Antero Resources Finance Corp - FORM 10-Q

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EX-32.2 - EX-32.2 - Antero Resources Finance Corp	a10-17729_1ex32d2.htm
EX-31.2 - EX-31.2 - Antero Resources Finance Corp	a10-17729_1ex31d2.htm
EX-31.1 - EX-31.1 - Antero Resources Finance Corp	a10-17729_1ex31d1.htm
EX-32.1 - EX-32.1 - Antero Resources Finance Corp	a10-17729_1ex32d1.htm

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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 September 30, 2010

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

1625 17th Street Denver, Colorado (Address of principal executive offices)		80202 (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. o Yes x 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

PART I. FINANCIAL INFORMATION		1
Item 1.	Financial Information	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results Of Operations	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	42
PART II OTHER INFORMATION		43
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3.	Defaults upon Senior Securities	43
Item 4.	(Removed and Reserved)	43
Item 5.	Other Information	43
Item 6.	Exhibits	44
SIGNATURES		45

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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. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” in our Registration Statement on Form S-4 (Commission File No. 333-164876) filed on June 3, 2010 (the “Form S-4”) and Part II, Item 1A—“Risk Factors” of this report. 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 and oil prices;

· timing and amount of future production of natural gas and oil;

· hedging strategy and results;

· future drilling plans;

· competition and government regulations;

· pending legal or environmental matters;

· marketing of natural gas and oil;

· leasehold or business acquisitions;

· costs of developing our properties and gathering and other midstream operations;

· general economic conditions;

· credit markets;

· liquidity and access to capital;

· 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 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 “Risk Factors” in the Form S-4 and in Part II, Item 1A—“Risk Factors” of this report.

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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 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 the Form S-4 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, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

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Item 1. Financial Information

ANTERO RESOURCES LLC

Consolidated Balance Sheets

December 31, 2009 and September 30, 2010

(In thousands)

(Unaudited)

	December 31,			September 30,
	2009			2010
Assets
Current assets:
Cash and cash equivalents	$	10,669		—
Accounts receivable — trade, net of allowance for doubtful accounts of $424 and $191, respectively	35,897			22,636
Accrued revenue	17,459			18,310
Prepaid expenses and drilling costs	7,419			16,937
Derivative instruments	22,105			87,496
Inventories	1,295			2,064
Assets held for sale	—			160,294
Total current assets	94,844			307,737
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties	596,694			579,845
Producing properties	1,340,827			1,614,397
Gathering systems and facilities	185,688			30,886
Other property and equipment	3,302			5,574
	2,126,511			2,230,702
Less accumulated depletion, depreciation, and amortization	(322,992		)	(399,061	)
Property and equipment, net	1,803,519			1,831,641
Derivative instruments	18,989			170,997
Other assets, net	19,214			16,202
Total assets	$	1,936,566		2,326,577

(Continued)

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ANTERO RESOURCES LLC

Consolidated Balance Sheets

December 31, 2009 and September 30, 2010

(In thousands)

(Unaudited)

	December 31,			September 30,
	2009			2010
Liabilities and Equity
Current liabilities:
Accounts payable	$	48,594		75,463
Accrued expenses	24,440			36,926
Revenue distributions payable	29,304			20,004
Advances from joint interest owners	1,400			1,847
Derivative instruments	8,623			6,312
Capital leases — current	132			152
Liabilities related to assets held for sale	—			19,231
Total current liabilities	112,493			159,935
Long-term liabilities:
Bank credit facility	142,080			155,994
Senior notes	372,397			528,110
Derivative instruments	2,464			—
Asset retirement obligations	3,487			3,934
Deferred tax payable	424			38,082
Other long-term liabilities	4,114			3,359
Total liabilities	637,459			889,414
Equity:
Members’ equity	1,392,833			1,392,806
Accumulated earnings (deficit)	(123,447		)	15,532
	1,269,386			1,408,338
Noncontrolling interest in consolidated subsidiary	29,721			28,825
Total equity	1,299,107			1,437,163
Total liabilities and equity	$	1,936,566		2,326,577

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Operations

Three months ended September 30, 2009 and 2010

(In thousands)

(Unaudited)

	2009			2010
Revenue:
Natural gas sales	$	30,008		49,870
Net realized and unrealized gains (losses) on commodity derivative instruments including unrealized gains (losses) of $(44,293) and $108,439, respectively	(16,437		)	125,875
Oil sales	1,664			1,684
Gathering and processing revenue	6,209			5,973
Total revenue	21,444			183,402

Operating expenses:
Lease operating expenses	3,664			6,070
Gathering, compression, and transportation	7,522			11,210
Production taxes	1,565			2,187
Exploration expenses	3,094			3,644
Impairment of unproved properties	9,885			11,043
Depletion, depreciation, and amortization	34,805			35,886
Accretion of asset retirement obligations	68			79
General and administrative	5,122			5,296
Total operating expenses	65,725			75,415
Operating income (loss)	(44,281		)	107,987

Other expense:
Interest expense, net	(7,184		)	(14,526	)
Net realized and unrealized losses on interest rate derivative instruments including unrealized gains of $1,114 and $1,302, respectively	(2,031		)	(755	)
Total other expense	(9,215		)	(15,281	)
Income (loss) before income taxes	(53,496		)	92,706
Deferred income tax expense	—			(25,107	)
Net income (loss)	(53,496		)	67,599
Noncontrolling interest in net loss of consolidated subsidiary	151			181
Net income (loss) attributable to Antero members	$	(53,345	)	67,780

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Operations

Nine months ended September 30, 2009 and 2010

(In thousands)

(Unaudited)

	2009			2010
Revenue:
Natural gas sales	$	91,603		146,709
Net realized and unrealized gains on commodity derivative instruments including unrealized gains (losses) of $(70,742) and $217,399, respectively	19,669			263,282
Oil sales	4,251			6,101
Gathering and processing revenue	15,902			18,462
Total revenue	131,425			434,554

