the vested profits interests charge is not deductible for federal or state income taxes and, along with the effect of state taxes, largely accounts 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, 2014.

At December 31, 2013, we had approximately $1.2 billion of U.S. federal net operating loss carryforwards (NOLs) and approximately $1.1 billion of state NOLs, which expire from 2024 through 2033. 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

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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.

The calculation of our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements include unrecognized benefits at September 30, 2014 of $11 million that, if recognized, would result in a reduction of current income taxes payable and an increase in noncurrent deferred tax liabilities. As of September 30, 2014, we have accrued approximately $0.8 million of interest on unrecognized tax benefits.

The Internal Revenue Service recently completed its examination of the tax returns of Antero Resources Finance Corporation (which was merged with Antero Resources Corporation in December 2013) for its tax years 2011 and 2012. There were no adjustments to our tax returns as a result of the examination. The Company’s state tax returns are being examined by West Virginia taxing authorities for tax years 2010 through 2012. The Company does not expect any material adjustments to tax liabilities will result from the examination.

Income from discontinued operations. On December 21, 2012, we completed the sale of our Piceance Basin assets in Colorado and recorded a loss in connection with the sale. The loss on the sale of the Piceance Basin assets was adjusted downward by $5.0 million (before tax expense of $1.9 million) for the three months ended September 30, 2013 as a result of the resolution of certain liabilities recorded at the time of the sale and the settlement of final purchase price adjustments.

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Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2014

The following table sets forth selected operating data for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2014:



	Nine Months Ended September 30,				Amount of Increase
(in thousands, except per unit and production data)	2013		2014		(Decrease)		Percent Change
Operating revenues:
Natural gas sales	$	476,403		936,877		460,474	97	%
NGL sales		59,772		244,807		185,035	310	%
Oil sales		11,435		89,059		77,624	679	%
Gathering, compression, and water distribution		—		11,964		11,964	*
Marketing		—		23,048		23,048	*
Commodity derivative fair value gains (losses)		285,510		(63,720)		(349,230)	*
Total operating revenues		833,120		1,242,035		408,915	49	%
Operating expenses:
Lease operating		5,222		18,570		13,348	256	%
Gathering, compression, processing, and transportation		148,023		315,878		167,855	113	%
Production and ad valorem taxes		30,578		64,123		33,545	110	%
Marketing		—		58,119		58,119	*
Exploration		17,034		21,176		4,142	24	%
Impairment of unproved properties		9,564		7,895		(1,669)	(17)	%
Depletion, depreciation, and amortization		158,650		320,984		162,334	102	%
Accretion of asset retirement obligations		797		931		134	17	%
General and administrative (before stock compensation)		40,727		76,521		35,794	88	%
Stock compensation		—		85,821		85,821	*
Total operating expenses		410,595		970,018		559,423	136	%
Operating income		422,525		272,017		(150,508)	(36)	%

Other Expenses:
Interest expense		(100,840)		(111,057)		(10,217)	10	%
Loss on early extinguishment of debt		—		(20,386)		(20,386)	*
Total other expenses		(100,840)		(131,443)		(30,603)	30	%
Income before income taxes and discontinued operations		321,685		140,574		(181,111)	(56)	%
Income tax expense		(120,695)		(75,919)		44,776	(37)	%
Income from continuing operations		200,990		64,655		(136,335)	(68)	%
Income from discontinued operations		3,100		2,210		(890)	(29)	%
Net income	$	204,090		66,865		(137,225)	(67)	%

Adjusted EBITDAX (1)	$	434,191		831,690		397,499	92	%

Production data:
Natural gas (Bcf)		120		217		97	81	%
NGLs (MBbl)		1,197		4,602		3,405	285	%
Oil (MBbl)		122		1,010		888	728	%
Combined (Bcfe)		128		251		123	96	%
Daily combined production (MMcfe/d)		470		920		450	96	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.96	$	4.31	$	0.35	9	%
NGLs (per Bbl)	$	49.95	$	53.20	$	3.25	7	%
Oil (per Bbl)	$	93.76	$	88.15	$	(5.61)	(6)	%
Combined (per Mcfe)	$	4.27	$	5.06	$	0.79	19	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	4.87	$	4.58	$	(0.29)	(6)	%
NGLs (per Bbl)	$	49.95	$	53.20	$	3.25	7	%
Oil (per Bbl)	$	90.28	$	86.57	$	(3.71)	(4)	%
Combined (per Mcfe)	$	5.12	$	5.29	$	0.17	3	%
Average Costs (per Mcfe):
Lease operating	$	0.04	$	0.07	$	0.03	75	%
Gathering, compression, processing, and transportation	$	1.15	$	1.26	$	0.11	10	%
Production and ad valorem taxes	$	0.24	$	0.26	$	0.02	8	%
Depletion, depreciation, amortization, and accretion	$	1.24	$	1.28	$	0.04	3	%
General and administrative (before stock compensation)	$	0.32	$	0.30	$	(0.02)	(6)	%

