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

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

o	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. x Yes o 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). x Yes o 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 o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(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) o Yes x No

The registrant had 262,049,659 shares of common stock outstanding as of May 6, 2014.

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TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		i
PART I—FINANCIAL INFORMATION		1
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	33
Item 4.	Controls and Procedures	34
PART II—OTHER INFORMATION		35
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 6.	Exhibits	36
SIGNATURES		37

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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 our midstream 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 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 (the “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.

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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 March 31, 2014

(Unaudited)

(In thousands, except share amounts)

Assets		2013		2014
Current assets:
Cash and cash equivalents	$	17,487		12,580
Accounts receivable — trade, net of allowance for doubtful
accounts of $1,251 in 2013 and 2014		30,610		27,250
Notes receivable - short-term portion		2,667		1,333
Accrued revenue		96,825		145,675
Derivative instruments		183,000		130,679
Other		2,975		4,405
Total current assets		333,564		321,922
Property and equipment:
Oil and gas properties, at cost (successful efforts method):
Unproved properties		1,513,136		1,543,118
Proved properties		3,621,672		4,191,186
Fresh water distribution systems		231,684		290,132
Gathering and compression systems		584,626		713,485
Other property and equipment		15,757		26,731
		5,966,875		6,764,652
Less accumulated depletion, depreciation, and amortization		(407,219	)	(498,425	)
Property and equipment, net		5,559,656		6,266,227
Derivative instruments		677,780		500,882
Other assets, net		42,581		45,426
Total assets	$	6,613,581		7,134,457
Liabilities and Equity
Current liabilities:
Accounts payable	$	370,640		428,938
Accrued liabilities		77,126		125,102
Revenue distributions payable		96,589		136,563
Deferred income tax liability		69,191		43,182
Derivative instruments		646		17,623
Other		8,037		9,398
Total current liabilities		622,229		760,806
Long-term liabilities:
Long-term debt		2,078,999		2,535,819
Deferred income tax liability		278,580		263,927
Other long-term liabilities		35,113		40,867
Total liabilities		3,014,921		3,601,419
Stockholders’ Equity:
Common stock, $0.01 par value; authorized - 1,000,000,000 shares; issued and outstanding 262,049,659 shares		2,620		2,620
Preferred stock, $0.01 par value; authorized - 50,000,000 shares; none issued		—		—
Additional paid-in capital		3,402,180		3,431,317
Accumulated earnings		193,860		99,101
Total stockholders’ equity		3,598,660		3,533,038
Total liabilities and equity	$	6,613,581		7,134,457

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Loss

Three Months Ended March 31, 2013 and 2014

(Unaudited)

(In thousands, except per share amounts)

		2013		2014
Revenue:
Natural gas sales	$	121,946		312,336
Natural gas liquids sales		10,572		73,928
Oil sales		877		24,122
Gathering, compression, and water distribution		—		3,524
Commodity derivative fair value losses		(71,941	)	(248,929	)
Total revenue		61,454		164,981
Operating expenses:
Lease operating		1,071		4,869
Gathering, compression, processing, and transportation		40,970		92,265
Production and ad valorem taxes		8,619		21,039
Exploration		4,362		6,997
Impairment of unproved properties		1,556		1,397
Depletion, depreciation, and amortization		40,364		91,206
Accretion of asset retirement obligations		264		302
General and administrative (including stock compensation of $29,137 in 2014)		12,717		50,985
Total operating expenses		109,923		269,060
Operating loss		(48,469	)	(104,079	)
Interest expense		(29,928	)	(31,342	)
Loss before income taxes		(78,397	)	(135,421	)
Provision for income tax benefit		30,400		40,662
Net loss and comprehensive loss	$	(47,997	)	(94,759	)
Loss per common share	$	(0.18	)	(0.36	)
Loss per common share - assuming dilution	$	(0.18	)	(0.36	)

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Equity

Three Months Ended March 31, 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
Stock compensation		—	29,137	—		29,137
Net loss and comprehensive loss		—	—	(94,759	)	(94,759	)
Balances, March 31, 2014	$	2,620	3,431,317	99,101		3,533,038

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ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Three Months Ended March 31, 2013 and 2014

(Unaudited)

(In thousands)

		2013			2014
Cash flows from operating activities:
Net loss	$		(47,997	)	(94,759	)
Adjustment to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		40,628			91,508
Impairment of unproved properties		1,556			1,397
Derivative fair value losses		71,941			248,929
Cash receipts (payments) for settled derivatives		48,131			(1,071	)
Deferred income tax benefit		(30,400		)	(40,662	)
Stock compensation		—			29,137
Other		1,387			3,182
Changes in assets and liabilities:
Accounts receivable		(10,545		)	3,360
Accrued revenue		(5,948		)	(48,850	)
Other current assets		11,711			(96	)
Accounts payable		(1,584		)	(5,718	)
Accrued liabilities		24,290			47,976
Revenue distributions payable		7,037			39,974
Net cash provided by operating activities		110,207			274,307
Cash flows used in investing activities:
Additions to unproved properties		(148,972		)	(60,149	)
Drilling and completion costs		(334,965		)	(496,221	)
Additions to fresh water distribution systems		(9,020		)	(60,030	)
Additions to gathering and compression systems		(55,975		)	(107,523	)
Additions to other property and equipment		(721		)	(7,783	)
Change in other assets		1,768			(3,807	)
Net cash used in investing activities		(547,885		)	(735,513	)
Cash flows from financing activities:
Issuance of senior notes		231,750			—
Borrowings on bank credit facility, net		187,000			457,000
Payments of deferred financing costs		(3,014		)	(701	)
Other		7,759			—
Net cash provided by financing activities		423,495			456,299
Net decrease in cash and cash equivalents		(14,183		)	(4,907	)
Cash and cash equivalents, beginning of period		18,989			17,487
Cash and cash equivalents, end of period	$		4,806		12,580
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$		16,160		13,087
Supplemental disclosure of noncash investing activities:
Changes in accounts payable for additions to property and equipment	$		88,843		64,016

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 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. Antero Investment also sold 3,409,091 shares of its common stock of Antero Resources Corporation in the IPO. The Company did not receive any of the proceeds from the sale of the shares by Antero Investment.

