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 June 30, 2011

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 333-164876

ANTERO RESOURCES FINANCE CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		90-0522247
(State or other jurisdiction of		(IRS Employer Identification No.)
incorporation or organization)

1625 17th 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). o 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 (Do not check if a smaller reporting company)		Smaller reporting company o

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

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TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING STATEMENTS		(ii)
PART I. FINANCIAL INFORMATION		1
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results Of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	29
PART II OTHER INFORMATION		30
Item 1.	Legal Proceedings	30
Item 1A.	Risk Factors	30
Item 6.	Exhibits	31
SIGNATURES		33

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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, 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. 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;

· 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 gathering and other 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, regulatory changes, the uncertainty inherent in estimating natural gas 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, 2010 on file with the Securities and Exchange Commission (Commission File No. 333-164876) and in Part II, Item 1A-”Risk Factors” of this Quarterly Report on Form 10-Q.

Reserve engineering is a process of estimating underground accumulations of natural gas 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

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and cost assumptions made by reserve 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 and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in our Annual Report on Form 10-K for the year ended December 31, 2010 or 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, express or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

iii

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ANTERO RESOURCES LLC

Consolidated Balance Sheets

December 31, 2010 and June 30, 2011

(Unaudited)

(In thousands)

	2010			2011
Assets
Current assets:
Cash and cash equivalents	$	8,988		3,943
Accounts receivable — trade, net of allowance for doubtful accounts of $272 and $181 in 2010 and 2011, respectively	30,971			30,260
Accrued revenue	24,868			36,762
Prepaid expenses	7,087			8,644
Derivative instruments	82,960			91,295
Inventories	2,031			3,219
Total current assets	156,905			174,123
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties	737,358			757,832
Producing properties	1,762,206			2,006,506
Gathering systems and facilities	85,404			119,357
Other property and equipment	5,975			6,775
	2,590,943			2,890,470
Less accumulated depletion, depreciation, and amortization	(431,181		)	(503,829	)
Property and equipment, net	2,159,762			2,386,641
Derivative instruments	147,417			159,632
Other assets, net	22,203			23,221
Total assets	$	2,486,287		2,743,617

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ANTERO RESOURCES LLC

Consolidated Balance Sheets

December 31, 2010 and June 30, 2011

(Unaudited)

(In thousands)

	2010		2011
Liabilities and Equity
Current liabilities:
Accounts payable	$	82,436	85,838
Accrued expenses	21,746		26,126
Revenue distributions payable	29,917		41,359
Advances from joint interest owners	1,478		3,965
Derivative instruments	4,212		—
Deferred income tax liability	12,694		15,498
Total current liabilities	152,483		172,786
Long-term liabilities:
Bank credit facility	100,000		325,000
Senior notes	527,632		527,481
Long-term note	25,000		25,000
Asset retirement obligations	5,374		5,842
Deferred income tax liability	77,489		100,048
Other long-term liabilities	3,322		5,643
Total liabilities	891,300		1,161,800
Equity:
Members’ equity	1,489,806		1,460,948
Accumulated earnings	105,181		120,869
Total equity	1,594,987		1,581,817
Total liabilities and equity	$	2,486,287	2,743,617

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Operations

Three Months Ended June 30, 2010 and 2011

(Unaudited)

(In thousands)

	2010			2011
Revenue:
Natural gas sales	$	40,268		86,695
Natural gas liquids sales	2,619			7,976
Oil sales	2,303			2,888
Realized and unrealized gain on commodity derivative instruments (including unrealized gains of $10,148 and $97,814 in 2010 and 2011, respectively)	26,324			117,135
Gas gathering and processing revenue	6,076			—
Total revenue	77,590			214,694
Operating expenses:
Lease operating expenses	6,277			7,683
Gathering, compression and transportation	10,757			19,807
Production taxes	1,932			4,109
Exploration expenses	2,047			2,304
Impairment of unproved properties	18,285			782
Depletion, depreciation and amortization	32,265			38,979
Accretion of asset retirement obligations	75			109
General and administrative	4,757			8,207
Loss on sale of assets	—			8,700
Total operating expenses	76,395			90,680
Operating income	1,195			124,014
Other expense:
Interest expense	(13,965		)	(15,606	)
Realized and unrealized gains on interest derivative instruments, net (including unrealized gains of $1,949 and $2,165 in 2010 and 2011, respectively	(223		)	—
Total other expense	(14,188		)	(15,606	)
Income (loss) before income taxes	(12,993		)	108,408
Income tax expense	(2,862		)	(33,785	)
Net income (loss)	(15,855		)	74,623
Noncontrolling interest in net income of consolidated subsidiary	(552		)	—
Net income (loss) attributable to Antero equity owners	$	(16,407	)	74,623

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Operations

Six Months Ended June 30, 2010 and 2011

(Unaudited)

(In thousands)

	2010			2011
Revenue:
Natural gas sales	$	92,508		147,553
Natural gas liquids sales	4,331			13,561
Oil sales	4,417			5,416
Realized and unrealized gain on commodity derivative instruments (including unrealized gains of $108,960 and $20,549 in 2010 and 2011, respectively)	137,407			69,107
Gas gathering and processing revenue	12,489			—
Total revenue	251,152			235,637
Operating expenses:
Lease operating expenses	10,875			14,984
Gathering, compression and transportation	20,898			36,957
Production taxes	4,602			7,237
Exploration expenses	3,399			5,433
Impairment of unproved properties	20,547			3,100
Depletion, depreciation and amortization	65,261			72,648
Accretion of asset retirement obligations	148			205
General and administrative	9,168			14,568
Loss on sale of compressor station	—			8,700
Total operating expenses	134,898			163,832
Operating income	116,254			71,805
Other income expense:
Interest expense	(27,257		)	(30,660	)
Realized and unrealized gains on interest derivative instruments, net (including unrealized gains of $3,474 and $4,212 in 2010 and 2011, respectively)	(1,825		)	(94	)
Total other expense	(29,082		)	(30,754	)
Income before income taxes	87,172			41,051
Income tax expense	(14,180		)	(25,363	)
Net income	72,992			15,688
Noncontrolling interest in net income of consolidated subsidiary	(1,793		)	—
Net income attributable to Antero equity owners	$	71,199		15,688

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Cash Flows

Six Months Ended June 30, 2010 and 2011

(Unaudited)

(In thousands)

	2010			2011
Cash flows from operating activities:
Net income	$	72,992		15,688
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization	65,261			72,648
Dry hole costs	360			3,044
Impairment of unproved properties	20,547			3,100
Accretion of asset retirement obligations	148			205
Accretion of bond discount (premium), net	(207		)	(151	)
Amortization and write-off of deferred financing costs	2,048			1,617
Unrealized gains on derivative instruments, net	(112,434		)	(24,762	)
Deferred taxes	14,180			25,363
Loss on sale of assets	—			8,700
Changes in current assets and liabilities:
Accounts receivable	6,228			712
Accrued revenue	(4,724		)	(11,894	)
Other current assets	(10,792		)	(2,745	)
Accounts payable	3,804			(252	)
Other liabilities	(2,498		)	6,701
Revenue distributions payable	5,485			11,442
Advances from joint interest owners	506			2,487
Net cash provided by operating activities	60,904			111,903
Cash flows from investing activities:
Additions to unproved properties	(15,723		)	(45,960	)
Drilling costs	(139,136		)	(229,122	)
Additions to gathering systems and facilities	(6,536		)	(49,953	)
Additions to other property and equipment	(413		)	(799	)
Proceeds from asset sales	—			15,379
Increase in other assets	(576		)	(2,635	)
Net cash used in investing activities	(162,384		)	(313,090	)
Cash flows from financing activities:
Issuance of senior notes	156,000			—
Borrowings on bank credit facility	85,994			255,000
Payments on bank credit facility	(142,080		)	(30,000	)
Payments of deferred financing costs	(3,788		)
Distribution to members	—			(28,858	)
Other	(1,258		)	—
Net cash provided by financing activities	94,868			196,142
Net decrease in cash and cash equivalents	(6,612		)	(5,045	)
Cash and cash equivalents, beginning of period	10,669			8,988
Cash and cash equivalents, end of period	$	4,057		3,943
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(31,918	)	(29,150	)
Supplemental disclosure of noncash investing activities:
Changes in accounts payable for additions to properties, gathering systems and facilities	$	28,560		3,654