Operating expenses:
Lease operating expenses	14,389			16,945
Gathering, compression, and transportation	19,183			32,108
Production taxes	4,393			6,789
Exploration expenses	8,440			7,043
Impairment of unproved properties	24,583			31,590
Depletion, depreciation, and amortization	108,987			101,147
Accretion of asset retirement obligations	194			227
General and administrative	14,396			14,464
Total operating expenses	194,565			210,313
Operating income (loss)	(63,140		)	224,241

Other expense:
Interest expense, net	(23,410		)	(41,783	)
Net realized and unrealized losses on interest rate derivative instruments including unrealized gains of $3,811 and $4,776, respectively	(3,856		)	(2,580	)
Total other expense	(27,266		)	(44,363	)
Income (loss) before income taxes	(90,406		)	179,878
Deferred income tax benefit (expense)	3,029			(39,287	)
Net income (loss)	(87,377		)	140,591
Noncontrolling interest in net loss (income) of consolidated subsidiary	539			(1,612	)
Net income (loss) attributable to Antero members	$	(86,838	)	138,979

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Consolidated Statements of Cash Flows

Nine months ended September 30, 2009 and 2010

(In thousands)

(Unaudited)

	2009			2010
Cash flows from operating activities:
Net income (loss)	$	(87,377	)	140,591
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and amortization	108,987			101,147
Dry hole costs	760			2,981
Impairment of unproved properties	24,583			31,590
Accretion of asset retirement obligations	194			227
Amortization of bond premium	—			(287	)
Amortization of deferred financing costs	2,410			3,095
Stock compensation	527			—
Unrealized losses (gains) on derivative instruments, net	66,931			(222,175	)
Deferred tax expense (benefit)	(3,029		)	39,287
Changes in current assets and liabilities:
Accounts receivable	22,262			951
Accrued revenue	7,588			(850	)
Prepaid expenses and drilling costs	187			(9,749	)
Inventories	745			(830	)
Accounts payable	(18,666		)	3,305
Accrued expenses	(679		)	14,145
Revenue distributions payable	(758		)	2,636
Advances from joint interest owners	(6,434		)	447
Net cash provided by operating activities	118,231			106,511

Cash flows from investing activities:
Additions to unproved properties	(9,459		)	(27,997	)
Drilling costs	(216,862		)	(239,257	)
Gathering systems and facilities	(3,696		)	(8,825	)
Additions to other property and equipment	(144		)	(2,391	)
Decrease (increase) in other assets	159			(317	)
Net cash used in investing activities	(230,002		)	(278,787	)

(Continued)

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ANTERO RESOURCES LLC

Consolidated Statements of Cash Flows

Nine months ended September 30, 2009 and 2010

(In thousands)

(Unaudited)

	2009			2010
Cash flows from financing activities:
Issuance of senior notes	$	—		156,000
Borrowings on bank credit facility	15,000			170,994
Payments on bank credit facility	(25,000		)	(157,080	)
Payments on capital lease obligations	(93		)	(148	)
Financing costs	(6,461		)	(3,788	)
Issuance of preferred stock	105,000			—
Other	(220		)	443
Net cash from (to) noncontrolling interest	766			(2,508	)
Net cash provided by financing activities	88,992			163,913
Net decrease in cash and cash equivalents	(22,779		)	(8,363	)
Cash classified as assets held for sale	—			(2,306	)
Cash and cash equivalents, beginning of period	38,969			10,669
Cash and cash equivalents, end of period	$	16,190		—
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(27,654	)	(26,939	)
Supplemental disclosure of noncash investing activities:
Net changes in accounts payable for additions to properties, systems, and facilities	$	(85,688	)	23,819

See accompanying notes to consolidated financial statements.

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

(1) Organization

(a) Business and 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 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 September 30, 2010 and December 31, 2009 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 Midstream Corporation (Antero Midstream), Antero Resources Pipeline Corporation (Antero Pipeline), Antero Resources Appalachian Corporation (Antero Appalachian), and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities). The consolidated financial statements for the three months and nine months ended September 30, 2009 and 2010 include the accounts of the Antero Entities. For periods prior to October 2009, ownership of the entities was under common control; the outstanding equity instruments of these entities were held by the same individuals or entities in the same percentage. In October 2009, the equity structure was reorganized in a nontaxable transaction through the formation of Antero Resources LLC, which issued units of members’ equity to the stockholders of the operating entities in exchange for all of their preferred and common shares in each entity. The assets and liabilities of each of the entities are included in the consolidated financial statements at their historical basis.

(b) Centrahoma Processing Joint Venture

Antero Midstream has a 60% interest in Centrahoma Processing LLC, a joint venture formed along with MarkWest Oklahoma Gas Company, LLC (MarkWest) to process gas from the Arkoma Basin. The joint venture is accounted for as a consolidated subsidiary with MarkWest’s 40% interest accounted for as a noncontrolling interest in the consolidated financial statements.

(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 (SEC) applicable to interim financial information and should be read in the context of the December 31, 2009 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2009 consolidated financial statements have been filed with the SEC in the Company’s Registration Statement on Form S-4 (Registration No. 333-164876).

(Continued)

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

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 September 30, 2010, and the results of its operations and its cash flows for the three months and nine months ended September 30, 2009 and 2010. All significant intercompany accounts and transactions have been eliminated. We have evaluated subsequent events after the consolidated balance sheet date of September 30, 2010 through the date of this filing. Operating results for the periods ended September 30, 2010 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.

(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 the region, availability of transportation capacity to other regions of the country, and various other factors. Increases or decreases in prices received could have a significant impact on the Company’s future results of operations.

(d) 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

(Continued)

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

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 has not designated any of its derivative instruments as accounting hedges; therefore, derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value and changes in the fair value of derivatives are recorded 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).

(e) 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 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.