In 2013, the Company formed a subsidiary, Antero Midstream. The Company owns all of the common economic interest in Antero Midstream and Antero Investment indirectly owns the special membership interest. In connection with a planned initial public offering of Antero Midstream during 2014, the Company intends to contribute its midstream assets to Antero Midstream and has entered into commercial arrangements for midstream services. The assets will be contributed to Midstream Operating, which will be contributed to Antero Midstream. The assets to be contributed consist of (i) low- and high-pressure natural gas gathering lines, (ii) oil and condensate gathering lines, (iii) fresh water distribution systems and (iv) compression facilities. The special membership interest in Antero Midstream provides Antero Investment with certain rights,

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

including the right to cause an initial public offering of Antero Midstream as a master limited partnership (“MLP”) or similar structure. Following any such 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. Following any such initial public offering, Antero Investment will also indirectly hold the incentive distribution rights in the MLP.

(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 by which the shares of the Company’s common stock to be allocated among the members of Antero Investment, including Employee Holdings, will be determined. As a result of the adoption of the Antero Investment LLC 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 $365 million of stock compensation expense for the vested profits interests through December 31, 2013 and will recognize an additional approximate $121 million over the remaining service period. Stock compensation expense for the profits interests during the three months ended March 31, 2014 was $28.7 million. 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 in 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 Annual Report on Form 10-K for the year ended December 31, 2013.

The accompanying unaudited 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 consolidated financial statements include all adjustments (consisting of

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of March 31, 2014, and the results of its operations for the three months ended March 31, 2013 and 2014, and its cash flows for the three months ended March 31, 2013 and 2014. The Company has no items of other comprehensive income or loss; therefore, our net loss is identical to our comprehensive loss. All significant intercompany accounts and transactions have been eliminated. Operating results for the period ended March 31, 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 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.

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 as described in note 11.

(b) Use of Estimates

The preparation of consolidated financial statements in conformity with generally accepted accounting principles in the United States 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 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, present value of cash flows from reserves, 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. Prices for natural gas have been particularly volatile in recent years. 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.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

(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, collar agreements, and other similar agreements relating to natural gas and oil expected to be produced. 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.

(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. 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 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 that are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

inputs include nonexchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, and interest rate 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

We have 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, and (3) fresh water distribution.

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) 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 (loss) per share.

Loss per common share and loss per common share—assuming dilution for the three months ended March 31, 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. Because of the losses incurred for both the three months ended March 31, 2013 and 2014, the effect of options and restricted stock awards is antidilutive.

(3) Long-Term Debt

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

		2013	2014
Bank credit facility(a)	$	288,000	745,000
7.25% senior notes due 2019(b)		260,000	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
Net unamortized premium		5,999	5,819
	$	2,078,999	2,535,819

(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 $2.5 billion at

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

March 31, 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 March 31, 2014, the borrowing base was $2.0 billion and lender commitments were $1.5 billion. Lender commitments can be increased to the full amount of the borrowing base upon approval of the lending group.

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 and the maturity of the Credit Facility.

On May 5, 2014, the maximum amount of the Credit Facility was increased from $2.5 billion to $3.5 billion and the borrowing base was increased from $2.0 billion to $3.0 billion. Lender commitments were increased from $1.5 billion to $2.0 billion. The maturity date of the facility was amended from May 2016 to May 2019. The next redetermination of the borrowing base is scheduled to occur in October 2014.

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 March 31, 2014.

As of March 31, 2014, the Company had an outstanding balance under the Credit Facility of $745 million, with a weighted average interest rate of 1.94%, and outstanding letters of credit of $73 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% of the unused facility based on utilization.

(b) 7.25% Senior Notes Due 2019

On August 1, 2011, the Company issued the 7.25% senior notes due August 1, 2019 (the “2019 notes”) at par. The 2019 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 2019 notes are guaranteed on a senior unsecured basis by the Company’s existing subsidiaries and certain its future restricted subsidiaries. Interest on the 2019 notes is payable on August 1 and February 1 of each year. The Company may redeem all or part of the notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017. At any time prior to August 1, 2014, the Company may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make- whole” premium and accrued interest. If the Company undergoes a change of control, the holders of the 2019 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 notes, plus accrued interest.

On November 25, 2013, the Company redeemed $140 million of the 2019 notes out of the proceeds from the IPO. On April 23, 2014, the Company delivered notice of its election to redeem the 2019 notes that remain outstanding on May 23, 2014 at a redemption price of 100% of the principal amount thereof plus a “make-whole” premium and accrued interest. The redemption will be financed using a portion of the proceeds from the offering of the Company’s 5.125% senior subordinated notes due 2022 (the “2022 notes”) described in note 11.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

(c) 6.00% Senior Notes Due 2020

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 the 2019 notes and 2021 notes (as defined below). The 2020 notes are guaranteed on a senior unsecured basis by the Company’s existing subsidiaries 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 104.500% 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 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 are guaranteed on a full and unconditional and joint and several basis by the Company’s existing subsidiaries 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, 2014, 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, 2016, 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) 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

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

1.0%. The note matures on June 1, 2014. At March 31, 2014 and December 31, 2013, there were no outstanding borrowings under this facility.

(4) Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2014 (in thousands).

Asset retirement obligations—beginning of period	$	11,859
Obligations incurred		261
Accretion expense		302
Asset retirement obligations—end of period	$	12,422

(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 16,779,323 shares are available for future grant under the Plan as of March 31, 2014.