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

December 31, 2010 and June 30, 2011

(1) Organization

Antero Resources LLC, a limited liability company, and its consolidated subsidiaries (collectively referred to as the “Company,” “we”, or “our”) are engaged in the exploration for and the production of natural gas, natural gas liquids (“NGLs”), and oil onshore in the United States in unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations. Our properties are primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma, and the Piceance Basin in Colorado. We also have certain midstream gathering and pipeline operations, which are ancillary to our interests in producing properties in these basins. Our corporate headquarters are in Denver, Colorado.

Our consolidated financial statements as of December 31, 2010 and June 30, 2011 include the accounts of Antero Resources LLC and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Corporation (“Antero Arkoma”), Antero Resources Piceance Corporation (“Antero Piceance”), Antero Resources Pipeline Corporation (“Antero Pipeline”), Antero Resources Appalachian Corporation and its subsidiary, Antero Resources Bluestone LLC (collectively, “Antero Appalachian”), and Antero Resources Finance Corporation (“Antero Finance”) (collectively, the “Antero Entities”).

(2) Basis of Presentation and Significant Accounting Policies

(a) Basis of Presentation

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”) applicable to interim financial information and should be read in the context of the December 31, 2010 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2010 consolidated financial statements have been filed with the SEC in Antero Resources Finance Corporation’s Annual Report on Form 10-K for the year ended December 31, 2010.

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 normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2011, the results of its operations for the three and six months ended June 30, 2010 and 2011, and its cash flows for the six months ended June 30, 2010 and 2011. All significant intercompany accounts and transactions have been eliminated. Operating results for the period ended June 30, 2011 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 Securities and Exchange Commission, the company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified except as described in note 10.

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(b) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results could differ from those estimates.

The Company’s financial statements are based on a number of significant judgments, assumptions, and estimates, including estimates of gas and oil reserve quantities, which are the basis for the calculation of depreciation, depletion, and amortization, present value of future reserves, and impairment of oil and gas properties. Reserve estimates are by their nature inherently imprecise.

(c) Risks and Uncertainties

Historically, the market for natural gas 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 a given 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 investments.

(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 expected to be produced. From time to time, the Company also enters into derivative contracts to mitigate the effects of interest rate fluctuations. 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 each counterparty 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, and changes in the fair value of interest rate derivatives are classified as other income (expense).

(f) Fair Value Measurements

Authoritative accounting guidance defines fair value, establishes a framework for measuring fair value, and requires 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

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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 that are valued using Level 2 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. The Company utilizes its counterparties to assess the reasonableness of its prices and valuation techniques. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.

(g) Income Taxes

Antero Resources LLC and each of its subsidiaries file separate federal and state income tax returns. Antero Resources LLC is a partnership for income tax purposes and therefore is not subject to federal or state income taxes. The tax on the income of Antero Resources LLC is borne by the individual members through the allocation of taxable income.

The Company and its subsidiaries have combined net operating loss carryforwards (“NOLs”) as of December 31, 2010 of approximately $509 million. The Company’s deferred tax assets relate primarily to NOLs and its deferred tax liabilities relate primarily to oil and gas properties and unrealized gains on derivative instruments. In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to the lack of historical profitable operations and based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of all of these deductible differences and has recorded valuation allowances in those subsidiaries having net deferred tax assets to the extent deferred tax assets exceed their deferred tax liabilities. The amount of deferred tax assets considered realizable could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. The Company’s income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 34% to consolidated income for the six month periods ended June 30, 2010 and 2011 primarily because of changes in the valuation allowance resulting from deferred tax liabilities arising in the period.

(h) Impairment of Unproved Properties

Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis.

Impairment of unproved properties during the six months ended June 30, 2011 and 2010 was $3.1 million and $20.6 million, respectively.

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(i) Industry Segment and Geographic Information

We have evaluated how the Company is organized and managed and have identified one operating segment—the exploration and production of oil, natural gas, and natural gas liquids. We consider our gathering, processing, and marketing functions as ancillary to our oil and gas producing activities. All of our assets are located in the United States and all of our revenues are attributable to United States customers.

(3) Credit Facilities

(a) Bank 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 is $1.5 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved properties and hedge positions and are subject to regular semiannual redeterminations. As of June 30, 2011, the borrowing base was $900 million. In connection with the issuance of $400 million of senior notes subsequent to June 30, 2011 (see note 10), the borrowing base was reduced to $800 million. Current lender commitments total $750 million and can be increased to the full $800 million borrowing base upon approval of the lending bank group. The maturity date of the Credit Facility is May 12, 2016. The next redetermination is scheduled to occur in October 2011.

The Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all of the financial debt covenants under the Credit Facility as of December 31, 2010 and June 30, 2011.

As of June 30, 2011, the Company had an outstanding balance under the Credit Facility of $325 million, with a weighted average interest rate of 2.26%, and outstanding letters of credit of approximately $19 million. As of December 31, 2010, the Company had an outstanding balance under the Credit Facility of $100 million, with a weighted average interest rate of 2.56%, and outstanding letters of credit of approximately $18 million.

(b) Senior Notes

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, Antero Finance issued an additional $150 million of the same series of 9.375% senior notes at a premium of $6 million. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a full and unconditional basis and joint and severally by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%. At any time prior to December 1, 2013, Antero Finance may also 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. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders. Antero Resources LLC, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

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(c) Treasury Management Facility

The Company has a stand-alone revolving note with a lender under the senior credit facility which provides for up to $7.5 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 Credit Facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. There were no borrowings outstanding under this facility at December 31, 2010 or June 30, 2011.

(d) Note Payable

The Company assumed a $25 million unsecured note payable in the business acquisition consummated on December 1, 2010. The note bears interest at 9% and is due December 1, 2013.

(4) Ownership Structure

At December 31, 2010 and June 30, 2011, the outstanding units in Antero Resources LLC are summarized as follows:

		Units
		authorized
		and issued
Class I units		107,281,058
Class A and B units		40,007,463
Class A and B profits units		19,726,873
		167,015,394

At June 30, 2011, 164,927 units are outstanding and not vested under the terms of the preferred and common stock awards in the Antero Entities for which they were exchanged.

None of the three classes of outstanding units are entitled to current cash distributions or are convertible into indebtedness. The Company has no obligation to repurchase these units at the election of the unitholders.

In the event of a distribution from Antero Resources LLC, amounts available for distribution are distributed according to a formula set forth in the Company’s limited liability company agreement that takes into account the relative priority of the various classes of units outstanding. In the event of a distribution due to the disposition of an individual Antero Entity, a portion of the proceeds is allocated to the employees of the Company based on a requisite return financial threshold. In general, distributions are made first to holders of the Class I units until they have received their investment amount and an 8% special allocation and then, as a group, to the holders of all classes of units together. The Class I units participate on a pro rata basis with the other classes of units in funds available for distributions in excess of the Class I unit investment and special allocation amounts.

At December 31, 2010 and June 30, 2011, the Class I units have an aggregate liquidation priority, including the special allocation of 8% per annum, of $1.86 billion and $1.92 billion, respectively.