(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).

(2)

*Not meaningful or applicable

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Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $548 million for the nine months ended September 30, 2013 to $1.3 billion for the nine months ended September 30, 2014, an increase of $723 million, or 132%. Our production increased by 96% over that same period, from 128 Bcfe, or 470 MMcfe per day, for the nine months ended September 30, 2013 to 251 Bcfe, or 920 MMcfe per day, for the nine months ended September 30, 2014. Net equivalent prices before the effects of realized hedge gains increased from $4.27 per Mcfe for the nine months ended September 30, 2013 to $5.06 for the nine months ended September 30, 2014, an increase of 19%. The 19% increase in net equivalent prices for the nine months ended September 30, 2014 compared to the prior year period resulted from a 9% increase in natural gas prices; the remaining 10% increase resulted from an increase in the mix of production of NGLs and oil compared to the prior year period and increased prices for NGLs. Increased production volumes accounted for an approximate $525 million increase in year-over year revenues (calculated as the change in year-to-year volumes times the prior year average price), and commodity price increases accounted for an approximate $198 million increase in year-over-year 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 ongoing drilling program.

Commodity derivative fair value gains (losses). To achieve more predictable cash flows, and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas and oil production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge 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, 2013 and 2014, our hedges resulted in derivative fair value gains (losses) of $286 million and $(64) million, respectively. The derivative fair value gains and losses included $109 million and $57 million of cash settlements received on derivatives for the nine months ended September 30, 2013 and 2014, respectively. Commodity derivative fair value gains or losses will vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled. Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas and oil strip 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.

Gathering, compression, and water distribution. Beginning in the fourth quarter of 2013, we began to recognize our midstream gathering, compression, and water distribution operations as reportable segments. Gathering, compression, and water distribution fees of $12 million during the nine months ended September 30, 2014 represent the portion of such fees that are charged to outside working interest owners and other third parties. Such fees were immaterial in the prior year period and were netted against gathering expenses.

Marketing. In 2014, we began to purchase and sell third-party natural gas and market our excess firm transportation capacity in order to utilize our excess firm transportation capacity. Marketing revenues of $23 million and expenses of $58 million for the nine months ended September 30, 2014 relate to these activities. Marketing costs include firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize the capacity and the cost of third-party purchased gas. This includes firm transportation costs of $33 million for the nine months ended September 30, 2014 related to an ethane transportation contract which is not being utilized because we are not currently recovering ethane. We enter into long-term firm transportation agreements for a significant part of our current and expected future production in order to secure guaranteed capacity on major pipelines.

Lease operating expenses. Lease operating expenses increased from $5.2 million for the nine months ended September 30, 2013 to $18.6 million for the nine months ended September 30, 2014, an increase of 256%. The increase is a result of the increase in the number of producing wells. On a per unit basis, lease operating expenses increased from $0.04 per Mcfe for the nine months ended September 30, 2013 to $0.07 for the nine months ended September 30, 2014. Lease operating expenses per unit have increased as an increased proportion of wells have been on production for longer periods of time compared to the prior year period. Lease operating expenses are expected to increase on a per unit basis as properties mature and production declines on a per well basis.

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $148 million for the nine months ended September 30, 2013 to $316 million for the nine months ended September 30, 2014. The increase in these expenses is a result of the increase in production, firm transportation commitments, and third-party gathering and compression expenses. On a per-Mcfe basis, total gathering, compression, processing and transportation

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expenses increased from $1.15 per Mcfe for the nine months ended September 30, 2013 to $1.26 for the nine months ended September 30, 2014 as a larger proportion of our gas was processed compared to the prior year period.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $31 million for the nine months ended September 30, 2013 to $64 million for the nine months ended September 30, 2014, primarily as a result of increased production and midstream assets subject to ad valorem taxes. Legislative proposals in the State of Ohio to increase severance taxes on production from horizontally drilled wells could increase our future production tax rates, if such legislation is enacted.