(f) 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, 2009 of approximately $323 million. Approximately $35 million of the NOLs relate to

(Continued)

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Antero Midstream, which was sold on November 5, 2010 (see note 3). 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 three month and nine month periods ended September 30, 2009 and 2010 primarily because of changes in the valuation allowance resulting from deferred tax liabilities arising in the period.

(g) 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 three months ended September 30, 2010 was $11.0 million compared to $9.9 million for the three months ended September 30, 2009. Impairment of unproved properties for the nine months ended September 30, 2010 was $31.6 million compared to $24.6 million for the nine months ended September 30, 2009.

(h) 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) Sale of Oklahoma Midstream Operations

On October 1, 2010, the Company entered into definitive agreements to sell Antero Midstream and its investment in the Centrahoma Processing LLC joint venture for a total of approximately $268 million in cash. The sale transaction closed on November 5, 2010. The assets and liabilities of Antero Midstream

(Continued)

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ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

have been classified as held for sale in the consolidated balance sheet at September 30, 2010 and consists primarily of gathering systems and facilities. The Company used the net proceeds from the sale to pay down outstanding borrowings under its revolving credit facility and to fund drilling expenditures.

(4) Credit Facilities

(a) Bank Credit Facility

On November 4, 2010, the Company entered into an amended and restated credit agreement (Credit Facility) with its lenders increasing the maximum amount of the revolving facility from $400.0 million to $1 billion. The borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved reserves and are subject to regular semiannual redeterminations. The initial borrowing base was set at $550.0 million. The next semiannual redetermination of the borrowing base is scheduled to occur in April 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 amended and restated Credit Facility provides that all advances are due and payable on November 4, 2015. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage 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 is in compliance with its financial debt covenants as of December 31, 2009 and September 30, 2010.

As of September 30, 2010, the Company had $156.0 million of outstanding borrowings under the Credit Facility. The Company pays commitment fees of up to 0.50% of the unused borrowing base. The Company also had approximately $18.1 million in outstanding letters of credit under the facility at September 30, 2010. Outstanding borrowings at December 31, 2009 were $142.1 million and $3.0 million of letters of credit.

(b) Senior Notes

On November 17, 2009, a newly formed wholly owned subsidiary of Antero Resources LLC, Antero Finance, issued $375.0 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, an additional $150.0 million of the same series of 9.375% senior notes were issued at a premium of $6.0 million. The notes are unsecured and subordinate to the Company’s bank credit facility to the extent of the value of the collateral securing the bank 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 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 from 104.688% on or after December 1, 2013 to 100% 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,

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Antero Finance may be required to offer to purchase notes from the holders. Proceeds from the issuance of the senior notes were used to retire $225.0 million of outstanding indebtedness under the second lien term notes payable and to pay down outstanding borrowings under the Credit Facility.

(5) Ownership Structure

At December 31, 2009 and September 30, 2010, the outstanding units in Antero Resources LLC are summarized as follows:

		Units
		authorized
		and issued
Class I units		103,466,666
Class A and B units		36,193,071
Class A and B profits units		19,726,873
		159,386,610

At September 30, 2010, 348,474 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 LLC 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, 2009 and September 30, 2010, the Class I units have an aggregate liquidation priority, including the special allocation of 8% per annum, of $1.45 billion and $1.54 billion, respectively.

During the nine months ended September 30, 2009, the Company issued $105 million of Series B preferred stock, which were exchanged for members’ units in Antero Resources LLC upon the reorganization.

(6) Financial Instruments

The carrying values of trade receivables, trade payables, the Credit Facility, and the term loan at December 31, 2009 and September 30, 2010 approximated market value. The carrying value of the bank

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

credit facility at December 31, 2009 and September 30, 2010 approximated fair value because the variable interest rates are reflective of current market conditions.

Based on Level 2 market data, the fair value of the Company’s senior notes was approximately $382.5 million and $557.8 million at December 31, 2009 and September 30, 2010, respectively.

(7) Asset Retirement Obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2010 (in thousands):

Asset retirement obligations — beginning of period	$	3,487
Obligations incurred	220
Accretion expense	227
Asset retirement obligations — end of period	$	3,934

(8) 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 nine months ended September 30, 2009 and 2010, 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 September 30, 2010, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, KeyBank, Barclays, Union Bank, and Credit Suisse accounted for approximately 47%, 26%, 12%, 3%, 6%, 3%, and 3%, respectively, of the net fair value of our commodity derivative assets position. The Company has no collateral from any counterparties. 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 September 30, 2010, there are no past due receivables from or payables to any of our counterparties.

Through September 30, 2010, the Company has entered into fixed price natural gas swaps in order to hedge a portion of its natural gas production from October 1, 2010 through December 31, 2014 as summarized in the following table. Hedge agreements referenced to the Centerpoint, NYMEX, and

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Transco Zone 4 indices are for production in the Arkoma Basin. Hedge agreements referenced to the CIG index are for production in the Piceance Basin. Hedge agreements referenced to the CGTAP index are for production from the Appalachian Basin.

		Weighted
		average
		index
	MMbtu/day	price
Three months ending December 31, 2010:
Centerpoint	30,000	$	7.53
CIG	30,000	5.47
NYMEX	10,000	6.65
CGTAP	40,000	5.91
Year ending December 31, 2011:
CIG	45,000	$	5.49
Transco zone 4	35,000	6.91
CGTAP	40,000	6.36
Year ending December 31, 2012:
CIG	35,000	$	6.06
Transco zone 4	35,000	7.05
CGTAP	50,000	6.18
Year ending December 31, 2013:
CIG	40,000	$	5.93
Transco zone 4	40,000	6.51
CGTAP	40,000	6.36
Year ending December 31, 2014:
CIG	40,000	$	6.07
Transco zone 4	20,000	6.51
CGTAP	60,000	6.39
Centerpoint	10,000	6.20

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

(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 second lien term loan and the bank credit facility. Under the swaps, the Company makes payments to the swap counterparty when the variable LIBOR three-month rate falls below the fixed rate or receives payments from the swap counterparty when the variable LIBOR three-month rate goes above the fixed rate. The outstanding swap agreements during the nine months ended September 30, 2009 and 2010 are summarized as follows:

		Covering
Notional amount of swap		periods	Fixed rate
$	225 million	May 2007 to July 1, 2011	4.11	%
$	150 million	April 1, 2008 to April 1, 2010	2.80
$	51 million	December 10, 2008 to December 10, 2009	2.79

When the Company retired the floating rate second lien term loan of $225 million out of the proceeds from the rate 9.375% senior notes in November 2009, it did not terminate the $225 million floating-to-fixed rate swap associated with this debt; therefore, this swap does not have debt associated with it.