During the six months ended June 30, 2011, the Company distributed $28.9 million to its members to cover their tax liabilities resulting from the sale of the Company’s Oklahoma midstream assets during the fourth quarter of 2010.

(5) Financial Instruments

The carrying values of trade receivables, trade payables, and the Credit Facility at December 31, 2010 and June 30, 2011 approximated market value. The carrying value of the Credit Facility at December 31, 2010 and June 30, 2011 approximated fair value because the variable interest rates are reflective of current market conditions.

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Based on Level 2 market data, the fair value of the Company’s senior notes was approximately $549 million and $563 million at December 31, 2010 and June 30, 2011, respectively.

(6) Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2011 (in thousands):

Asset retirement obligations — beginning of period	$	5,374
Obligations incurred	263
Accretion expense	205
Asset retirement obligations — end of period	$	5,842

(7) Derivative Instruments and Risk Management Activities

(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 six months ended June 30, 2010 and 2011, 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 June 30, 2011, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, Dominion Field Services, Barclays, Credit Suisse, Union Bank, and KeyBank accounted for approximately 42%, 23%, 11%, 8%, 8%, 6%, 1%, and 1%, respectively, of the net fair value of our commodity derivative assets position. The Company has no collateral from any counterparties. All but one of our commodity and interest rate derivative positions are with institutions that have a position in our Credit Facility and are secured by the collateral pledged on the Credit Facility and cross default provisions between the Credit Facility and the derivative instruments. At June 30, 2011, there are no past due receivables from or payables to any of our counterparties.

As of June 30, 2011, the Company has entered into fixed price natural gas swaps in order to hedge a portion of its natural gas production from July 1, 2011 through December 31, 2016 as summarized in the following table. Hedge agreements referenced to the Centerpoint and Transco Zone 4 indices are for production in the Arkoma Basin. Hedge agreements referenced to the CIG and NYMEX-WTI indices are for production in the Piceance Basin. Hedge agreements referenced to the CGTAP and Dominion indices are for production from the Appalachian Basin.

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			Weighted
			average
	Natural gas	Oil	index
	MMbtu/day	Bbls/day	price
Six months ending December 31, 2011:
CIG	45,000		$	5.51
Transco zone 4	55,000		6.11
CGTAP	95,526		5.51
Dominion	4,260		8.16
NYMEX-WTI		300	88.75

Year ending December 31, 2012:
CIG	55,000		$	5.51
Transco zone 4	45,000		6.60
CGTAP	115,556		5.64
Dominion	53,318		5.34
NYMEX-WTI		300	90.20

Year ending December 31, 2013:
CIG	60,000		$	5.54
Transco zone 4	40,000		6.51
CGTAP	72,631		5.94
Dominion	81,702		5.36
NYMEX-WTI		300	90.30

Year ending December 31, 2014:
CIG	50,000		$	5.84
Transco zone 4	20,000		6.51
CGTAP	120,000		5.96
Dominion	100,000		5.51
Centerpoint	10,000		6.20

Year ending December 31, 2015:
CIG	60,000		$	5.29
Transco zone 4	20,000		5.58
CGTAP	60,000		5.89
Dominion	190,000		5.81

Year ending December 31, 2016:
CGTAP	10,000		$	5.95

(b) Interest Rate Derivatives

The Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations under the Credit Facility. Under the swaps, the Company made payments to the swap counterparty when the variable LIBOR three-month rate fell below the fixed rate or receives payments from the swap counterparty when the variable LIBOR three-month rate increased above the fixed rate. The Company has no outstanding swap agreements at June 30, 2011.

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(c) Summary

The following is a summary of the fair values of our derivative instruments, which are not designated as hedges for accounting purposes and where such values are recorded in the consolidated balance sheets as of December 31, 2010 and June 30, 2011.

		December 31,
	Balance sheet	2010		June 30, 2011
	location	Fair value		Fair value
		(In thousands)		(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	82,960	$	91,295
Commodity contracts	Long-term assets	147,417		159,632
Total asset derivatives		$	230,377	$	250,927

Liability derivatives not designated as hedges for accounting purposes:
Interest rate contracts	Current liabilities	$	4,212	$	—

The following is a summary of realized and unrealized gains (losses) on derivative instruments and where such values are recorded in the consolidated statements of operations for the three months and six months ended June 30, 2010 and 2011:

	Statement of operations location	Three Months Ended June 30, 2009			Six Months Ended June 30, 2010		Three Months Ended June 30, 2011		Six Months Ended June 30, 2011
Realized gains on commodity contracts	Revenue	$	16,176		28,447		19,320		48,558
Unrealized gains on commodity contracts	Revenue	10,148			108,960		97,815		20,549
Total gains on commodity contracts		26,324			137,407		117,135		69,107
Realized losses on interest rate contracts	Other income (expense)	(2,172		)	(5,299	)	(2,165	)	(4,306	)
Unrealized gains on interest rate contracts	Other income (expense)	1,949			3,474		2,165		4,212
Total losses on rate contracts		(223		)	(1,825	)	—		(94	)
Net gains on derivative contracts		$	26,101		135,582		117,135		69,013

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The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at June 30, 2011:

	Fair value measurements using
	Quoted
	prices
	in active		Significant
	markets for		other	Significant
	identical		observable	unobservable
	assets		inputs	inputs
Description	(Level 1)		(Level 2)	(Level 3)	Total

Derivatives asset:
Fixed price commodity swaps	$	—	250,927	—	250,927

(8) Loss on Sale of West Virginia Compressor Station

On April 29, 2011, the Company sold a compressor station that it had constructed in West Virginia to a third-party provider of field compression services for $7.3 million. An $8.7 million loss was recognized on the sale. On the same date, the Company amended an existing service agreement with this third-party to provide compression services at this location for a term of 84 months.

(9) Contingencies

In March 2011, the Company received orders for compliance from the U.S. Environmental Protection Agency relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations 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.

(10) Subsequent Event

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the

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value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on August 1 and February 1 of each year, commencing on February 1, 2012. Antero Finance 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. In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the notes, plus accrued interest. At any time prior to August 1, 2014, Antero Finance 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 a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2013, Antero Finance may, at its option, redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the notes, plus accrued interest. If Antero Finance has not exercised its optional redemption rights upon a change of control, the note holders will have the right to require Antero Finance 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.

The Company used the proceeds from the offering of the notes to repay borrowings outstanding under its Credit Facility, for development of oil and gas properties, and for general corporate purposes. In accordance with the terms of the senior credit facility, the borrowing base under the Credit Facility was reduced $0.25 for every $1 of additional indebtedness, to $800 million.

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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. In addition, such analysis should be read in conjunction with the historical audited financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2010. 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 which could cause actual results to vary from our expectations include changes in commodity prices, the timing of planned capital expenditures, 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” included in our Annual Report on Form 10-K for the year ended December 31, 2010 and Part II, Item 1A.”Risk Factors” of this report. We do not undertake any obligation to publicly update any forward-looking statements.

Antero Resources Finance Corporation (“Antero Finance”), which was formed to be the issuer of the $525 million principal amount of senior notes due 2017 and the $400 million principal amount of senior notes due 2019, is an indirect wholly owned subsidiary of Antero Resources LLC. In this section, references to “Antero,” “we,” “the Company,” “us,” “our” and “operating entities” refer to the corporations that conduct Antero Resources LLC’s operations (Antero Resources Corporation, Antero Resources Midstream Corporation (through November 5, 2010), Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation, and, beginning December 1, 2010, Antero Resources Bluestone LLC, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see “Items 1 and 2. Business and Properties—Business—Corporate Sponsorship and Structure” included in our Annual Report on Form 10-K for the year ended December 31, 2010 or note 1 to the consolidated financial statements included elsewhere in this report.