Exploration expense. Exploration expense increased from $17 million for the nine months ended September 30, 2013 to $21 million for the nine months ended September 30, 2014 primarily because of an increase in the cost of unsuccessful lease acquisitions due to an increase in lease acquisition efforts.

Impairment of unproved properties. Impairment of unproved properties was approximately $9.6 million for the nine months ended September 30, 2013 compared to $7.9 million for the nine months ended September 30, 2014. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage, and recognize impairment costs accordingly.

DD&A. DD&A increased from $159 million for nine months ended September 30, 2013 to $321 million for the nine months ended September 30, 2014, primarily because of increased production. DD&A per Mcfe increased by 3%, from $1.24 per Mcfe during the nine months ended September 30, 2013 to $1.28 per Mcfe during the nine months ended September 30, 2014, primarily as a result of increased depreciation on midstream assets and facilities.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the nine months ended September 30, 2013 or 2014 for proved properties.

General and administrative and stock compensation expense. General and administrative expense (before stock compensation expense) increased from $41 million for the nine months ended September 30, 2013 to $77 million for the nine months ended September 30, 2014, primarily as a result of increased staffing levels and related salary and benefits expenses, as well as increases in legal and other general corporate expenses, all of which are due to our growth in development activities and production levels. On a per unit basis, general and administrative expense before stock compensation decreased by 6%, from $0.32 per Mcfe during the nine months ended September 30, 2013 to $0.30 per Mcfe during the nine months ended September 30, 2014, primarily due to a 96% increase in production. We had 204 employees as of September 30, 2013 and 384 employees as of September 30, 2014.

Noncash stock compensation expense of $86 million for the nine months ended September 30, 2014 included a charge of $68 million for the amortization of expense related to vested profits interests issued upon the completion of our IPO in 2013. See note 1 to the consolidated financial statements included elsewhere in this report for more information on the vested profits interest charge.

Interest expense. Interest expense increased from $101 million for the nine months ended September 30, 2013 to $111 million for the nine months ended September 30, 2014, primarily due to increased indebtedness. Interest expense includes approximately $5 million and $6 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2013 and 2014, respectively.

Loss on early extinguishment of debt. On May 23, 2014, we redeemed the outstanding 7.25% senior notes due 2019, having a principal balance of $260 million, at a redemption price of 100% of the principal amount plus a make-whole premium of $17.4 million. The make-whole premium along with the write-off of $3 million of deferred financing costs was charged to loss on early extinguishment of debt in the accompanying statements of operations. The redemption was financed using a portion of the proceeds from the initial offering of our 2022 notes on May 6, 2014.

Income tax expense. Income tax expense decreased from $121 million for the nine months ended September 30, 2013 to $76 million for the nine months ended September 30, 2014 because of the decrease in pre-tax income compared to the prior year period.

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Stock compensation expense of $68 million related to the vested profits interest charge is not deductible for federal or state income taxes and, along with the effect of state taxes, largely accounts 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, 2014.

At December 31, 2013, we had approximately $1.2 billion of U.S. federal NOLs and approximately $1.1 billion of state NOLs, which expire from 2024 through 2033. 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.

Income from discontinued operations. On December 21, 2012, we completed the sale of our Piceance Basin assets in Colorado and recorded a loss in connection with the sale. The loss on the sale of the Piceance Basin assets was adjusted downward by $5.0 million (before tax expense of $1.9 million) for the nine months ended September 30, 2013 as a result of the resolution of certain liabilities recorded at the time of the sale and the settlement of final purchase price adjustments.

On June 29, 2012, we completed the sale of our Arkoma Basin assets in Oklahoma and recorded a loss in connection with the sale. The loss on the sale of the Arkoma Basin assets was adjusted downward by $3.6 million (before tax expense of $1.4 million) for the nine months ended September 30, 2014 as a result of the resolution of certain liabilities recorded at the time of the sale.