The Company had a notional amount of $150.0 million of interest rate swaps outstanding related to the Credit Facility at December 31, 2009 and March 31, 2010. These swaps expired on April 1, 2010.

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

(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, 2009 and September 30, 2010.

	2009			2010
	Balance sheet			Balance sheet
	location	Fair value		location	Fair value
		(In			(In
		thousands)			thousands)

Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	22,105	Current assets	$	87,496
Commodity contracts	Long-term assets	18,989		Long-term assets	170,997

Total asset derivatives		$	41,094		$	258,493

Liability derivatives not designated as hedges for accounting purposes:
Interest rate contracts	Current liabilities	$	8,623	Current liabilities	$	6,312
Interest rate contracts	Long-term liabilities	2,464		Long-term liabilities	—

Total liability derivatives		$	11,087		$	6,312

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

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 nine months ended September 30, 2009 and 2010:

		Three months			Nine months		Three months		Nine months
	Statement of	ended			ended		ended		ended
	operations	September 30,			September 30,		September 30,		September 30,
	location	2009			2009		2010		2010

Realized gains on commodity contracts	Revenue	$	27,856		90,411		17,436		45,883
Unrealized gains (losses) on commodity contracts	Revenue	(44,293		)	(70,742	)	108,439		217,399

Total gains (losses) on commodity contracts		(16,437		)	19,669		125,875		263,282

Realized losses on interest rate contracts	Other expense	(3,145		)	(7,667	)	(2,057	)	(7,356	)
Unrealized gains on interest rate contracts	Other expense	1,114			3,811		1,302		4,776

Total losses on interest rate contracts		(2,031		)	(3,856	)	(755	)	(2,580	)

Net gains (losses) on derivative contracts		$	(18,468	)	15,813		125,120		260,702

The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at September 30, 2010:

	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
	(In thousands)
Derivatives asset (liability):
Fixed price commodity swaps	$	—	258,493		—	258,493
Interest rate swaps	—		(6,312	)	—	(6,312	)
	$	—	252,181		—	252,181

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

(9) Contingencies

Litigation

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

(10) Guarantor Subsidiaries

The following entities are guarantors of the Company’s senior notes at September 30, 2010: Antero Resources LLC (the Parent Company), Antero Arkoma, Antero Piceance, Antero Midstream, Antero Pipeline, and Antero Appalachian (collectively, the Guarantor Companies). Each of the guarantees is full and unconditional and joint and several. The nonguarantor company is Centrahoma Processing LLC. On November 5, 2010, Antero Midstream and its subsidiary, Centrahoma Processing LLC, were sold (see note 3) and Antero Midstream is no longer an obligor or guarantor of the Company’s senior notes or senior secured revolving credit facility.

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

The condensed consolidating financial statements below present the consolidating financial position, results of operations, and cash flows of Antero Resources LLC, its combined guarantor subsidiaries, and the nonguarantor company.

Condensed Consolidating Balance Sheet

December 31, 2009

	Parent		Guarantor		Nonguarantor
	company		companies		company	Elimination		Total
	(In thousands)

Assets

Cash and cash equivalents	$	—	9,090		1,579	—		10,669
Accounts receivable	—		23,795		12,102	—		35,897
Derivative instruments	—		22,105		—	—		22,105
Other current assets	—		35,218		599	(9,644	)	26,173

Total current assets	—		90,208		14,280	(9,644	)	94,844

Property and equipment, net	—		1,734,138		69,381	—		1,803,519
Derivative instruments	—		18,989		—	—		18,989
Other assets, net	—		17,673		1,541	—		19,214
Investment in subsidiaries	1,299,107		—		—	(1,299,107	)	—

Total assets	$	1,299,107	1,861,008		85,202	(1,308,751	)	1,936,566

Liabilities and Equity

Accounts payable and accrued expenses	$	—	72,168		866	—		73,034
Revenue distribution payable and advances from joint interest owners	—		30,704		—	—		30,704
Derivative instruments	—		8,623		—	—		8,623
Other current liabilities	—		(1,283	)	11,059	(9,644	)	132

Total current liabilities	—		110,212		11,925	(9,644	)	112,493

Long-term liabilities:
Bank credit facility and senior notes	—		514,477		—	—		514,477
Derivative instruments	—		2,464		—	—		2,464
Other long term liabilities	—		8,025		—	—		8,025

Total liabilities	—		635,178		11,925	(9,644	)	637,459

Total equity	1,299,107		1,225,830		73,277	(1,299,107	)	1,299,107

Total liabilities and equity	$	1,299,107	1,861,008		85,202	(1,308,751	)	1,936,566

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Consolidating Balance Sheet

September 30, 2010

	Parent		Guarantor	Nonguarantor
	company		companies	company	Elimination		Total
	(In thousands)

Assets

Cash and cash equivalents	$	—	—	—	—		—
Accounts receivable	—		22,636	—	—		22,636
Derivative instruments	—		87,496	—	—		87,496
Other current assets	—		37,311	—	—		37,311
Assets held for sale	—		75,976	84,318	—		160,294