Overview

Our Company

Antero Resources is an independent oil and natural gas company engaged in the exploration, development and production of natural gas, natural gas liquids, and oil located onshore in the United States. We focus on unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations. We hold a combination of rich gas and lean gas properties, which are primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado. Our corporate headquarters are in Denver, Colorado.

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year project inventory. We also plan to supplement our existing project inventory with additional leasehold acquisitions in our core operating areas that meet our strategic and financial objectives.

As of June 30, 2011, our estimated proved reserves were 3.6 Tcfe of natural gas, consisting of 2.8 Tcf of natural gas, 111 MMBbl of natural gas liquids, and 20 MMBbl of oil. As of June 30, 2011, 78% of our estimated proved reserves were natural gas, 19% were proved developed and 89% were operated by us. From December 31, 2007 through June 30, 2011, we increased our estimated proved reserves at a compounded annual growth rate of 113%, while our production increased over the same period at a compounded annual growth rate of 68%, to an average rate of 197 MMcfe/d for the first six months of 2011. For the year ended December 31, 2010, we generated cash flow from operations of $125.8 million, net income of $230.2 million and EBITDAX of $197.7 million. For the six months ended June 30, 2011, we generated cash flow from operations of $111.9 million, net income of $15.7 million, and EBITDAX of $141.9 million. See “Non-GAAP Financial Measure” included elsewhere in this report for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income.

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We have assembled a diversified 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 of the Appalachian Basin, the Woodford Shale of the Arkoma Basin (the Arkoma Woodford), the Fayetteville Shale of the Arkoma Basin, and the Mesaverde tight sands and the Mancos and Niobrara Shales of the Piceance Basin. From inception, we have drilled and operated 417 wells through June 30, 2011 with a success rate of approximately 98%. Our drilling inventory consists of approximately 7,000 potential well locations, both proven and unproven, all of which are unconventional resource opportunities. For information on the possible limitations on our ability to drill our potential locations, see “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 existing production. We own gathering lines in the Appalachian Basin and the Piceance Basin.

On November 5, 2010, we sold our Oklahoma midstream assets and received approximately $259 million of net cash proceeds from the sale and realized a gain of approximately $148 million. We used the proceeds to repay amounts outstanding under our senior secured revolving bank credit facility (the “Credit Facility”) and thereby increase availability on our Credit Facility for working capital, drilling activities and property acquisitions. We entered into long-term contracts with the purchaser of the midstream assets to continue to gather and process our Oklahoma gas production. The terms of the Antero Resources LLC limited liability company operating agreement require us to make distributions sufficient to cover the members’ tax liabilities for taxable gains that are allocated to the members. As a result of the gain on the sale of the midstream assets, we distributed $29 million to the members subsequent to December 31, 2010.

During the year ended December 31, 2010, we incurred approximately $332 million of capital expenditures for exploration and development of natural gas and oil properties. Capital expenditures for exploration and development were allocated 48% to our Marcellus shale project in the Appalachian basin, 33% to the Arkoma basin, and 19% to the Piceance Basin. Total capital expenditures during the year ended December 31, 2010, including exploration and development, leasehold acquisition, and gathering systems, were $423 million. Our revised capital expenditure budget for 2011, as approved by our Board of Directors, is $685 million, which includes $519 million for drilling and completion, $80 million for leasehold acquisitions, and $86 million for construction of gathering pipelines and facilities. Approximately 71% of the budget is allocated to the Marcellus Shale, 17% is allocated to the Piceance Basin, and 12% is allocated to the Woodford Shale and Fayetteville Shale. For the six months ended June 30, 2011, our total capital expenditures were approximately $326 million. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, commodity prices and drilling results.

In May 2011, we and our lenders amended our Credit Facility. The amendment increased the maximum Credit Facility from $1.0 billion to $1.5 billion. The borrowing base was increased from $550 million to $900 million; however, in accordance with the terms of the Credit Facility, on August 1, 2011 the borrowing base was reduced by $0.25 for each $1 of additional indebtedness to $800 million in connection with the issuance of $400 million of our 7.25% senior notes due 2019. Current lender commitments total $750 million and can be increased to the full $800 million borrowing base upon approval of the lending bank group. As amended, the Credit Facility matures in May 2016. The borrowing base is redetermined semiannually and the borrowing base is based on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions. The next redetermination is scheduled to occur in October 2011.

As of June 30, 2011, we have entered into hedging contracts covering a total of approximately 463 Bcfe of our projected natural gas and oil production from July 1, 2011 through December 31, 2016 at a weighted average index price of $5.79 per Mcfe. For the six months ending December 31, 2011, we have hedged approximately 37 Bcfe of our projected natural gas and oil production at a weighted average index price of $5.73 per Mcfe.

On August 1, 2011, we issued $400 million of 7.25% senior notes due August 2019 at par. We used the proceeds to repay amounts outstanding under the Credit Facility, for development of our oil and natural gas properties and for general corporate purposes.

We operate in one industry segment, which is the exploration, development and production of natural gas, NGLs, and oil, and all of our operations are conducted in the United States. Our gathering assets are primarily dedicated to supporting the natural gas volumes we produce.

Source of Our Revenues

Our production revenues are entirely from the continental United States and currently are comprised of approximately 88% natural gas, 8% natural gas liquids, and 4% oil. Natural gas and oil prices are inherently volatile and are influenced by many factors

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outside of our control. 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. We currently use fixed price natural gas and oil 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 each period end we estimate the fair value of these swaps and recognize an unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. During the six months ended June 30, 2010 and 2011, we recognized significant unrealized commodity gains or losses on these swaps. We expect continued volatility in the fair value of these swaps.

Principal Components of Our Cost Structure

· Lease operating and gathering, compression and transportation expenses. These are daily costs incurred to bring natural gas and oil out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our natural gas and oil properties. Cost levels for these expenses can vary based on industry drilling and production activity levels and the resulting demand fluctuations for oilfield services.

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

· Exploration expense. These are geological and geophysical costs, including delay rentals and the costs of unsuccessful exploratory dry holes and unsuccessful leasing efforts.

· Impairment of unproved and proved properties. These costs include unproved property impairment and costs associated with lease expirations. We could also record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows. From our inception through June 30, 2011, it has not been necessary to record any impairment for proved properties.

· Depreciation, depletion and amortization. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas 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.

· Interest expense. We finance a portion of our working capital requirements and acquisitions with borrowings under our Credit Facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We also have fixed interest on our outstanding senior notes. We will likely continue to incur significant interest expense as we continue to grow. From time to time, we have entered into variable to fixed interest rate swaps to mitigate the effects of interest rate changes. We do not designate these swaps as hedges and therefore do not accord them hedge accounting treatment. Realized and unrealized gains or losses on these interest rate derivative instruments are included as a separate line item in other income (expense). All of our interest rate swaps have expired as of June 30, 2011.

· Income tax expense. Each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. 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 (“IDC”). We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis. Collectively, the operating entities have generated net operating loss carryforwards which expire at various dates from 2024 through 2030. We have not recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will not realize a future benefit equal to the full amount of the loss carryforward over time. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income, estimates of future taxable income are reduced, or tax laws are changed.