Capital Resources and Liquidity

Our primary sources of liquidity have been proceeds from issuances of equity securities and senior notes, borrowings under our revolving credit facilities, asset sales, and net cash provided by operating activities. Our primary use of cash has been for the exploration, development, and acquisition of unconventional natural gas and oil properties. 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 expenditures, and liquidity requirements. Our future success in growing 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 should 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.

The following table summarizes our cash flows for the nine months ended September 30, 2013 and 2014:



	Nine Months Ended September 30,
(in thousands)	2013		2014
Net cash provided by operating activities	$	331,937	$	798,746
Net cash used in investing activities		(1,864,884)		(2,824,472)
Net cash provided by financing activities		1,525,542		2,014,547
Net decrease in cash and cash equivalents	$	(7,405)	$	(11,179)

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Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $332 million and $799 million for the nine months ended September 30, 2013 and 2014, respectively. The increase in cash flow from operations from the nine months ended September 30, 2013 compared to the nine months ended September 30, 2014 was primarily the result of increased production volumes, offset in part by increases in cash operating costs, interest expense, and changes in working capital levels.

Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for natural gas, NGLs, and oil, as well as our production volumes. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, and other variable factors influence 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, 2014, we used cash totaling $2.8 billion in investing activities, including $1.7 billion for drilling and completion costs, $518 million for undeveloped leasehold acquisitions, $156 million for fresh water distribution facilities, $407 million for gathering and compression systems, and $13 million for other property and equipment. During the nine months ended September 30, 2013, we used cash totaling $1.9 billion in investing activities, including $1.1 billion for drilling and completion costs, $343 million for undeveloped leasehold acquisitions, $102 million for fresh water distribution systems, and $240 million for gathering and compression systems.

Our board of directors has approved a revised capital budget of $3.7 billion for 2014. 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 to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods in order to achieve a desirable balance between sources and uses of liquidity, and 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 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, 2014 of $2.0 billion consisted of net additional borrowings on our Credit Facility and the Midstream Facility of $1.2 billion and the issuance of $1.1 billion of our 5.125% Senior Notes, net of $305 million for retirements of senior notes and payments for early redemption premiums and deferred financing costs. Net cash provided by financing activities of $1.5 billion for the nine months ended September 30, 2013 resulted from the issuance of $225 million of our 6.00% Senior Notes at a premium of 3%, $1.3 billion of net additional borrowings on our Credit Facility, net of payments of deferred financing costs of $8.3 million, and other items of $6.6 million.

Senior Secured Revolving Credit Facility. On October 16, 2014, the Credit Facility was amended to increase maximum borrowings under the facility from $3.5 billion to $4.0 billion, increase the borrowing base from $3.0 billion to $4.0 billion, and increase lender commitments from $2.5 billion to $3.0 billion, including $500 million of commitments under the Midstream Facility. Lender commitments can be increased to the full $4.0 billion upon the approval of the lenders. The maturity date of the facility is May 2019. The borrowing base is redetermined semi-annually and is based on the lenders’ judgment of the volume of our proved oil and gas reserves and the estimated future cash flows from these reserves and the value of our hedge positions. The next redetermination is scheduled to occur in April 2015. At September 30, 2014, we had $1.505 billion of borrowings and $332 million of letters of credit outstanding under the Credit Facility and the Midstream Facility. At December 31, 2013, we had $288 million of borrowings and $32 million of letters of credit outstanding under the Credit Facility.

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The Credit Facility and the Midstream Facility are ratably secured by mortgages on substantially all of our properties and guarantees from the Company or its subsidiaries, as applicable. Interest is payable at a variable rate based on LIBOR or the prime rate based on our election at the time of borrowing.

The Credit Facility and the Midstream Facility contain certain covenants, including restrictions on indebtedness, asset sales, investments, liens, dividends, hedging, and certain other transactions without the prior consent of the lenders. We are required to maintain the following two financial ratios:

a current ratio, which is the ratio of our consolidated current assets (including any unused borrowing base under the Credit Facility and excluding derivative assets) to our consolidated current 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 consolidated EBITDAX to consolidated interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

The actual borrowing capacity available to us may be limited by these current ratio and minimum interest coverage ratio covenants. At September 30, 2014, our current ratio was 1.45 to 1.0 (based on the $3.0 billion borrowing base in effect as of September 30, 2014) and our interest coverage ratio was 6.95 to 1.0.