Our stock-based compensation expense is as follows for the three months ended March 31, 2014 (in thousands):

Profits interests awards (see note 1)	$	28,689
Restricted stock awards		309
Stock options		139
Total expense	$	29,137

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

Restricted Stock and Restricted Stock Unit Awards

Restricted stock awards vest subject to the satisfaction of service requirements. The grant date fair value of these awards are determined based on the 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 three months ended March 31, 2014 is as follows:

	Number of shares			Weighted average grant date fair value		Aggregate intrinsic value (in thousands)
Total granted and unvested, December 31, 2013	45,093		$	54.27	$	2,861
Granted	13,795		$	56.82		863
Vested	—
Forfeited	(2,050	)	$	55.63		(128	)
Total awarded and unvested—March 31, 2014	56,838		$	54.27	$	3,558

Unamortized expense of $2.3 million at March 31, 2014 is expected to be recognized over approximately 3 years.

Subsequent to March 31, 2014, the Company granted restricted stock unit awards for 1,902,889 shares at a grant date fair value of $123.8 million, which will be recognized as expense over vesting periods of approximately 3.5 to 4 years.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

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 three months ended March 31, 2014 is as follows:

	Stock options		Weighted average exercise price	Weighted average remaining contractual life		Intrinsic 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 March 31, 2014	70,339	$	54.15	9.54	$	594
Expected to vest as of March 31, 2014	70,339	$	54.15	9.54	$	594
Exercisable at March 31, 2014	—

We use a Black-Scholes option-pricing model to determine the 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 March 31, 2014, there was $1.2 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.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

(6) Financial Instruments

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

The fair value of the Company’s senior notes was approximately $1.9 billion, based on Level 2 market data inputs at December 31, 2013 and $1.8 billion at March 31, 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 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, 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 recognized upon the ultimate sale of the natural gas produced.

For the three months ended March 31, 2013 and 2014, the Company was party to natural gas 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. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

As of March 31, 2014, the Company has entered into fixed price natural gas and oil swaps in order to hedge a portion of its natural gas and oil production from April 1, 2014 through December 31, 2019 as summarized in the following table.

	Natural gas MMbtu/day	Oil Bbls/day		Weighted average index price
Nine Months ending December 31, 2014:
TCO	210,000	—	$	5.06
Dominion South	160,000	—	$	5.10
NYMEX	340,000	—	$	4.10
CGTLA	10,000	—	$	3.84
NYMEX-WTI	—	3,000	$	95.22
2014 Total	720,000	3,000

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

	Natural gas MMbtu/day	Oil Bbls/day		Weighted average index price
Year ending December 31, 2015:
TCO	130,000		$	4.93
Dominion South	230,000		$	5.60
NYMEX	250,000		$	4.14
CGTLA	40,000		$	4.00
2015 Total	650,000

Year ending December 31, 2016:
TCO	80,000		$	4.67
Dominion South	272,500		$	5.35
NYMEX	120,000		$	4.17
CGTLA	170,000		$	4.09
2016 Total	642,500

Year ending December 31, 2017:
TCO	20,000		$	4.02
NYMEX	270,000		$	4.39
CGTLA	420,000		$	4.27
CCG	70,000		$	4.57
2017 Total	780,000

Year ending December 31, 2018:
NYMEX	710,000		$	4.60

Year ending December 31, 2019:
NYMEX	467,500		$	4.41

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

(b) Summary

The following is a summary of the fair values of derivative instruments not designated as hedges for accounting purposes and where such values are recorded in the consolidated balance sheets as of December 31, 2013 and March 31, 2014. None of the Company’s derivative instruments are designated as hedges for accounting purposes.

	December 31, 2013			March 31, 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	$	130,679
Commodity contracts	Long-term assets		677,780	Long-term assets		500,882

Total asset derivatives			860,780			631,561

Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities		646	Current liabilities		17,623
Commodity contracts	Long-term liabilities		—	Long-term liabilities		1,662

Total liability derivatives			646			19,285

Net derivatives		$	860,134		$	612,276

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 condensed consolidated balance sheets for the periods presented, all at fair value (in thousands):

		December 31, 2013							March 31, 2014
		Gross amounts on balance sheet		Gross amounts offset on balance sheet		Net amounts 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		$	700,418		(68,857	)	631,561
Commodity derivative liabilities	$	(646	)	—		(646	)	$	(21,031	)	1,746		(19,285	)

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

The following is a summary of derivative fair losses and where such values are recorded in the consolidated statements of operations for the three months ended March 31, 2013 and 2014 (in thousands):

	Statement of operations location		2013		2014
Commodity derivative fair value losses	Revenue	$	(71,941	)	(248,929	)

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 matthers will not have a material adverse effect on its 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 March 31, 2013 and 2014 (in thousands):

		Exploration and production		Gathering and compression	Fresh water distribution	Elimination of intersegment transactions		Consolidated total
2013:
Sales and revenues:
Third-party	$	61,454		—	—	—		61,454
Intersegment		—		1,953	4,365	(6,318	)	—
	$	61,454		1,953	4,365	(6,318	)	61,454

Depletion, depreciation, and amortization	$	39,476		1,012	—	(124	)	40,364
Interest expense	$	29,909		19	—	—		29,928
Income tax benefit	$	30,400		—	—	—		30,400
Operating income (loss)(1)	$	(49,087	)	744	3,571	(3,697	)	(48,469	)
Segment assets	$	4,038,932		238,067	22,856	(206,976	)	4,092,879
Capital expenditures for segment assets	$	488,479		55,975	9,020	(3,821	)	549,653

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

		Exploration and production		Gathering and compression	Fresh water distribution	Elimination of intersegment transactions		Consolidated total
2014:
Sales and revenues:
Third-party	$	161,457		930	2,594	—		164,981
Intersegment		—		10,843	21,909	(32,752	)	—
	$	161,457		11,773	24,503	(32,752	)	164,981

Depletion, depreciation, and amortization	$	83,138		6,108	2,918	(958	)	91,206
Interest expense	$	31,084		172	86	—		31,342
Income tax benefit	$	40,662		—	—	—		40,662
Operating income (loss)(1)	$	(109,482	)	4,896	16,202	(15,695	)	(104,079	)
Segment assets	$	6,982,436		703,426	288,981	(840,386	)	7,134,457
Capital expenditures for segment assets	$	581,736		107,523	60,030	(17,583	)	731,706

(1) All general and administrative expenses are included in the exploration and production segment.