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Results of Operations

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2011

The following table sets forth selected operating data for the three months ended June 30, 2010 compared to the three months ended June 30, 2011:

	Three Months Ended June 30,						Amount of Increase			Percent
	2010			2011			(Decrease)			Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	40,268		$	86,695		$	46,427		115	%
Natural gas liquids sales	2,619			7,976			5,357			205	%
Oil sales	2,303			2,888			585			25	%
Realized commodity derivative gains	16,176			19,320			3,144			19	%
Unrealized commodity derivative gains	10,148			97,815			87,667			864	%
Gathering and processing	6,076			—			(6,076		)	*
Total operating revenues	77,590			214,694			137,104			177	%
Operating expenses:
Lease operating expense	6,277			7,683			1,406			22	%
Gathering, compression and transportation	10,757			19,807			9,050			84	%
Production taxes	1,932			4,109			2,177			113	%
Exploration expense	2,047			2,304			257			13	%
Impairment of unproved properties	18,285			782			(17,503		)	(96	)%
Depletion depreciation and amortization	32,265			38,979			6,714			21	%
Accretion of asset retirement obligations	75			109			34			45	%
General and administrative	4,757			8,207			3,450			73	%
Loss on sale of compressor station	—			8,700			8,700			*
Total operating expenses	76,395			90,680			14,285			19	%
Operating income	1,195			124,014			122,819			*
Other income (expense):
Interest expense	(13,965		)	(15,606		)	(1,641		)	12	%
Realized interest rate derivative losses	(2,172		)	(2,165		)	7			*
Unrealized interest rate derivative gains	1,949			2,165			216			11	%
Total other expense	(14,188		)	(15,606		)	(1,418		)	10	%
Income (loss) before income taxes	(12,993		)	108,408			121,401			*
Deferred income tax expense	(2,862		)	(33,785		)	(30,923		)	*
Net income (loss)	(15,855		)	74,623			90,478			*
Non-controlling interest in net income of consolidated subsidiary	(552		)	—			552			*
Net income (loss) attributable to Antero members	$	(16,407	)	$	74,623		$	91,030		*

EBITDAX (3)	$	43,204		$	77,230		$	34,026		79	%

Production data:
Natural gas (Bcf)	10			19			9			90	%
Oil (MBbl)	36			34			(2		)	(6	)%
NGLs (MBbl)(1)	148			150			2			1	%
Combined (Bcfe)	11			20			9			82	%
Daily combined production (MMcfe/d)	124			221			97			78	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.95		$	4.56		$	0.61		15	%
Natural gas liquids (per Bbl)	$	45.58		$	53.01		$	7.43		16	%
Oil (per Bbl)	$	63.27		$	85.98		$	22.71		36	%
Combined (per Mcfe)	$	4.23		$	4.85		$	0.62		15	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	5.53		$	5.59		$	0.06		1	%
Natural gas liquids (per Bbl)	$	45.58		$	53.01		$	7.43		16	%
Oil (per Bbl)	$	63.27		$	75.59		$	12.32		19	%
Combined (per Mcfe)	$	5.74		$	5.81		$	0.07		1	%
Average Costs (per Mcfe):
Lease operating costs	$	0.59		$	0.38		$	(0.21	)	(36	)%
Gathering, compression and transportation	$	1.01		$	0.98		$	(0.03	)	(3	)%
Production taxes	$	0.18		$	0.20		$	0.02		11	%
Depletion, depreciation amortization and accretion	$	3.02		$	1.94		$	(1.08	)	(36	)%
General and administrative	$	0.44		$	0.41		$	(0.03	)	(7	)%

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the Piceance and Arkoma Basins separately from natural gas sales in the first quarter of 2011. We have also reclassified NGL revenues realized in the prior year period from natural gas sales.

In 2010, NGL quantities include 102 MBbl of NGLs retained by our midstream business as compensation for processing third-party gas under long-term contracts. These quantities are not reflected in the per Mcfe data in this table. Our midstream business was sold in November 2010.

(2) Average prices shown in the table reflect both of the before-and-after effects of our realized commodity hedging transactions. 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) See “Non-GAAP Financial Measure” included elsewhere in this report for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

* Not meaningful or applicable

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, natural gas liquids, and oil increased from $45 million for the three months ended June 30, 2010 to $97 million for the three months ended June 30, 2011, an increase of $52 million, or 115%. Our production increased by 78% from 11 Bcfe for the three months ended June 30, 2010 to 20 Bcfe for the three months ended June 30, 2011 and prices increased by 13%, before the effect of realized hedge gains. The net increase in revenues resulted from increased production volumes, which accounted for a $46 million increase in revenues (calculated as the increase in year-to-year volumes times the prior year average price), and commodity price increases which accounted for $6 million of the increase in revenues (calculated as the decrease in year-to-year average price times current year production volumes).

Commodity hedging activities. 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 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 realized gains or losses on the derivative instruments, are recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate from the fixed price we will receive on future production.

For the three months ended June 30, 2010 and 2011, our hedges resulted in realized gains of $16 million and $19 million, respectively. For the three months ended June 30, 2010 and 2011, our hedges resulted in unrealized gains of $10 million and $98 million, respectively. 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.

Gathering and processing revenues. Because we sold our Oklahoma midstream assets in the fourth quarter of 2010, we had no gathering and processing revenues for the three months ended June 30, 2011. Gathering and processing revenues were $6 million for the three months ended June 30, 2010.

Lease operating expenses. Lease operating expenses increased from $6 million for the three months ended June 30, 2010 to $8 million for the three months ended June 30, 2011, an increase of 22%, due to a 78% increase in production primarily in the Appalachian Basin. On a per unit basis, lease operating expenses decreased by 36%, from $0.59 per Mcfe for the three months ended June 30, 2010 to $0.38 for the three months ended June 30, 2011.

Gathering, compression and transportation. Gathering, compression and transportation expense increased from $11 million for the three months ended June 30, 2010 to $20 million for the three months ended June 30, 2011 primarily due to an increase in production volumes and increased costs on firm transportation commitments. On a total per unit basis, these expenses decreased from $1.01 per Mcfe for the three months ended June 30, 2010 to $0.98 per Mcfe for the three months ended June 30, 2011. Transportation expenses are expected to increase over the remainder of 2011 because our commitment on the Ruby Pipeline from the Piceance Basin to the West Coast begins in July 2011.

Production taxes. Total production taxes increased by approximately $2.2 million for the three months ended June 30, 2011 compared to the prior year period, primarily as a result of increased production. On a per unit basis, production taxes per Mcfe increased from $0.18 to $0.20 per Mcfe. Production taxes as a percentage of natural gas, NGL, and oil revenues were 4.3% for both the three months ended June 30, 2010 and 2011. Production taxes are primarily based on the wellhead values of production and the applicable rates vary across the areas in which we operate. As the proportion of our production changes from area to area, our

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production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

Exploration expense. Exploration expense was $2 million for both the three months ended June 30, 2010 and 2011.

Impairment of unproved properties. Impairment of unproved properties was approximately $18 million for the three months ended June 30, 2010 compared to less than $1 million for the three months ended June 30, 2011. The decrease in impairment charges is due to the combined effect of (1) drilling activities in our Arkoma and Piceance projects which have resulted in a greater portion of our acreage being held by production and, (2) impairment charges for non-productive expiring acreage in these project areas in prior periods resulting in fewer current period expirations and less acreage to evaluate. We charge impairment expense for expired or soon to expire 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.

Depreciation, depletion and amortization (DD&A). DD&A increased from $32 million for three months ended June 30, 2010 to $39 million for the three months ended June 30, 2011 primarily because of increased production. DD&A per Mcfe decreased by 36% from $3.02 per Mcfe during the three months ended June 30, 2010 to $1.94 per Mcfe during the three months ended June 30, 2011, primarily as a result of increased reserves in 2011.

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 June 30, 2010 or 2011 for proved properties.

General and administrative. General and administrative expense increased from $5 million for the three months ended June 30, 2010 to $8 million for the three months ended June 30, 2011 primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses, all related to our growth in production levels and exploration activities. On a per unit basis, general and administrative expense decreased by 7%, from $0.44 per Mcfe during the three months ended June 30, 2010 to $0.41 per Mcfe during the three months ended June 30, 2011, primarily due to a 78% increase in production.