Senior Notes. We have $525 million of 6.00% senior notes outstanding, which are due December 1, 2020. The 2020 notes are unsecured and effectively subordinated to the Credit Facility and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2020 notes rank pari passu to our other outstanding senior notes. The 2020 notes are guaranteed on a senior unsecured basis by Antero Resources Midstream LLC and Antero Midstream LLC and certain of our future restricted subsidiaries. Interest on the 2020 notes is payable on June 1 and December 1 of each year. We may redeem all or part of the 2020 notes at any time on or after December 1, 2015 at redemption prices ranging from 104.50% on or after December 1, 2015 to 100.00% on or after December 1, 2018. In addition, on or before December 1, 2015, we may redeem up to 35% of the aggregate principal amount of the 2020 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 106.00% of the principal amount of the 2020 notes, plus accrued interest. At any time prior to December 1, 2015, we may redeem the 2020 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2020 notes plus a “make-whole” premium and accrued interest. If we undergo a change of control, the holders of the 2020 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2020 notes, plus accrued interest.

We also have $1 billion of 5.375% senior notes outstanding, which are due November 1, 2021. The 2021 notes are unsecured and effectively subordinated to the Credit Facility and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2021 notes rank parri passu to our other outstanding senior notes. The 2021 notes are guaranteed by Antero Resources Midstream LLC and Antero Midstream LLC and certain of our future restricted subsidiaries. Interest on the 2021 notes is payable on May 1 and November 1 of each year. We 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, we 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%. At any time prior to November 1, 2016, we may also redeem the 2021 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2021 notes plus a “make-whole” premium and accrued interest. If we undergo a change of control prior to May 1, 2015, we may redeem all, but not less than all, of the 2021 notes at a redemption price equal to 110% of the principal amount of the 2021 notes. If we undergo a change of control, we may be required to offer to purchase the 2021 notes from the holders at a price equal to 101% of the principal amount of the 2021 notes, plus accrued interest.

We also have $1.1 billion of 5.125% senior notes outstanding, which are due December 1, 2022. The 2022 notes are unsecured and effectively subordinated to the Credit Facility and the Midstream Facility to the extent of the value of the collateral securing such facilities. The 2022 notes rank parri passu to our other outstanding senior notes. The 2022 notes are guaranteed by Antero Resources Midstream LLC and Antero Midstream LLC and certain of our future restricted subsidiaries. Interest on the 2022 notes is payable on June 1 and December 1 of each year. We may redeem all or part of the 2021 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, we 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%. At any time prior to June 1, 2017, we may also redeem the 2022

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notes, in whole or in part, at a price equal to 100% of the principal amount of the 2022 notes plus a “make-whole” premium and accrued interest. If we undergo a change of control prior to December 1, 2015, we may redeem all, but not less than all, of the 2022 notes at a redemption price equal to 110% of the principal amount of the 2022 notes. If we undergo a change of control, the holders of the 2022 notes will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the 2022 notes, plus accrued interest.

We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under the Credit Facility, redeem previously issued senior notes, and for development of our oil and natural gas properties.

The senior notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained. We were in compliance with such covenants as of December 31, 2013 and September 30, 2014.

Treasury Management Facility. We have 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 our 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 June 1, 2015. At September 30, 2014 and December 31, 2013, there were no outstanding borrowings under this facility.

Non-GAAP Financial Measure

“Adjusted EBITDAX” is a non-GAAP financial measure that we define as net income 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, exploration expense, franchise taxes, stock compensation, loss on early extinguishment of debt, and gain or loss on sale of assets. “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 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, as a basis for strategic planning and forecasting, and by our lenders pursuant to covenants under the 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 effect 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. The following table represents a reconciliation of our net income (loss) from continuing operations to Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case, for the periods presented:

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	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2013		2014		2013		2014