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ANTERO RESOURCES CORPORATION

Notes to Consolidated Financial Statements

December 31, 2013 and March 31, 2014

(10) Subsidiary Guarantors

The Company’s wholly owned subsidiaries each have fully and unconditionally guaranteed the Company’s outstanding senior notes. The following Condensed Consolidating Balance Sheets as of December 31, 2013 and March 31, 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 months ended March 31, 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 Consolidated Financial Statements

December 31, 2013 and March 31, 2014

March 31, 2014

		Parent	Guarantor Subsidiaries	Eliminations		Consolidated
Assets
Current assets:
Cash and cash equivalents	$	12,580	—	—		12,580
Other		309,342	1	(1	)	309,342
Total current assets		321,922	1	(1	)	321,922

Property and equipment, net		6,266,227	—	—		6,266,227
Other long-term assets		546,308	—	—		546,308
Investment in subsidiary		1	—	(1	)	—
	$	7,134,458	1	(2	)	7,134,457

Liabilities and Stockholders’ Equity

Current liabilities	$	760,806	—			760,806
Long-term debt		2,535,819	—	—		2,535,819
Other long-term liabilities		304,794	—	—		304,794
Due to subsidiary		1	—	(1	)	—
Total liabilities		3,601,420	—	(1	)	3,601,419

Stockholders’ equity		3,533,038	1	(1	)	3,533,038
Total liabilities and equity	$	7,134,458	1	(2	)	7,134,457

(11) Subsequent Events

On April 1, 2014, the Company granted restricted stock unit awards for 1,902,899 shares at a grant date fair value of $123.8 million, which will be recognized as expense over vesting periods of approximately 3.5 to 4 years.

On April 23, 2014, the Company delivered notice of its election to redeem the 2019 notes that remain outstanding on May 23, 2014 at a redemption price of 100% of the principal amount thereof plus a “make-whole” premium and accrued interest. The redemption will be financed using a portion of the proceeds from the offering of the 2022 notes described below.

On May 5, 2014 the Credit Facility was amended to increase the face amount of the facility from $2.5 billion to $3.5 billion, to increase the borrowing base from $2.0 billion to $3.0 billion, and to increase lender commitments from $1.5 billion to $2.0 billion. The maturity date of the facility was amended from May 2016 to May 2019.

On May 6, 2014, the Company issued $600 million of its 5.125% senior subordinated notes due 2022 at par. A portion of the net proceeds from the sale of the 2022 notes will be used to redeem all outstanding 2019 notes and the remainder will be used to partially repay amounts outstanding under the Credit Facility.

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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 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 exploration, development and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of March 31, 2014, we held approximately 462,000 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

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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 December 31, 2013, our estimated proved reserves were approximately 7.6 Tcfe, consisting of 6.8 Tcf of natural gas, 137 MMBbl of NGLs, and 10 MMBbl of oil. We have a 24-year drilling inventory and have approximately 4,800 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 in existence or 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 and (iii) fresh water distribution. All of our operations are conducted in the United States.

Address, Internet Website and Availability of Public Filings

As of May 5, 2014, our principal executive offices were relocated to 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.

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 March 31, 2014, we generated cash flow from operations of $274 million, a net loss of $95 million, and EBITDAX of $274 million. The net loss of $95 million for the three months ended March 31, 2014 included $249 million of commodity derivative losses, of which $1 million related to cash settled derivatives, and a deferred tax benefit of $41 million. This compares to cash flow from operations of $110 million, a net loss of $48 million, and EBITDAX of $119 million for the three months ended March 31, 2013. See “—Non-GAAP Financial Measure” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income.

For the three months ended March 31, 2014, our production totaled approximately 71 Bcfe, or 786 MMcfe per day, compared to 34 Bcfe, or 383 MMcfe per day for the three months ended March 31, 2013. The average price received for production for the three months ended March 31, 2014 was $5.80 per Mcfe before the effects of commodity hedges compared to $3.87 per Mcfe for the three months ended March 31, 2013. Average prices after the effects of commodity hedges were $5.79 per Mcfe for the three months ended March 31, 2014 compared to $5.26 for the three months ended March 31, 2013.

2014 Capital Budget

For the three months ended March 31, 2014, our total capital expenditures were approximately $732 million, including drilling and completion costs of $496 million, gathering and compression costs of $107 million, fresh water distribution project costs of $60 million, leasehold acquisition costs of $60 million, and other capital expenditures of $8 million. Our revised capital expenditure budget for 2014 is $2.85 billion and includes: $1.8 billion for drilling and completion; $750 million for the expansion of midstream facilities, including $200 million for fresh water distribution infrastructure; and $300 million for core leasehold acreage acquisitions. We do not budget for producing property acquisitions. Substantially all of the $1.8 billion allocated for drilling and completion is allocated to our operated drilling in rich gas areas. Approximately 75% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 25% is allocated to the Utica Shale. During 2014, we plan to operate an average of 14 drilling rigs in the Marcellus Shale, including three intermediate rigs that drill the vertical section of some horizontal wells to kick-off point, and four drilling rigs in the Utica Shale. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

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Credit Facility Amendments

On May 5, 2014, our revolving credit facility was amended to provide for maximum borrowings of $3.5 billion and a current borrowing base of $3.0 billion. Lender commitments were increased from $1.5 billion to $2.0 billion. Lender commitments can be increased to the full $3.0 billion upon the approval of the lenders. The maturity date of the facility was amended from May 2016 to May 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 and the estimated future cash flows from these reserves and the value of our hedge positions. The next redetermination is scheduled to occur in October 2014.

At March 31, 2014, we had $818 million of borrowings and letters of credit outstanding under the Credit Facility and $682 million of available borrowing capacity, based on $1.5 billion of lender commitments at that date.