Interest expense and realized and unrealized gains and losses on interest rate derivatives. Interest expense increased from $14 million for the three months ended June 30, 2010 to $16 million during the three months ended June 30, 2011 due to increased borrowings on the Credit Facility. Interest expense includes approximately $2 million of non-cash amortization of deferred financing costs for the each of the three months ended June 30, 2010 and 2011.

We have entered into various variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our Credit Facility and the previously outstanding second lien term loan facility. During the three months ended June 30, 2011, one of these swaps remained outstanding with a notional amount of $225 million and a fixed pay rate of 4.11%. This swap expired on July 1, 2011. During each of the three months ended June 30, 2010 and 2011, we had realized losses on interest rate swap agreements of $2 million. As of June 30, 2011, we had no remaining liability for outstanding interest rate swaps.

Income tax expense. Income tax expense reflects the fact that each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. None of the operating entities has taxable income in either the current or prior years, which is primarily attributable to the differing book and tax treatment of unrealized derivative gains and intangible drilling costs. Accordingly, valuation allowances have generally been established against net operating loss (“NOLs”) carryforwards to the extent that such NOLs exceed net deferred tax liabilities, resulting in no income tax expense or benefit for those subsidiaries having deferred tax assets in excess of deferred tax liabilities. We have not recognized the full value of these NOLs on our balance sheet because our management team believes it is more likely than not that we will not realize a future benefit for the full amount of the loss carryforwards over time.

Certain subsidiaries had net deferred tax liabilities at June 30, 2011, resulting from unrealized gains on commodity derivatives and basis differences in assets. Deferred income tax expense of $34 million during the three months ended June 30, 2011 resulted from the increase in the unrealized gains on commodity derivatives during the quarter.

At December 31, 2010, the operating entities had a combined total of approximately $509 million of NOLs, which expire starting in 2024 and through 2030. Proposed legislation in the U.S. Congress would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that legislation is enacted.

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Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2011

The following table sets forth selected operating data for the six months ended June 30, 2010 compared to the six months ended June 30, 2011:

	Six Months Ended June 30,						Amount of Increase			Percent
	2010			2011			(Decrease)			Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	92,508		$	147,553		$	55,045		60	%
Natural gas liquids sales	4,331			13,561			9,230			213	%
Oil sales	4,417			5,416			999			23	%
Realized commodity derivative gains	28,447			48,558			20,111			71	%
Unrealized commodity derivative gains (losses)	108,960			20,549			(88,411		)	(81	)%
Gathering and processing	12,489			—			(12,489		)	*
Total operating revenues	251,152			235,637			(15,515		)	(6	)%
Operating expenses:
Lease operating expense	10,875			14,984			4,109			38	%
Gathering, compression and transportation	20,898			36,957			16,059			77	%
Production taxes	4,602			7,237			2,635			57	%
Exploration expense	3,399			5,433			2,034			60	%
Impairment of unproved properties	20,547			3,100			(17,447		)	(85	)%
Depletion depreciation and amortization	65,261			72,648			7,387			11	%
Accretion of asset retirement obligations	148			205			57			39	%
General and administrative	9,168			14,568			5,400			59	%
Loss on sale of compressor station	—			8,700			8,700			*
Total operating expenses	134,898			163,832			28,934			21	%
Operating income (loss)	116,254			71,805			(44,449		)	*
Other income (expense):
Interest expense	(27,257		)	(30,660		)	(3,403		)	(12	)%
Realized interest rate derivative losses	(5,299		)	(4,306		)	993			(19	)%
Unrealized interest rate derivative gains	3,474			4,212			738			21	%
Total other expense	(29,082		)	(30,754		)	(1,672		)	6	%
Income (loss) before income taxes	87,172			41,051			(46,121		)	*
Deferred income tax (expense) benefit	(14,180		)	(25,363		)	(11,183		)	*
Net income (loss)	72,992			15,688			(57,304		)	*
Non-controlling interest in net income of consolidated subsidiary	(1,793		)	—			1,793			*
Net income (loss) attributable to Antero members	$	71,199		$	15,688		$	(55,511	)	*

EBITDAX (3)	$	94,929		$	141,865		$	46,936		49	%

Production data:
Natural gas (Bcf)	20			34			14			70	%
Oil (MBbl)	68			65			(3		)	(4	)%
NGLs (MBbl)(1)	282			276			(6		)	(2	)%
Combined (Bcfe)	22			36			14			64	%
Daily combined production (MMcfe/d)	121			197			76			63	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	4.67		$	4.39		$	(0.28	)	(6	)%
Natural gas liquids (per Bbl)	$	47.70		$	49.08		1.38			3	%
Oil (per Bbl)	$	64.67		$	82.88		$	18.21		28	%
Combined (per Mcfe)	$	4.88		$	4.67		$	(0.21	)	(4	)%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	6.11		$	5.84		$	(0.27	)	(4	)%
Natural gas liquids (per Bbl)	$	47.70		$	49.08		1.38			3	%
Oil (per Bbl)	$	64.67		$	75.27		$	10.60		16	%
Combined (per Mcfe)	$	6.25		$	6.03		$	(0.22	)	(4	)%
Average Costs (per Mcfe):
Lease operating costs	$	0.52		$	0.42		$	(0.10	)	(19	)%
Gathering, compression and transportation	$	1.01		$	1.04		$	0.03		3	%
Production taxes	$	0.22		$	0.20		$	(0.02	)	(9	)%
Depletion, depreciation amortization and accretion	$	3.14		$	2.04		$	(1.10	)	(35	)%
General and administrative	$	0.44		$	0.41		$	(0.03	)	(7	)%

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(1) Effective January 1, 2011, we began realizing the value of our processed NGLs from the Piceance Basin as a result of a new processing agreement. Because of their greater current significance, we have begun reporting our NGL revenues from both the Piceance and Arkoma Basins separately from natural gas sales in the first quarter of 2011. We have also reclassified NGL revenues realized in the prior year period from natural gas sales.

In 2010, NGL quantities include 191 MBbl of NGLs retained by our midstream business as compensation for processing third-party gas under long-term contracts. These quantities are not reflected in the per Mcfe data in this table. Our midstream business was sold in November 2010.

(3) See “Non-GAAP Financial Measure” included elsewhere in this report for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income.

* Not meaningful or applicable

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, natural gas liquids, and oil increased from $101 million for the six months ended June 30, 2010 to $166 million for the six months ended June 30, 2011, an increase of $65 million, or 64%. Our production increased by 63% from 22 Bcfe for the six months ended June 30, 2010 to 36 Bcfe for the six months ended June 30, 2011 and prices decreased by 5%, before the effect of realized hedge gains. The net increase in revenues resulted from increased production volumes, which accounted for a $70 million increase in revenues (calculated as the increase in year-to-year volumes times the prior year average price), and commodity price declines, which accounted for a decrease in revenues of $5 million (calculated as the decrease in year-to-year average price times current year production volumes).

Commodity hedging activities. For the six months ended June 30, 2010 and 2011, our hedges resulted in realized gains of $28 million and $49 million, respectively. For the six months ended June 30, 2010 and 2011, our hedges resulted in unrealized gains of $109 million and $21 million, respectively. 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.

Gathering and processing revenues. Because we sold our Oklahoma midstream assets in the fourth quarter of 2010, we had no gathering and processing revenues for the six months ended June 30, 2011. Gathering and processing revenues were $12 million for the six months ended June 30, 2010.

Lease operating expenses. Lease operating expenses increased from $11 million for the six months ended June 30, 2010 to $15 million for the six months ended June 30, 2011, an increase of 38%, primarily due to a 63% increase in production primarily from the Appalachian Basin and increased workover expenses in the Piceance Basin. On a per unit basis, lease operating expenses decreased by 19%, from $0.52 per Mcfe for the six months ended June 30, 2010 to $0.42 for the six months ended June 30, 2011.