Total current assets	—		223,419	84,318	—		307,737

Property and equipment, net	—		1,831,641	—	—		1,831,641
Derivative instruments	—		170,997	—	—		170,997
Other assets, net	—		16,202	—	—		16,202
Investment in subsidiaries	1,437,163		—	—	(1,437,163	)	—

Total assets	$	1,437,163	2,242,259	84,318	(1,437,163	)	2,326,577

Liabilities and Equity

Accounts payable and accrued expenses	$	—	112,389	—	—		112,389
Revenue distribution payable and advances from joint interest owners	—		21,851	—	—		21,851
Derivative instruments	—		6,312	—	—		6,312
Other current liabilities	—		152	—	—		152
Liabilities related to assets held for sale	—		5,949	13,282	—		19,231

Total current liabilities	—		146,653	13,282	—		159,935

Long-term liabilities:
Bank credit facility and senior notes	—		684,104	—	—		684,104
Derivative instruments	—		38,082	—	—		38,082
Other long term liabilities	—		7,293	—	—		7,293

Total liabilities	—		876,132	13,282	—		889,414

Total equity	1,437,163		1,366,127	71,036	(1,437,163	)	1,437,163

Total liabilities and equity	$	1,437,163	2,242,259	84,318	(1,437,163	)	2,326,577

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Combining Income Statement

Three months ended September 30, 2009

	Guarantor			Nonguarantor
	companies			company		Eliminations	Total
	(In thousands)

Revenues	$	17,722		2,578		1,144	21,444

Operating expenses:
Operating expenses	22,907			1,747		1,144	25,798
Depletion, depreciation, and amortization	33,719			1,086		—	34,805
General and administrative	5,000			122		—	5,122

Total operating expenses	61,626			2,955		1,144	65,725

Operating loss	(43,904		)	(377	)	—	(44,281	)

Interest and other expense, net	(9,215		)	—		—	(9,215	)

Loss before taxes	(53,119		)	(377	)	—	(53,496	)

Deferred income tax benefit	—			—		—	—

Net loss	(53,119		)	(377	)	—	(53,496	)

Noncontrolling interest in net loss of consolidated subsidiary	—			—		151	151

Net loss attributable to Antero members	$	(53,119	)	(377	)	151	(53,345	)

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Combining Income Statement

Nine months ended September 30, 2009

	Guarantor			Nonguarantor
	companies			company		Eliminations		Total
	(In thousands)

Revenues	$	130,687		6,524		(5,786	)	131,425

Operating expenses:
Operating expenses	72,692			4,276		(5,786	)	71,182
Depletion, depreciation, and amortization	105,750			3,237		—		108,987
General and administrative	14,038			358		—		14,396

Total operating expenses	192,480			7,871		(5,786	)	194,565

Operating loss	(61,793		)	(1,347	)	—		(63,140	)

Interest and other expense, net	(27,266		)	—		—		(27,266	)

Loss before taxes	(89,059		)	(1,347	)	—		(90,406	)

Deferred income tax benefit	3,029			—		—		3,029

Net loss	(86,030		)	(1,347	)	—		(87,377	)

Noncontrolling interest in net loss of consolidated subsidiary	—			—		539		539

Net loss attributable to Antero members	$	(86,030	)	(1,347	)	539		(86,838	)

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Combining Statement of Cash Flows

Nine months ended September 30, 2009

	Guarantor			Nonguarantor
	companies			company		Eliminations		Total
	(In thousands)

Net cash provided by operating activities	$	113,534		4,697		—		118,231
Net cash used in investing activities	(228,268		)	(2,883	)	1,149		(230,002	)
Net cash provided by financing activities	88,225			1,916		(1,149	)	88,992

Net increase (decrease) in cash and cash equivalents	(26,509		)	3,730		—		(22,779	)

Cash and cash equivalents, beginning of year	34,182			4,787		—		38,969

Cash and cash equivalents, end of year	$	7,673		8,517		—		16,190

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Consolidating Income Statement

Three months ended September 30, 2010

	Parent		Guarantor		Nonguarantor
	company		companies		company		Eliminations		Total
	(In thousands)

Revenues	$	—	183,742		2,233		(2,573	)	183,402

Operating expenses:
Operating expenses	—		35,528		1,278		(2,573	)	34,233
Depletion, depreciation, and amortization	—		34,880		1,006		—		35,886
General and administrative	—		5,249		47		—		5,296

Total operating expenses	—		75,657		2,331		(2,573	)	75,415

Operating income (loss)	—		108,085		(98	)	—		107,987

Interest and other expense, net	—		(15,281	)	—		—		(15,281	)
Equity in earnings of subsidiaries	67,780		—		—		(67,780	)	—

Income (loss) before taxes	67,780		92,804		(98	)	(67,780	)	92,706

Deferred income tax expense	—		(25,107	)	—		—		(25,107	)

Net income (loss)	67,780		67,697		(98	)	(67,780	)	67,599

Noncontrolling interest in net loss of consolidated subsidiary	—		—		—		181		181

Net income (loss) attributable to Antero members	$	67,780	67,697		(98	)	(67,599	)	67,780

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Consolidating Income Statement

Nine months ended September 30, 2010

	Parent		Guarantor		Nonguarantor
	company		companies		company	Eliminations		Total
	(In thousands)

Revenues	$	—	434,079		8,500	(8,025	)	434,554

Operating expenses:
Operating expenses	—		99,035		3,692	(8,025	)	94,702
Depletion, depreciation, and amortization	—		98,240		2,907	—		101,147
General and administrative	—		14,307		157	—		14,464

Total operating expenses	—		211,582		6,756	(8,025	)	210,313

Operating income	—		222,497		1,744	—		224,241
Interest and other expense, net	—		(44,363	)	—	—		(44,363	)
Equity in earnings of subsidiaries	138,979		—		—	(138,979	)	—