Hedge Position

As of March 31, 2014, we had entered into hedging contracts for April 1, 2014 through December 31, 2019 for 1.385 Tcf of our projected natural gas production at a weighted average index price of $4.58 per MMbtu and 825,000 Bbls of oil at a weighted average price of $95.22 per Bbl. These hedging contracts include contracts for the year ended December 31, 2014 of approximately 198 Bcf of natural gas at a weighted average index price of $4.60 per Mcf and 825,000 Bbls of oil at $95.22 per Bbl.

Issuance of 5.125% Senior Subordinated Notes

On May 6, 2014, we issued $600 million of 5.125% senior notes due 2022 at par. Net proceeds from the offering were approximately $592 million, after deducting the initial purchasers discounts and estimated expenses. We intend to use approximately $277 million to finance the redemption of our outstanding 7.25% senior notes due 2019 and the remaining net proceeds to repay a portion of the outstanding borrowings under our revolving credit facility.

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. In connection with the closing of the offering, Antero Resources Midstream LLC will convert from a limited liability company into a Delaware master limited partnership. In connection with the closing of the MLP’s initial public offering, we intend to contribute substantially all of our midstream assets to the MLP as well as the right to develop additional midstream infrastructure to service our growing production. However, we cannot provide any assurance that we will be able to complete the proposed initial public offering of the MLP in a timely fashion, or at all.

Source of Our Revenues

Our revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing, and from gathering, compression, and fresh water distribution fees. Our revenues derive entirely from the continental United States. During the three months ended March 31, 2014, our revenues from production were comprised of approximately 76% from the sale of natural gas and 24% from the sale of NGLs and oil. Our revenues from production for the year ended December 31, 2013 were comprised of approximately 84% from natural gas and 16% from NGLs and oil. Natural gas, NGLs, and oil prices are inherently volatile and are influenced by many factors outside of our control. All of our production is derived from natural gas wells, some of which also produce NGLs, after processing, and oil. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas production and oil production. We currently use fixed price swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At the end of each period we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize the changes in the fair value of unsettled commodity derivative instruments in earnings at the end of each accounting period. We expect continued volatility in the fair value of these swaps.

Our Expenses

· Lease operating expenses. These are the day to day operating costs incurred to maintain production of our natural gas, NGLs, and oil. Such costs include produced water recycling, monitoring, pumping, maintenance, repairs, and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services.

· Gathering, compression, processing and transportation. These are costs incurred to bring natural gas, NGLs, and oil to the market. Such costs include the costs to operate and maintain our low and high pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transport our gas. They also include costs to process and extract NGLs from our produced gas and to transport our NGLs and oil to market.

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We often enter into fixed price long-term contracts that secure transportation and processing capacity that may include minimum volume commitments, the cost for which is included in these expenses.

· Production and ad valorem taxes. Production and ad valorem taxes consist of severance and ad valorem taxes and are paid on produced natural gas, NGLs, and oil based on a percentage of realized prices (not hedged prices) and at fixed rates per unit of production established by federal, state or local taxing authorities.

· Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes and costs related to unsuccessful leasing efforts.

· Impairment of unproved and proved properties. These costs include unproved property impairment and costs associated with lease expirations. We could record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows. Through March 31, 2014, we have not recorded any impairment for proved properties.

· Depreciation, depletion, and amortization. Depreciation, depletion, and amortization, or “DD&A”, includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs, and oil. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each unit of production using the units of production method.

· General and administrative expense. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance expenses. General and administrative expense for the three months ended March 31, 2014 also includes a noncash stock compensation charge of $29.2 million, including a charge of $28.7 million for the recognition and amortization of expense related to vested profits interests upon the completion of the Antero Resources Corporation IPO in 2013. See note 1 to the consolidated financial statements included elsewhere in this report for more information on the vested profits interests charge.

· Interest expense. We finance a portion of our working capital requirements and acquisitions with borrowings under the Credit Facility and the Midstream Facility, which have a variable rate of interest based on LIBOR or the prime rate. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. At March 31, 2014, we had a fixed interest rate of 5.375% on our 2021 notes having a principal balance of $1 billion, a fixed interest rate of 7.25% on our 2019 notes having a principal balance of $260 million, and a fixed interest rate of 6.00% on our 2020 notes having a principal balance of $525 million. We expect to continue to incur significant interest expense as we continue to grow.

· Income tax expense. We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs and the deferral of unrealized commodity hedge gains for tax purposes until they are realized. We do pay some state taxes where taxes are determined on a basis other than income. We have recorded deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets. Our deferred tax assets and liabilities result from temporary differences between tax and financial statement income primarily from derivatives, oil and gas properties, and net operating loss carryforwards. We have generated net operating loss carryforwards that expire at various dates from 2024 through 2033. We have recorded valuation allowances for deferred tax assets of approximately $27 million primarily for state loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

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Results of Operations

Three months ended March 31, 2013 Compared to Three months ended March 31, 2014

The following table sets forth selected operating data for the three months ended March 31, 2013 compared to the three months ended March 31, 2014:

	Three Months Ended March 31,						Amount of Increase
	2013			2014			(Decrease)			Percent Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	121,946		$	312,336		190,390			156	%
NGL sales	10,572			73,928			63,356			599	%
Oil sales	877			24,122			23,245			2,651	%
Gathering, compression, and water distribution	—			3,524			3,524			*
Commodity derivative fair value losses	(71,941		)	(248,929		)	(176,988		)	*
Total operating revenues	61,454			164,981			103,527			168	%
Operating expenses:
Lease operating	1,071			4,869			3,798			355	%
Gathering, compression, processing, and transportation	40,970			92,265			51,295			125	%
Production and ad valorem taxes	8,619			21,039			12,420			144	%
Exploration	4,362			6,997			2,635			60	%
Impairment of unproved properties	1,556			1,397			(159		)	(10	)%
Depletion, depreciation, and amortization	40,364			91,206			50,842			126	%
Accretion of asset retirement obligations	264			302			38			14	%
General and administrative (before stock compensation)	12,717			21,848			9,131			72	%
Stock compensation	—			29,137			29,137			*
Total operating expenses	109,923			269,060			159,137			145	%
Operating loss	(48,469		)	(104,079		)	(55,610		)	*