Gathering, compression and transportation. Gathering, compression and transportation expense increased from $21 million for the six months ended June 30, 2010 to $37 million for the six months ended June 30, 2011 primarily due to an increase in production volumes and increased costs on firm transportation commitments. On a total per unit basis, these expenses increased from $1.01 per Mcfe for the six months ended June 30, 2010 to $1.04 per Mcfe for the six months ended June 30, 2011. Transportation expenses are expected to increase over the remainder of 2011 because our commitment on the Ruby Pipeline from the Piceance Basin to the West Coast begins in July 2011.

Production taxes. Total production taxes increased by approximately $3 million for the six months ended June 30, 2011 compared to the prior year period, primarily as a result of the increased production. On a per unit basis, production taxes per Mcfe decreased from $0.22 to $0.20 per Mcfe. Production taxes as a percentage of natural gas, NGL, and oil revenues were 4.5% for the six months ended June 30, 2010 compared to 4.4% for the six months ended June 30, 2011. Production taxes are primarily based on the wellhead values of production and the applicable rates vary across the areas in which we operate. As the proportion of our production

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changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

Exploration expense. Exploration expense increased from $3 million for the six months ended June 30, 2010 to $5 million for the six months ended June 30, 2011 primarily because of an [increase in dry hole costs.]

Impairment of unproved properties. Impairment of unproved properties was approximately $21 million for the six months ended June 30, 2010 compared to $3 million for the six months ended June 30, 2011. The decrease in impairment charges is due to the combined effect of (1) drilling activities in our Arkoma and Piceance projects which have resulted in a greater portion of our acreage being held by production and (2) impairment charges for non-productive expiring acreage in these project areas in prior periods resulting in fewer current expirations and less acreage to evaluate. We charge impairment expense for expired or soon to expire 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.

Depreciation, depletion and amortization (DD&A). DD&A increased from $65 million for six months ended June 30, 2010 to $73 million for the six months ended June 30, 2011 because of increased production. DD&A per Mcfe decreased by 35% from $3.14 per Mcfe during the six months ended June 30, 2010 to $2.04 per Mcfe during the six months ended June 30, 2011, primarily as a result of increased reserves in 2011.

No impairment expenses were recorded for the six months ended June 30, 2010 or 2011 for proved properties.

General and administrative. General and administrative expense increased from $9 million for the six months ended June 30, 2010 to $15 million for the six months ended June 30, 2011 primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses, all related to our growth in production levels and exploration activities. On a per unit basis, general and administrative expense decreased by 7%, from $0.44 per Mcfe during the six months ended June 30, 2010 to $0.41 per Mcfe during the six months ended June 30, 2011, primarily due to 63% production growth.

Interest expense and realized and unrealized gains and losses on interest rate derivatives. Interest expense increased from $27 million for the six months ended June 30, 2010 to $31 million during the six months ended June 30, 2011 due to increased borrowings on the Credit Facility. Interest expense includes approximately $2 million of non-cash amortization of deferred financing costs for the each of the six months ended June 30, 2010 and 2011.

We have entered into various variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our Credit Facility and the previously outstanding second lien term loan facility. During the six months ended June 30, 2011, one of these swaps remained outstanding with a notional amount of $225 million and a fixed pay rate of 4.11%. This swap expired on July 1, 2011. During the six months ended June 30, 2010 and 2011, we realized a loss on interest rate swap agreements of $5 million and $4 million, respectively. As of June 30, 2011, we had no remaining liability for outstanding interest rate swaps.

Income tax expense. Certain subsidiaries had net deferred tax liabilities at June 30, 2011, resulting from unrealized gains on commodity derivatives and basis differences in assets. Deferred income tax expense of $25 million during the six months ended June 30, 2011 resulted from the increase in the unrealized gains on commodity derivatives during the quarter.

At December 31, 2010, the operating entities had a combined total of approximately $509 million of NOLs, which expire starting in 2024 and through 2030. Congress recently proposed legislation that would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that legislation is enacted.

Capital Resources and Liquidity

Our primary sources of liquidity have been through issuances of equity securities, borrowings under bank credit facilities, issuances of senior notes, 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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Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $61 million and $112 million for the six months ended June 30, 2010 and 2011, respectively. The increase in cash flow from operations from the six months ended June 30, 2010 to the six months ended June 30, 2011 was primarily the result of increased production volumes and revenues, net of 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 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 six months ended June 30, 2010 and 2011, we had cash flows used in investing activities of $162 million and $313 million, respectively, as a result of our capital expenditures for drilling, development and acquisition costs. The increase in cash used in investing activities for the six months ended June 30, 2011 compared to the six months ended June 30, 2010 was a result of higher levels of drilling activity. We expect that our cash used in investing activities will increase for the remainder of 2011 compared to the rate of spending during the first six months of 2011 based on our current capital budget and planned drilling activities.

Our revised capital budget for 2011 is $685 million. 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 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 during the six months ended June 30, 2011 of $196 million was the net result of net borrowings on the Credit Facility of $225 million and $29 million of distributions to members. The distribution to members was required by the limited liability operating agreement to cover income taxes owed by the members as a result of the gain realized on the sale of the Oklahoma midstream assets in the fourth quarter of 2010. Net cash provided by financing activities of $95 million during the six months ended June 30, 2010 was primarily the result of the issuance of $156 million of senior notes, net of payments on the Credit Facility of $56 million, and other items totaling $5 million.

Credit Facility. In May 2011, we and our lenders amended our Credit Facility. The amendment increased the maximum Credit Facility from $1.0 billion to $1.5 billion. The borrowing base was increased from $550 million to $900 million; however, in accordance with the terms of the Credit Facility, on August 1, 2011 the borrowing base was reduced by $0.25 for each $1 of additional indebtedness to $800 million in connection with the issuance of $400 million of our 7.25% senior notes due 2019. Current lender commitments total $750 million and can be increased to the full $800 million borrowing base upon approval of the lending bank group. As amended, the Credit Facility matures in May 2016. The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions. The next redetermination is scheduled to occur in October 2011.

As of June 30, 2011, we had borrowings outstanding under our Credit Facility of $325 million and letters of credit outstanding of approximately $19 million. As of December 31, 2010, we had $118 million of outstanding borrowings and letters of credit. The credit facility is secured by mortgages on substantially all of our properties and guarantees from the operating entities. 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 contains certain covenants, including restrictions on indebtedness, asset sales, investments, liens, dividends, and certain other transactions without the prior consent of the lenders. We are required to maintain the following two financial ratios:

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· a current ratio, which is the ratio of our consolidated current assets (includes unused commitment under 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, 2010 and as of June 30, 2011.

As of December 31, 2010 and June 30, 2011, borrowings and letters of credit outstanding under our Credit Facility totaled $118 million and $344 million, respectively, and had a weighted average interest rate (excluding the impact of our interest rate swaps) of 2.56% and 2.26%, respectively.

Senior Notes. We have $525 million of 9.375% senior notes outstanding which are due December 1, 2017. The notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on June 1 and December 1 each year. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%. At any time prior to December 1, 2013, Antero Finance may also 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. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

The senior notes indenture contains restrictive covenants and a minimum interest coverage ratio requirement of 2.25:1. We were in compliance with such covenants and the coverage ratio requirement as of December 31, 2010 and June 30, 2011.

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par. The notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on August 1, and February 1 of each year, commencing on February 1, 2012. Antero Finance 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. In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the notes, plus accrued interest. At any time prior to August 1, 2014, Antero Finance 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 a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2013, Antero Finance may, at its option, redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the notes, plus accrued interest. If Antero Finance has not exercised its optional redemption rights upon a change of control, the note holders will have the right to require Antero Finance 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.