Net income from continuing operations	$	117,794	$	203,909	$	200,990	$	64,655
Commodity derivative fair value (gains) losses(1)		(161,968)		(308,975)		(285,510)		63,720
Net cash receipts on settled derivative instruments(1)		47,034		57,451		109,311		57,333
Interest expense		37,444		42,455		100,840		111,057
Loss on early extinguishment of debt		—		—		—		20,386
Income tax expense		67,370		135,035		120,695		75,919
Depreciation, depletion, amortization, and accretion		65,963		124,944		159,447		321,915
Impairment of unproved properties		3,205		4,542		9,564		7,895
Exploration expense		5,372		7,476		17,034		21,176
Stock compensation expense		—		24,285		—		85,896
State franchise taxes		620		450		1,820		1,738
Adjusted EBITDAX from continuing operations		182,834		291,572		434,191		831,690
Net income from discontinued operations		3,100		—		3,100		2,210
Gain on sale of assets		(5,000)		—		(5,000)		(3,564)
Income tax expense		1,900		—		1,900		1,354
Adjusted EBITDAX from discontinued operations		—		—		—		—
Total adjusted EBITDAX		182,834		291,572		434,191		831,690
Interest expense		(37,444)		(42,455)		(100,840)		(111,057)
Exploration expense		(5,372)		(7,476)		(17,034)		(21,176)
Changes in current assets and liabilities		(1,194)		55,621		13,529		96,153
State franchise taxes		(620)		(450)		(1,820)		(1,738)
Other noncash items		1,336		3,905		3,911		4,874
Net cash provided by operating activities	$	139,540	$	300,717	$	331,937	$	798,746

(1)

The adjustments for the derivative fair value (gains) losses and net cash received on settled commodity derivative instruments have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivative instruments, which are recognized at the end of each accounting period. As a result, commodity derivate gains and losses are reflected on a cash basis in the calculation of Adjusted EBITDAX for 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 oil and gas production activities, estimates of natural gas and oil reserve quantities and standardized measures of future cash flows, and impairment of unproved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in our 2013 Form 10-K. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. Also, see note 2 of the notes to our audited consolidated financial statements, included in our 2013 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

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New Accounting Pronouncements

On May 28, 2014, the 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 U.S. GAAP when it becomes effective. The new standard is effective for the Company on January 1, 2017. Early application is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is evaluating the effect that ASU 2014-09 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 standard on its ongoing financial reporting.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases. See “—Contractual Obligations” for commitments under operating leases, drilling rig and frac service agreements, firm transportation, and gas processing and compression service agreements.

Contractual Obligations

Contractual Obligations. A summary of our contractual obligations as of September 30, 2014 is provided in the following table.


	Year
(in millions)	1		2		3		4		5		Thereafter		Total

Credit Facility and Midstream Facility(1)	$	—	$	500	$	—	$	—	$	1,005	$	—	$	1,505
Senior notes—principal(2)		—		—		—		—		—		2,625		2,625
Senior notes—interest(2)		146		142		141		141		142		353		1,065
Drilling rig and frac service commitments(3)		249		174		130		—		—		—		553
Firm transportation (4)		264		498		789		838		921		10,523		13,833
Gas processing, gathering, and compression services (5)		323		230		244		245		205		1,088		2,335
Office and equipment leases		8		9		7		6		5		11		46
Asset retirement obligations(6)		—		—		—		—		—		14		14
Total	$	990	$	1,553	$	1,311	$	1,230	$	2,278	$	14,614	$	21,976

(1)

Includes outstanding principal amount at September 30, 2014. This table does not include future commitment fees, interest expense or other fees on the Credit Facility and 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)

Includes the 6.00% notes due 2020, the 5.375% notes due 2021, and the 5.125% notes due 2022.

(3)

At September 30, 2014, we had contracts for the services of 21 rigs which expire at various dates from 2014 through 2016. We also had contracts for the services of 5 frac fleets which expire at various dates from 2015 through 2017. 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)

We have entered into 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 represent our minimum daily volumes at the reservation fee rate. 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 gas processing, gathering and compression services agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the

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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.

(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.

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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, and 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 instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity Price Risk

Our primary market risk exposure is in the price we receive for our natural gas, NGL, and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas, NGLs, and oil production has been volatile and unpredictable for several years, 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 natural gas and oil prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our natural gas and oil production when management believes that favorable future prices can be secured.

Our financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. These contracts may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, cashless price collars that set a floor and ceiling price for the hedged production, or basis differential swaps. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference. The Company was not party to any collars during the nine months ended September 30, 2014.