Interest expense	(29,928		)	(31,342		)	1,414			5	%
Loss before income taxes	(78,397		)	(135,421		)	(57,024		)	*
Income tax benefit	30,400			40,662			10,262			34	%
Net loss	(47,997		)	(94,759		)	(46,762		)	*

Adjusted EBITDAX (1)	$	118,749		$	273,656		154,907			130	%

Production data:
Natural gas (Bcf)	33			62			29			86	%
NGLs (MBbl)	205			1,198			993			484	%
Oil (MBbl)	10			271			261			2,563	%
Combined (Bcfe)	34			71			37			105	%
Daily combined production (MMcfe/d)	383			786			403			105	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.67		$	5.05		$	1.38		38	%
NGLs (per Bbl)	$	51.55		$	61.69		$	10.14		20	%
Oil (per Bbl)	$	86.12		$	88.87		$	2.75		3	%
Combined (per Mcfe)	$	3.87		$	5.80		$	1.93		50	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	5.13		$	5.02		$	(0.11	)	(2	)%
NGLs (per Bbl)	$	51.55		$	61.69		$	10.14		20	%
Oil (per Bbl)	$	75.41		$	90.78		$	15.37		20	%
Combined (per Mcfe)	$	5.26		$	5.79		$	0.53		10	%
Average Costs (per Mcfe):
Lease operating	$	0.03		$	0.07		$	0.04		133	%
Gathering, compression, processing, and transportation	$	1.19		$	1.30		$	0.11		9	%
Production and advalorem taxes	$	0.25		$	0.30		$	0.05		20	%
Depletion, depreciation, amortization, and accretion	$	1.18		$	1.29		$	0.11		9	%
General and administrative (3)	$	0.37		$	0.31		$	(0.06	)	(16	)%

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

(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.

(3) Does not include noncash stock compensation expense in 2014.

* Not meaningful or applicable

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $133 million for the three months ended March 31, 2013 to $410 million for the three months ended March 31, 2014, an increase of $277 million, or 208%. Our production increased by 105% over that same period, from 34 Bcfe for the three months ended March 31, 2013 to 71 Bcfe

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for the three months ended March 31, 2014. Net equivalent prices before the effects of realized hedge gains increased from $3.87 per Mcfe for the three months ended March 31, 2013 to $5.80 for the three months ended March 31, 2014, an increase of 50%. The 50% increase in net equivalent prices for the three months ended March 31, 2014 compared to the prior year quarter resulted from a 38% increase in natural gas prices; the remaining 12% 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 and oil. Increased production volumes accounted for an approximate $140 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 $137 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 additional producing wells as a result of our ongoing drilling program.

Commodity derivative fair value 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 results of operations. For the three months ended March 31, 2013 and 2014, our hedges resulted in derivative fair value losses of $72 million and $249 million, respectively. The derivative fair value losses included $48 million and $(1) million of cash settlements received (paid) on derivatives for the three months ended March 31, 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 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 fresh water distribution fees of $3.5 million during the three months ended March 31, 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.

Lease operating expenses. Lease operating expenses increased by 355% from the three months ended March 31, 2013 to the three months ended March 31, 2014 to $5 million. The increase occurred because of the increase in the number of producing wells. On a per unit basis, lease operating expenses increased by 133%, from $0.03 per Mcfe for the three months ended March 31, 2013 to $0.07 for the three months ended March 31, 2014. Lease operating expenses per unit have increased as an increased number 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 $41 million for the three months ended March 31, 2013 to $92 million in 2014. The increase in these expenses resulted from 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 $1.19 per Mcfe for 2013 to $1.30 in 2014 due to more gas being processed compared to the prior year period and payments for additional firm transportation commitments. 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.

Production and ad valorem tax expense. Total production and ad valorem taxes increased from $9 million for the three months ended March 31, 2013 to $21 million for the three months ended March 31, 2014, primarily as a result of increased production and midstream assets. Production and ad valorem taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging were 6.5% for the three months ended March 31, 2013 compared to 5.1% for the three months ended March 31, 2014. Production taxes decreased as a percentage of revenues as production increased in Ohio, which has a lower severance tax rate than West Virginia, and per unit based taxes also decreased as a percentage of revenues as prices increased. Ad valorem taxes increased because of the construction of the fresh water distribution and other midstream assets. 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 $4 million for the three months ended March 31, 2013 to $7 million for the three months ended March 31, 2014 primarily because of an increase in the cost of unsuccessful lease acquisition efforts due to an increase in lease acquisition efforts.

Impairment of unproved properties. Impairment of unproved properties was approximately $1.5 million for the three months ended March 31, 2013 compared to $1.4 million for the three months ended March 31, 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.

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DD&A. DD&A increased from $40 million for three months ended March 31, 2013 to $91 million for the three months ended March 31, 2014, primarily because of increased production. DD&A per Mcfe increased by 9% from $1.18 per Mcfe during the three months ended March 31, 2013 to $1.29 per Mcfe during the three months ended March 31, 2014, primarily as a result of increased depreciation on gathering systems and facilities and increased proved property costs subject to depletion.

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 March 31, 2013 or 2014 for proved properties.

General and administrative and stock compensation expense. General and administrative expense increased from $13 million for the three months ended March 31, 2013 to $22 million for the three months ended March 31, 2014, primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses, all of which resulted from our growth in development activities and production levels. On a per unit basis, general and administrative expense decreased by 16%, from $0.37 per Mcfe during the three months ended March 31, 2013 to $0.31 per Mcfe during the three months ended March 31, 2014, primarily due to a 105% increase in production. We had 163 employees as of March 31, 2013 and 277 employees as of March 31, 2014. General and administrative expense for the three months ended March 31, 2014 includes a noncash stock compensation charge of $29.2 million, including a charge of $28.7 million for the recognition and amortization of expense related to vested profits interests upon the completion of the 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 $30 million for the three months ended March 31, 2013 to $31 million for the three months ended March 31, 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 March 31, 2013 and 2014.