Income before taxes	138,979		178,134		1,744	(138,979	)	179,878

Deferred income tax expense	—		(39,287	)	—	—		(39,287	)

Net income	138,979		138,847		1,744	(138,979	)	140,591

Noncontrolling interest in net loss of consolidated subsidiary	—		—		—	(1,612	)	(1,612	)

Net income attributable to Antero members	$	138,979	138,847		1,744	(140,591	)	138,979

(Continued)

Table of Contents

ANTERO RESOURCES LLC

Notes to Consolidated Financial Statements

September 30, 2010 and December 31, 2009

(Unaudited)

Condensed Consolidating Statement of Cash Flows

Nine months ended September 30, 2010

	Parent		Guarantor		Nonguarantor
	company		companies		company		Eliminations		Total
	(In thousands)

Net cash provided by operating activities	$	—	99,044		7,467		—		106,511
Net cash used in investing activities	—		(274,287	)	(738	)	(3,762	)	(278,787	)
Net cash provided by (used in) financing activities	—		166,420		(6,269	)	3,762		163,913

Net increase (decrease) in cash and cash equivalents	—		(8,823	)	460		—		(8,363	)

Cash and cash equivalents, beginning of year	—		9,090		1,579		—		10,669
Cash classifed as held-for-sale	—		(2,306	)	—		—		(2,306	)

Cash and cash equivalents, end of year	$	—	(2,039	)	2,039		—		—

Table of Contents

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 Registration Statement on Form S-4 (Commission File No. 333-164876) filed on June 3, 2010 (the “Form S-4”). 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 natural gas and oil 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 “Risk Factors” in our Form S-4 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, which was formed to be the issuer of the $525 million principal amount of senior notes due 2017, is an indirect wholly owned subsidiary of Antero Resources LLC. In this section, references to “Antero,” “we,” “us,” “our” and “operating entities” refer to the five corporations that conduct Antero Resources LLC’s operations (Antero Resources Corporation, Antero Resources Midstream Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation), unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see note 1 of the consolidated financial statements included elsewhere in this report.

Overview

Antero is an independent oil and natural gas company engaged in the exploration, development and production of unconventional natural gas properties located onshore in the United States. We focus on 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. Our corporate headquarters are in Denver, Colorado. As of December 31, 2009, our estimated proved reserves were 1,140.7 Bcfe, consisting of 1,130.3 Bcf of natural gas and 1.7 MMBbl of oil and condensate. As of December 31, 2009, 99% of our proved reserves were natural gas, 24% were proved developed and 69% were operated by us. For the nine months ended September 30, 2010, we generated cash flow from operations, net income, and EBITDAX of $101.5 million, $139.0 million, and $145.3 million, respectively. A definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss) is included under “—Non-GAAP Financial Measure” below.

For the year ended December 31, 2009, we had capital expenditures of approximately $203.5 million, approximately 89% of which was allocated to low-risk development projects with the remaining capital budget allocated to infrastructure projects and land acquisition. Our capital expenditure budget for 2010 is approximately $381 million, 84% of which is allocated to drilling. Of our 2010 drilling budget, approximately 55% is allocated to the Appalachian Basin Marcellus Shale, 26% to the Arkoma Basin Woodford Shale and 19% to the Piceance Basin. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget based on liquidity, commodity prices and drilling results.

We believe we have a conservative financial position characterized by modest leverage, a strong hedge position and ample liquidity. As of September 30, 2010, we have entered into hedging contracts covering a total of approximately 189.1 Bcf of our natural gas production from October 1, 2010 through December 31, 2014 at a weighted average index price of $6.29 per Mcf. For the three months ending December 31, 2010, we have hedged approximately 10.1 Bcf of our production at a weighted average index price of $6.30 per Mcf. At September 30, 2010 we have a principal amount of $525 million 9.375% senior notes outstanding due 2017. At September 30, 2010, the borrowing base under our senior secured revolving credit facility was $400 million (the maximum amount available under the facility at that date). Subsequent to September 30, 2010, the borrowing base was increased to $550 million and the maximum amount available under the facility was increased to $1 billion.

We completed the sale of our Oklahoma midstream assets on November 5, 2010 for a sales price of $268 million, plus $2 million of working capital adjustments. The net proceeds from the sale were used to repay borrowings outstanding

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under our revolving credit facility and for general corporate purposes, including to fund our capital expenditure program. During the nine months ended September 30, 2010, we realized approximately $18 million of revenues and $1.2 of net income from these Oklahoma midstream assets.

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

Source of Our Revenues

Our production revenues are derived entirely from the continental United States and currently are comprised of approximately 95% natural gas and 5% oil and natural gas liquids. Natural gas and oil prices are inherently volatile and are influenced by many factors 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 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 nine months ended September 30, 2009 and 2010, we have 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.

· 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 payroll and benefits for the geological and geophysical staff, seismic costs, 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 impairments 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. Through September 30, 2010, 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. Because the economic life and total reserves for each producing well depends upon the assumed price for future sales, fluctuations in commodity prices used in reserve estimation may impact the level of proved reserves in the units of production calculation of depreciation and depletion expense. Additionally, changes in estimates of reserves, future development costs, or reclassifications of unproved properties to producing properties will impact depletion expense.

· General and administrative expense. These costs are comprised of 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 bank credit facilities. 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 at 9.375% on $525 million of principal amount of senior notes due 2017. We will likely continue to incur significant interest expense as we continue to grow. We have also entered into various variable to fixed interest rate swaps to mitigate the effects

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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).

· 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 starting in 2024 through 2029. 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 or estimates of future taxable income are reduced. We have recognized deferred tax expense for certain subsidiaries that have deferred tax liabilities in excess of their deferred tax assets due to unrealized gains on derivative instruments and basis differences in assets.