At September 30, 2014, we had in place natural gas and oil swaps covering portions of our projected production from 2014 through 2019. Our hedge position as of September 30, 2014 is summarized in note 7 to our consolidated financial statements included elsewhere herein. Our financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas and oil price fluctuations. Our Credit Facility allows us to enter into hedging contracts for periods through December 31, 2020. The facility allows hedging contracts up to 85% of our estimated production from proved reserves for up to 12 months in the future, 80% for 13 to 24 months in the future, 75% for 25 to 36 months in the future, 70% for 37 to 48 months in the future, 65% for 49 to 60 months in the future, and 65% of production for periods beyond 60 months in the future. Based on our production and our fixed price swap contracts in place during the nine months ended September 30, 2014, we estimate that revenues from production, as adjusted for cash settled derivatives, for the nine months ended September 30, 2014 would have decreased by approximately $7 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGL prices.

All derivative instruments, other than those that meet the normal purchase and normal sales 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 accounting hedge 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. We present realized and unrealized gains or losses on commodity derivatives in our 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 flow is only impacted by our derivative instruments when the associated derivative contracts are settled by making or receiving payments to or from the counterparty. At September 30, 2014, the estimated fair value of our commodity derivative instruments was a net asset of $739 million comprised of current and noncurrent assets, and noncurrent liabilities. At

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December 31, 2013, the estimated fair value of our commodity derivative instruments was a net asset of $860 million comprised of current and noncurrent assets, and current liabilities.

By removing price volatility from a portion of our expected natural gas and oil production, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flows. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($739 million at September 30, 2014) and the sale of our oil and gas production ($144 million at September 30, 2014).

By using derivative instruments that are not traded on an exchange to hedge 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 deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have economic hedges in place with ten different counterparties, all of which are lenders under our Credit Facility. The fair value of our commodity derivative contracts of approximately $739 million at September 30, 2014 includes the following values by bank counterparty: BNP Paribas - $193 million; Credit Suisse - $154 million; Wells Fargo - $129 million; JP Morgan - $109 million; Barclays - $106 million; Citigroup - $32 million; and Fifth Third - $16 million. The credit ratings of certain of these banks were downgraded in recent years because of the sovereign debt crisis in Europe. The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2014 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, 2014, 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.

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which has a floating interest rate. The average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2014, was approximately 2.44%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2014 would have resulted in an estimated $9.5 million increase in interest expense for the nine months ended September 30, 2014.

Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (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. 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

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financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2014 at the reasonable assurance level.

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, 2014 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 the U.S. Environmental Protection Agency (the “EPA”) 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 pertaining to unpermitted discharges of fill material into wetlands or waters 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.

The Company has been named in separate lawsuits in Colorado, West Virginia, and Pennsylvania in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties and their persons. The plaintiffs have requested unspecified damages and other injunctive or equitable relief. The Company denies any such allegations and intends to vigorously defend itself against these actions. We are unable to estimate the amount of monetary or other damages, if any, that might result from these claims.

The Company is party to various other legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

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 2013 Form 10-K. The risks described in our 2013 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 2013 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.

Item 5.Other Information.

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 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 US 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).

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 and (ii) beneficially own more than 10% of the equity interests of, and have the right to designate members of the board of directors of Endurance International Group (“EIG”) and Santander Asset Management Investment Holdings Limited (“SAMIH”). EIG and 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 EIG and SAMIH and its non-U.S. affiliates that may be deemed to be under common “control” with us. 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 of EIG and SAMIH, and neither we nor WP has independently verified or participated in the preparation of the disclosures. Neither we nor WP is representing to the accuracy or completeness of the disclosures nor do we or WP undertake any obligation to correct or update them.

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As to EIG:

Antero Resources Corporation understands that EIG’s affiliates intend to disclose in their next annual or quarterly SEC report that: “On or around September 26, 2014, during a routine compliance scan of new and existing subscriber accounts, EIG or its affiliates discovered that Seyed Mahmoud Mohaddes (“Mohaddes”) was named as the account contact for a subscriber account (the “Subscriber Account”). Previously, on July 2, 2013, before Mohaddes had been designated as a SDN, the billing information for the Subcriber Account was updated to include Mohaddes. On September 16, 2013, the Office of Foreign Assets Control (“OFAC”) designated Mohaddes as a Specially Designated National (“SDN”), pursuant to 31 C.F.R. Part 560.304. EIG discovered Mohaddes when its routine compliance scan identified an attempt on or around September 26, 2014 to add Mohaddes, an SDN, as the account contact to the Subscriber Account. EIG blocked the Subscriber Account that day and reported the domain name registered to the Subscriber Account to OFAC as potentially the property of a SDN, subject to blocking pursuant to Executive Order 13599. Since September 16, 2013, when Mohaddes was added to the SDN list, charges in the total amount of $120.35 were made to the Subscriber Account for web hosting and domain privacy services. EIG ceased billing for the Subscriber Account. To date, EIG has not received any correspondence from OFAC regarding this matter.