Income tax benefit. Income tax benefit changed from a deferred benefit of $30 million for the three months ended March 31, 2013 to a deferred benefit of $41 million for the three months ended March 31, 2014 because of the increase in the pre-tax loss compared to the prior year period. The deferred benefit in 2013 and 2014 results from the loss incurred for financial reporting purposes in both the three months ended March 31, 2013 and 2014 and results in decreased deferred tax liabilities. Stock compensation of $28.7 million for the three months ended March 31, 2014 relates to the stock compensation described in note 1(c) to the consolidated financial statements included elsewhere herein. This 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 three months ended March 31, 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 starting in 2024 and 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 such legislation might be enacted.

The calculation of the our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements include unrecognized benefits at March 31, 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 March 31, 2014, we have accrued approximately $0.7 million of interest on unrecognized tax benefits.

Capital Resources and Liquidity

Our primary sources of liquidity have been proceeds from issuances of equity securities and senior notes, borrowings under bank 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 proved reserves and production will be highly dependent on the capital resources available to us.

We believe that funds from operating cash flows and available borrowings under our 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.

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The following table summarizes our cash flows for the three months ended March 31, 2013 and 2014:

	Three Months Ended March 31,
	2013			2014
	(in thousands )
Net cash provided by operating activities	$	110,207		$	274,307
Net cash used in investing activities	(547,885		)	(735,513		)
Net cash provided by financing activities	423,495			456,299
Net decrease in cash and cash equivalents	$	(14,183	)	$	(4,907	)

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $110 million and $274 million for the three months ended March 31, 2013 and 2014, respectively. The increase in cash flow from operations from the three months ended March 31, 2013 compared to the three months ended March 31, 2014 was primarily the result of increased production volumes and revenues, net of the decrease in cash settlements from derivatives and the increase 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 is the volatility of prices for natural gas, NGLs, and oil production. 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 three months ended March 31, 2014, we used cash totaling $736 million in investing activities, including $60 million for undeveloped leasehold acquisitions, $496 million for drilling and completion costs, $60 million for fresh water distribution facilities, $108 million for gathering and compression systems, and $8 million for other property and equipment. During the three months ended March 31, 2013, we used cash totaling $548 million in investing activities, including $149 million for undeveloped leasehold acquisitions, $335 million for drilling and completion costs, $9 million for fresh water distribution systems, and $56 million of expenditures for gathering and compression systems.

Our board of directors has approved a revised capital budget of $2.85 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 to achieve the desired 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 three months ended March 31, 2014 of $456 million consisted primarily of additional borrowings on our Credit Facility. Net cash provided by financing activities for the three months ended March 31, 2013 resulted from the issuance of $225 million of our 6.00% Senior Notes at a premium of 3%, $187 million of net additional borrowings on our Credit Facility, net of payments of deferred financing costs on the issuance of the senior notes of $3.0 million, and other items of $8 million.

Senior Secured Revolving Credit Facility. On May 5, 2014, the Credit Facility was amended to provide for maximum borrowings of $3.5 billion and a current borrowing base of $3.0 billion. Lender commitments were increased from $1.5 billion to $2.0 billion. Lender commitments can be increased to the full $3.0 billion upon the approval of the lenders. The maturity date of the facility was amended from May 2016 to May 2019. The borrowing base is redetermined semi-annually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and the value of our hedge positions. The next redetermination is scheduled to occur in October 2014. At March 31, 2014, we had $745 million of borrowings and $73 million of letters of credit outstanding under the Credit 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 (includes unused borrowing base under the revolving credit facility and excludes 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, of not less than 2.5 to 1.0.

We were in compliance with such covenants and ratios as of December 31, 2013 and as of March 31, 2014.

Senior Notes. We 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 our wholly owned subsidiary 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. If we undergo a change of control prior to May 1, 2015, we may be required to repurchase all or a portion of the 2021 notes at a price equal to 110% of the principal amount of the 2021 notes, plus accrued interest.

We also have 7.25% senior notes outstanding, which are due August 1, 2019 with an original principal amount of $400 million. The 2019 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 2019 notes rank pari passu to our other outstanding senior notes. The 2019 notes are guaranteed on a senior unsecured basis by our wholly owned subsidiary and certain of our future restricted subsidiaries. Interest on the 2019 notes is payable on August 1 and February 1 of each year. We may redeem all or part of the 2019 notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017. If we undergo a change of control, we may be required to repurchase all or a portion of the 2019 notes at a price equal to 101% of the principal amount of the 2019 notes, plus accrued interest. In November 2013, we used a portion of the proceeds from our IPO to redeem $140 million aggregate principal amount of the 2019 notes.

We also 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 our wholly owned subsidiary and certain of its 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.

We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under the Credit Facility 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 March 31, 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

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lender’s prime rate plus 1.0%. The note matures on June 1, 2014. At March 31, 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 (loss) before interest expense, interest income, derivative fair value gains or losses, excluding net cash receipts or payments on derivative instruments, taxes, impairments, depletion, depreciation, amortization, exploration expense, franchise taxes, stock compensation, business acquisition expenses 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 loss from 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:

	Three Months Ended March 31,
	2013			2014
(in thousands)
Net loss from operations	$	(47,997	)	(94,759	)
Commodity derivative fair value losses(1)	71,941			248,929
Net cash receipts (payments) on settled derivative instruments(1)	48,131			(1,071	)
Interest expense	29,928			31,342
Income tax benefit	(30,400		)	(40,662	)
Depreciation, depletion, amortization, and accretion	40,628			91,508
Impairment of unproved properties	1,556			1,397
Exploration expense	4,362			6,997
Stock compensation expense	—			29,137
State franchise taxes	600			838
Adjusted EBITDAX	118,749			273,656
Interest expense	(29,928		)	(31,342	)
Exploration expense	(4,362		)	(6,997	)
Changes in current assets and current liabilities	24,961			36,646
State franchise taxes	(600		)	(838	)
Other noncash items	1,387			3,182
Net cash provided by operating activities	$	110,207		274,307

(1) The adjustments for the derivative fair value losses and net cash received on settled commodity derivative instruments have the effect of adjusting the net loss from operations for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period. This results in reflecting commodity derivative gains and losses on a cash basis in the calculation of Adjusted EBITDAX during the period the derivatives settled.