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Results of Operations

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2010

The following table sets forth selected operating data for the three months ended September 30, 2009 compared to the three months ended September 30, 2010:

	Three Months Ended September 30,						Amount of Increase			Percent
	2009			2010			(Decrease)			Change
	(in thousands, except per unit data)
Operating revenues:
Natural gas sales	$	30,008		$	49,870		$	19,862		66	%
Oil sales	1,664			1,684			20			1	%
Realized commodity derivative gains	27,856			17,436			(10,420		)	(37	)%
Unrealized commodity derivative gains (losses)	(44,293		)	108,439			152,732				*
Gathering and processing	6,209			5,973			(236		)	(4	)%
Total operating revenues	21,444			183,402			161,958			755	%
Operating expenses:
Lease operating expense	3,664			6,070			2,406			66	%
Gathering, compression and transportation	7,522			11,210			3,688			49	%
Production taxes	1,565			2,187			622			40	%
Exploration expense	3,094			3,644			550			18	%
Impairment of unproved properties	9,885			11,043			1,158			12	%
Depletion depreciation and amortization	34,805			35,886			1,081			3	%
Accretion of asset retirement obligations	68			79			11			16	%
General and administrative	5,122			5,296			174			3	%
Total operating expenses	65,725			75,515			9,690			15	%
Operating income (loss)	(44,281		)	107,987			152,268				*
Other income (expense):
Interest expense	(7,184		)	(14,526		)	(7,342		)	102	%
Realized interest rate derivative losses	(3,145		)	(2,056		)	1,089			(35	)%
Unrealized interest rate derivative gains	1,114			1,301			187			17	%
Total other expense	(9,215		)	(15,281		)	(6,066		)	66	%
Income (loss) before income taxes	(53,496		)	92,706			146,202				*
Deferred income tax (expense) benefit	—			(25,107		)	(25,107		)		*
Net income (loss)	(53,496		)	67,599			121,095				*
Non-controlling interest in net income of consolidated subsidiary	151			181			30			20	%
Net income (loss) attributable to Antero members	$	(53,345	)	$	67,780		$	121,245			*
Production data:
Natural gas (Bcf)	8.2			12.3			4.1			50	%
Oil (MBbl)	31.6			26.0			(5.6		)	(18	)%
NGLs (MBbl)(1)	113.8			110.2			(3.6		)	(3	)%
Combined (Bcfe)	9.1			13.2			4.1			45	%
Daily combined production (MMcfe/d)	98.8			143.1			44.3			45	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	3.65		$	4.04		$	0.39		11	%
Oil (per Bbl)	$	52.66		$	64.77		$	12.11		23	%
Combined (per Mcfe)	$	3.77		$	4.12		$	0.35		9	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	7.04		$	5.45		$	(1.59	)	(23	)%
Oil (per Bbl)	$	52.66		$	64.77		$	12.11		23	%
Combined (per Mcfe)	$	7.08		$	5.52		$	(1.56	)	(22	)%
Average Costs (per Mcfe):
Lease operating costs	$	0.44		$	0.49		$	0.05		11	%
Gathering, compression and transportation	$	0.89		$	0.90		$	0.01		1	%
Production taxes	$	0.19		$	0.17		$	(0.02	)	(11	)%
Depletion, depreciation amortization and accretion	$	4.14		$	2.88		$	(1.27	)	(31	)%
General and administrative	$	0.61		$	0.42		$	(0.19	)	(31	)%

(1) Represents NGLs retained by our midstream business as compensation for processing third-party gas under long term contracts. These amounts are not reflected in the per Mcfe data in this table.

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(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 production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

* Not meaningful or applicable

Natural gas and oil sales. Revenues from production of natural gas and oil increased from $31.7 million for the three months ended September 30, 2009 to $51.6 million for the three months ended September 30, 2010, an increase of $19.9 million or 63%. Our production, excluding NGLs retained by our midstream business, increased by 49% from 8.4 Bcfe for the three months ended September 30, 2009 to 12.5 Bcfe for the three months ended September 30, 2010 and prices increased by 9% before the effect of realized hedge gains. The net increase in revenues resulted from commodity price increases, which accounted for a $4.4 million increase (calculated as the increase in quarter-to-quarter average price times current year production volumes) in revenues, and by increased production volumes which increased revenues by $15.5 million (calculated as the increase in year-to-year volumes times the prior year average price).

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 September 30, 2009 and 2010, our hedges resulted in realized gains of $27.9 million and $17.4 million, respectively. For the three months ended September 30, 2009 and 2010, our hedges resulted in unrealized gains (losses) of $(44.3) million and $108.4 million, respectively. These unrealized gains at September 30, 2010 may reverse to the extent natural gas strip prices increase from their September 30, 2010 levels or as such gains are realized through settlement.

Gathering and processing revenues. Gathering and processing revenues decreased from $6.2 million for the three months ended September 30, 2009 to $6.0 million for the three months ended September 30, 2010 because of lower prices for natural gas liquids. On November 5, 2010, we completed the sale of our Oklahoma midstream assets; therefore, we anticipate future revenues from gathering and processing will be insignificant.

Lease operating expenses. Lease operating expenses increased from $3.7 million for the three months ended September 30, 2009 to $6.1 million for the three months ended September 30, 2010, an increase of 66%, primarily because of increased total production, workover expenses in the Piceance Basin, and the commencement of production in the Appalachian Basin. On a per unit basis, lease operating expenses increased in total from $0.44 per Mcfe for the three months ended September 30, 2009 to $0.49 for the three months ended September 30, 2010.

Gathering, compression and transportation. Gathering, compression and transportation expense increased from $7.5 million for the three months ended September 30, 2009 to $11.2 million for the three months ended September 30, 2010 primarily due to an increase in production volumes and more costly transportation. There was only a minor amount of production or gathering expense from Appalachia during the three months ended September 30, 2009; Appalachia wells on production under short-term transportation arrangements accounted for $1.8 million of the increase in gathering and transportation expenses for the three months ended September 30, 2010 compared to the three months ended September 30, 2009. On September 27, 2010, we began delivering most of our current Appalachian gas production under fixed long-term transportation contracts and, as a result, we expect future Appalachian Basin transportation expenses to decline compared to the Appalachian Basin transportation expenses with respect to the three months ended September 30, 2010. On a total per unit basis, these expenses remained relatively constant, increasing from $0.89 per Mcfe for the three months ended September 30, 2009 to $0.90 per Mcfe for the three months ended September 30, 2010.