On July 10, 2014, OFAC designated each of Stars Group Holding (“Stars”), and Teleserve Plus SAL (“Teleserve”), as SDNs under Executive Order 13224, and their property became subject to blocking pursuant to the Global Terrorism Sanctions Regulations, 31 C.F.R. Part 594. On July 15, 2014, as part of EIG’s compliance review processes, they discovered that the domain names associated with each of Stars and Teleserve (the “Stars/Teleserve Domain Names”) were registered through our platform. EIG immediately took steps to suspend and lock the Stars/Teleserve Domain Names to prevent them from being transferred or resolving to a website, and they promptly reported the Domain Names as potentially blocked property to OFAC. EIG did not generate any revenue from the Stars/Teleserve Domain Names since they were added to the SDN list on July 10, 2014. To date, EIG has not received any correspondence from OFAC regarding the matter.

On July 15, 2014 during a compliance scan of all domain names on one of its platforms, EIG identified the domain name Kahanetzadak.com (the “Domain Name”), which was listed as an AKA of the entity Kahane Chai which operates as the American Friends of the United Yeshiva and was designated as a SDN on November 2, 2001 pursuant to Executive Order 13224. Since the Domain Name was transferred into one of EIG’s reseller's customer's account, there was no direct financial transaction between EIG and the registered owner of the Domain Name. The Domain name was suspended upon discovering it on their platform, and EIG will be reporting the Domain Name to OFAC as potentially the property of a SDN.”

As to SAMIH:

Antero Resources Corporation understands that SAMIH’s affiliates intend to disclose in their next annual or quarterly SEC report that an Iranian national, resident in the U.K., who is currently designated by the U.S. under the Iranian Financial Sanctions Regulations and the Weapons of Mass Destruction Proliferators Sanctions Regulations (“NPWMD sanctions program”), holds a mortgage and two investment accounts with Santander Asset Management UK Limited. No further drawdown has been made (or would be permitted) under this mortgage although Santander UK continues to receive repayment installments. In the nine months ended September 30, 2014, total revenue in connection with the mortgage was approximately £1,800 and net profits were negligible relative to the overall profits of Santander UK. The same Iranian national also holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen for the nine months ended September 30, 2014. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. In the nine months ended September 30, 2014, the total revenue for the Santander Group in connection with the investment accounts was £190 and net profits were negligible relative to the overall profits of Banco Santander, S.A.

In addition, during the third quarter 2014, Santander UK identified two additional customers: a UK national designated by the U.S. under the NPWMD sanctions program who holds a business account, where no transaction have taken place. Such account is in the process of being closed. No revenue or profit has been generated. A second UK national designated by the US for reasons of terrorism held a personal current account and a personal credit card account in the third quarter 2014, both of which have now been closed. Although transactions have taken place on the current account during the reportable period, revenue and profits generated were negligible. No transactions have taken place on the credit card.

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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 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


Date: November 5, 2014	By:	/s/ GLEN C. WARREN, JR.
		Glen C. Warren, Jr.
		President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX


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 September 18, 2014, by and among Antero Resources Corporation, the subsidiary guarantors named therein and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K (Commission File No. 001-36120) filed on September 24, 2014).

10.1		Twelfth Amendment to Fourth Amended and Restated Credit Agreement, dated as of July 28, 2014, by and among Antero Resources Corporation, as Borrower, certain subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on July 31, 2014).

10.2		Thirteenth Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 8, 2014, by and among Antero Resources Corporation, as Borrower, certain subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 001-36120) filed on September 10, 2014).

10.3		Second Amendment to Credit Agreement, dated as of July 28, 2014, by and among Antero Midstream LLC, as Borrower, certain subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and J.P. Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (Commission File No. 001-36120) filed on July 31, 2014).

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 Form 10-Q of Antero Resources Corporation for the quarter ended September 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as blocks of text.

The exhibits marked with the asterisk symbol (*) are filed or furnished (in the case of Exhibits 32.1 and 32.2) with this Form 10-Q.