We used the proceeds from the offering of the notes to repay borrowings outstanding under our Credit Facility, for development of our oil and natural gas properties and for general corporate purposes. In accordance with the terms of the Credit Facility, the borrowing base under our Credit Facility was reduced $0.25 for every $1 of additional indebtedness, to $800 million. After applying the proceeds of the offering, we had approximately $731 million of available borrowing capacity under the Credit Facility.

Treasury Management Facility. On September 14, 2010, the Company executed a stand-alone revolving note with a lender under the Credit Facility which provides for up to $7.5 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 Credit Facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. At June 30, 2011 there were no outstanding borrowings under this facility.

Note Payable. We assumed a $25 million unsecured note payable in the business acquisition consummated on December 1, 2010. The note bears interest at 9% and is due December 1, 2013.

Interest Rate Hedges. We have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our Credit Facility and previously outstanding second lien term loan facility. During the six months ended June 30,

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2011, we had one interest rate swap outstanding for a notional amount of $225 million with a fixed pay rate of 4.11%. The swap expired on July 1, 2011. During the six months ended June 30, 2010 and 2011, we had realized losses on interest rate swap agreements of $5 and $4 million, respectively, and unrealized gains of approximately $3 million and $4 million, respectively. At June 30, 2011 there is no outstanding liability for interest rate swaps.

Non-GAAP Financial Measure

“EBITDAX” is a non-GAAP financial measure that we define as net income before interest, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, franchise taxes, stock compensation and interest income. “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. 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. EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure:

· is widely used by investors in the natural gas and oil 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 a covenant under our Credit Facility. EBITDAX is used as a measure of our operating performance pursuant to a covenant under the indenture governing our $525 million principal amount of 9.375% senior notes due 2017 and our $400 million principal amount of 7.25% senior notes due 2019.

There are significant limitations to using 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 EBITDAX reported by different companies. The following table represents a reconciliation of our net income to EBITDAX for the year ended December 31, 2010 and the six months ended June 30, 2010 and 2011:

	Year Ended December 31,			Three Months Ended June 30,						Six Months Ended June 30,
	2010			2010			2011			2010			2011
										(in thousands)
Net income attributable to Antero members	$	228,628		$	(16,407	)	$	74,623		$	71,199		$	15,688
Unrealized gains on derivative contracts	(170,571		)	(10,148		)	(97,814		)	(108,960		)	(20,549		)
Gain on sale of Oklahoma midstream assets	(147,559		)	—			—
Interest expense and other	59,140			14,188			15,606			29,082			30,754
Provision for income taxes	30,009			2,862			33,785			14,180			25,363
Depreciation, depletion, amortization and accretion	134,272			32,340			39,088			65,409			72,853
Impairment of unproved properties	35,859			18,285			782			20,547			3,100
Exploration expense	24,794			2,047			2,304			3,399			5,433
Loss on sale of compressor station	—			—			8,700			—			8,700
Other	3,106			37			156			73			523
EBITDAX	$	197,678		$	43,204		$	77,230		$	94,929		$	141,865

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,

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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 Annual Report on Form 10-K for the year end December 31, 2010. 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 Annual Report on Form 10-K for the year end December 31, 2010 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 June 30, 2011 that had a significant effect on the Company’s financial reporting.

Off-Balance Sheet Arrangements and Contractual Obligations

Currently, we do not have any off-balance sheet arrangements other than operating leases. There have been no material changes to contractual obligations from those reported in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity Price Risk and Hedging Activities

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 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. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the Centerpoint East, CIG Hub, Transco Zone 4 and Columbia Gas Transmission (CGTAP), and Dominion South Indices.

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 December 31, 2010 and June 30, 2011, we had in place natural gas and oil swaps covering portions of our projected production from 2011 through 2016. Our hedge position as of June 30, 2011 is summarized in note 7 to our consolidated financial statements included elsewhere in this report. 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 and 65% for 49 to 60 months in the future. Based on our production for the six months ended June

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30, 2011 and our fixed price swap contracts in place during that period, our income before taxes for the six months ended June 30, 2011 would have decreased by approximately $1.6 million for each $0.10 decrease per MMBtu in natural gas prices and $0.3 million for each $1.00 decline in oil prices.

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 December 31, 2010, the estimated fair value of our commodity derivative instruments was a net asset of $230 million comprised of current and noncurrent assets. At June 30, 2011, the estimated fair value of our commodity derivative instruments was a net asset of $251 million comprised of current and noncurrent assets.

By removing price volatility from a portion of our expected natural gas production through December 2016, 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.

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 nine different counterparties, all but one of which is a lender under our Credit Facility. As of June 30, 2011, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, Dominion Field Services, Barclays, Credit Suisse, Union Bank, and KeyBank accounted for approximately 42%, 23%, 11%, 8%, 8%, 6%, 1%, and 1%, respectively, of the net fair value of our commodity derivative assets position. We believe 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 June 30, 2011, we have no past due receivables from or payables to any of our counterparties.

Interest Rate Risks and Hedges

During the six months ended June 30, 2011, we had indebtedness outstanding under our Credit Facility, which has a floating interest rate. The average annual interest rate incurred on this indebtedness for the six months ended June 30, 2011, was approximately 2.4% without giving effect to interest rate swaps. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2011, would have resulted in an estimated $1 million increase in interest expense for the six months ended June 30, 2011 before giving effect to interest rate swaps. During the six months ended June 30, 2011, a significant part of our indebtedness consisted of fixed rate 9.375% senior notes due 2017 having an outstanding principal amount of $525 million.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2011.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

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 the our Annual Report on Form 10-K for the year ended December 31, 2010. The risks described in the Annual Report on Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations. Except as set forth below, there have been no material changes to the risks described in the 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.

Recently proposed rules regulating air emissions from oil and gas operations could cause us to incur increased capital expenditures and operating costs

On July 28, 2011, the Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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Item 6. Exhibits.

Exhibit Number		Description of Exhibits
3.1		Certificate of Incorporation of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.2		Bylaws of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.3		Certificate of Formation of Antero Resources LLC (incorporated by reference to Exhibit 3.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.4		Amended and Restated Limited Liability Company Agreement of Antero Resources LLC dated as of December 1, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 3, 2010).
4.1		Indenture dated as of November 17, 2009 among Antero Resources Finance Corporation, the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
4.2		Registration Rights Agreement dated as of November 17, 2009 among Antero Resources Finance Corporation, the several guarantors named therein, and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4 No. (Commission File No. 333-164876) filed on February 12, 2010).
4.3		Registration Rights Agreement dated as of January 19, 2010 among Antero Resources Finance Corporation, the several guarantors named therein, and the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
4.4		Registration Rights Agreement dated as of November 3, 2009 by and among Antero Resources LLC and the other parties named therein (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4 No. (File No. 333-164876) filed on February 12, 2010).
4.5		Indenture, dated as of August 1, 2011, by and among Antero Resources Finance Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on August 1, 2011).
4.6		Registration Rights Agreement, dated as of August 1, 2011, by and among Antero Resources Finance Corporation, the several guarantors named therein and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K (Commission File No. 333-164876) filed on August 1, 2011).
10.1		Second Amendment to Fourth Amended And Restated Credit Agreement, dated as of July 8, 2011, among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on July 11, 2011).
10.2		Purchase Agreement, dated as of July 27, 2011, by and among Antero Resources Finance Corporation, the guarantors party thereto and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on August 1, 2011).
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 the quarterly report on Form 10-Q of Antero Resources Finance Corporation for the quarter ended March 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iv) Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.

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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.

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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 FINANCE CORPORATION


Date: August 12, 2011	By:	/s/ GLEN C. WARREN, JR.
		Glen C. Warren, Jr.
		President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

Antero Resources Finance Corp 10-Q