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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 accounting principles generally accepted in the United States. 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.

New Accounting Pronouncements

There were no new accounting pronouncements issued during the three months ended March 31, 2014 that had or are expected to have a material effect on the Company’s 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 March 31, 2014 is provided in the following table.

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

Credit Facility(1)	$	—	$	—	$	—	$	745	$	—	$	—	$	745
Senior notes—principal(2)	—		—		—		—		—		1,785		1,785
Senior notes—interest(2)	104		104		104		104		104		207		727
Drilling rig and frac service commitments(3)	176		95		55		2		—		—		328
Firm transportation (4)	186		258		258		256		255		1,975		3,188
Gas processing, gathering, and compression service (5)	197		198		207		206		190		910		1,908
Office and equipment leases	6		6		6		6		3		15		42
Asset retirement obligations(6)	—		—		—		—		—		12		12
Total	$	669	$	661	$	630	$	1,319	$	552	$	4,904	$	8,735

(1)	Includes outstanding principal amount at March 31, 2014. This table does not include future commitment fees, interest expense or other fees on the Credit 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 7.25% senior notes due 2019, the 6.00% notes due 2020, and the 5.375% notes due 2021.

(3)	At March 31, 2014, we had contracts for the services of 15 rigs which expire at various dates from 2014 through 2016. We also had two frac services contracts which expire in 2014 and 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.

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(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 a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. 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 service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. 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.

(6)	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.

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, NGL, 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 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 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 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 and cashless price collars that set a floor and ceiling price for the hedged production. 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.

At March 31, 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 March 31, 2014 is summarized in note 7 to our consolidated financial statements included elsewhere herein. Our financial hedging activities are intended to support natural gas, NGLs, and oil prices at targeted levels and to manage our exposure to natural gas price fluctuations. Our Credit Facility allows us to hedge 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 2018 and 2019. Based on our quarterly production and our fixed price swap contracts in place during the quarter, the net effect on our revenues of a $0.10 decrease per MMBtu in natural gas prices and a $1.00 per Bbl decrease in oil prices would have been negligible.

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All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value in accordance with United States GAAP and are included in the consolidated balance sheets as assets or liabilities. Fair values are adjusted for non-performance risk. Because we do not designate these hedges as accounting hedges, we do not receive accounting hedge treatment and all mark-to-market gains or losses as well as realized gains or losses on the derivative instruments are recognized in our results of operations. We present realized and unrealized gains or losses on commodity derivatives in our operating revenues as “Realized and unrealized gains (losses) on commodity derivative instruments.”

Mark-to-market adjustments of derivative instruments produce 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 when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. At March 31, 2014, the estimated fair value of our commodity derivative instruments was a net asset of $612 million comprised of current and noncurrent assets and current liabilities. At 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.

By removing price volatility from a portion of our expected natural gas production through December 2019, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($612 million at March 31, 2014) and the sale of our oil and gas production ($145 million at March 31, 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 $612 million at March 31, 2014 includes the following asset (liability) values by bank counterparty: BNP Paribas - $171 million; Credit Suisse - $131 million; Wells Fargo - $105 million; JP Morgan - $102 million; Barclays - $93 million; Deutsche Bank - $13 million; and Citigroup, Toronto Dominion Bank, Bank of Montreal, and Fifth Third Bank totaling $(3) 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 March 31, 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 contracts, nor are they required to provide credit support to us. As of March 31, 2014, we have no past due receivables from or payables to any of our counterparties.

We are also subject to credit risk due to concentration of our receivables from several significant customers for sales of natural gas, NGLs, and oil. We 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 three months ended March 31, 2014, was approximately 1.94%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2014 would have resulted in an estimated $1.2 million increase in interest expense for the three months ended March 31, 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)

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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 financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2014 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There has been no change 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 March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 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 Santander Asset

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Management Investment Holdings Limited (“SAMIH”). SAMIH may therefore be deemed to be under common “control” with us; however, this statement is not meant to be an admission that common control exists.

The disclosure below relates solely to activities conducted by SAMIH and its 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 SAMIH, and neither we nor WP has independently verified or participated in the preparation of the disclosure. Neither we nor WP is representing to the accuracy or completeness of the disclosure nor do we or WP undertake any obligation to correct or update it.

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 NPWMD designation, holds two investment accounts with Santander Asset Management UK Limited. The accounts have remained frozen throughout 2013 and the first quarter of 2014. The investment returns are being automatically reinvested, and no disbursements have been made to the customer. Total revenue for the Santander Group in connection with the investment accounts was £23,017 and net profits in the first quarter 2014 were negligible relative to the overall profits of Banco Santander, S.A.

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: May 7, 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

Exhibit Number		Description of Exhibits
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	*	Fifth Supplemental Indenture related to the 7.25% Senior Notes due 2019, dated as of March 18, 2014, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.

4.2	*	Fourth Supplemental Indenture related to the 6.0% Senior Notes due 2020, dated March 18, 2014, by and among Antero Resources Finance Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.

4.3	*	Second Supplemental Indenture related to the 5.375% Senior Notes due 2021, dated as of December 31, 2013, by and among Antero Resources Finance Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.

10.1	*	Tenth Amendment to Fourth Amended and Restated Credit Agreement, dated as of February 28, 2014, 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.

10.2	*	Credit Agreement, dated as of February 28, 2014, among Antero Midstream LLC (formerly known as Antero Resources Midstream Operating LLC), as Borrower, certain subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, Union Bank, N.A. and Credit Agricole Corporate and Investment Bank, as Co-Documentation Agents, and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners.

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 March 31, 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.