Production taxes. Total production taxes increased from $1.6 million for the three months ended September 30, 2009 to $2.2 million for the three months ended September 30, 2010, primarily as a result of the increase in natural gas and oil prices and the commencement of production in the Appalachian Basin. Production taxes as a percentage of natural gas and oil revenues were 4.9% for the three months ended September 30, 2009 compared to 4.2% for the three months ended September 30, 2010. 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 production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

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Exploration expense. Exploration expense increased from $3.1 million for the three months ended September 30, 2009 to $3.6 million for the three months ended September 30, 2010. A decrease in standby rig and other costs of $2.1 million from the three months ended September 30, 2009 was offset by an increase in dry hole costs of $2.6 million.

Impairment of unproved properties. Our impairment of unproved property expense increased from $9.9 million for the three months ended September 30, 2009 to $11.0 million for the three months ended September 30, 2010. The increase in lease impairment costs was primarily driven by our belief that we will not renew or drill on certain leaseholds within non-core Ardmore and Arkoma Basin acreage which are expiring at various dates through September 30, 2011. 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 $34.8 million for three months ended September 30, 2009 to $35.9 million for the three months ended September 30, 2010, an increase of $1.1 million due to increased production and the commencement of production in the Appalachian Basin. DD&A per Mcfe decreased by 31% from $4.14 per Mcfe during the three months ended September 30, 2009 to $2.88 per Mcfe during the three months ended September 30, 2010, primarily as a result of increased reserves in 2010 and lower per Mcfe development costs across all of our basins.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the three months ended September 30, 2009 or 2010 for proved properties.

General and administrative. General and administrative expense increased slightly from $5.1 million for the three months ended September 30, 2009 to $5.3 million for the three months ended September 30, 2010. Increased costs of approximately $0.9 million for the three months ended September 30, 2010 compared to the three months ended September 30, 2009 related to salaries, employee benefits, contract personnel and professional services expenses were offset primarily by a reduction of franchise tax expense from the three months ended September 30, 2009. Increased salary and related expenses in 2010 were incurred for personnel required to execute our capital expenditure program. On a per unit basis, general and administrative expense decreased from $0.61 per Mcfe during the three months ended September 30, 2009 to $0.42 per Mcfe during the three months ended September 30, 2010 due to 45% production growth.

Interest expense and realized and unrealized gains and losses on interest rate derivatives. Interest expense increased from $7.2 million for the three months ended September 30, 2009 to $14.5 million during the three months ended September 30, 2010 due to increased interest costs resulting from the issuance of $525.0 million of 9.375% senior notes. In November 2009, we issued $375.0 million of 9.375% senior notes, and in January 2010, we issued an additional $150.0 million of the same series of 9.375% senior notes. The fixed interest rate on these senior notes is significantly higher than the variable rate we have been paying on our credit facility borrowings and on our second lien debt facility (which was repaid in full with the net proceeds of the November 2009 senior notes offering). As a result, interest expense in 2010 is higher than 2009 levels. Interest expense includes $0.9 million and $1.0 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2009 and 2010, respectively.

We have entered into various variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our senior secured revolving credit facility and second lien term loan facility. During the three months ended September 30, 2009, we had interest rate swaps outstanding for a notional amount of $426.0 million with fixed pay rates ranging from 2.79% to 4.11% and terms expiring from December 2009 through July 2011. During the three months ended September 30, 2010, we had one interest rate swap outstanding with a notional amount of $225 million which related to the $225 million second lien term loan facility which was repaid in November 2009. This swap expires in July 2011. During the three months ended September 30, 2010, we realized a loss on interest rate swap agreements of $2.1 million; whereas, during the three months ended September 30, 2009, we had a realized loss on interest rate swap agreements of $3.1 million. At September 30, 2010, the estimated fair value of our interest rate swap agreement was a liability of $6.3 million, which is included in current liabilities. As of September 30, 2010, we were in a liability position on the interest rate swap because of the large decline in interest rates since entering into the agreement. The amount of future gain or loss actually recognized on the swap is dependent upon future interest rates, which will affect the value of the swap.

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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 September 30, 2010, resulting from unrealized gains on commodity derivatives and basis differences in assets, resulting in the provision for deferred income taxes of $25.1 million during the three months ended September 30, 2010.

At December 31, 2009, the operating entities had a combined total of approximately $323 million of NOLs, which expire starting in 2024 and through 2029. Approximately $35 million of these NOLs related to Antero Midstream, which was sold on November 5, 2010. 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.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2010

The following table sets forth selected operating data for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2010:

	Nine Months Ended September 30,						Amount of Increase			Percent
	2009			2010			(Decrease)			Change
	(in thousands, except per unit data)
Operating revenues:
Natural gas sales	$	91,603		$	146,709		$	55,106		60	%
Oil sales	4,251			6,101			1,850			44	%
Realized commodity derivative gains	90,411			45,883			(44,528		)	(49	)%
Unrealized commodity derivative gains (losses)	(70,742		)	217,399			288,141				*
Gathering and processing	15,902			18,462			2,560			16	%
Total operating revenues	131,425			434,554			303,129			231	%
Operating expenses:
Lease operating expense	14,389			16,945			2,556			18	%
Gathering compression and transportation	19,183			32,108			12,925			67	%
Production taxes	4,393			6,789			2,396			55	%
Exploration expense	8,440			7,043			(1,397		)	(17	)%
Impairment of unproved properties	24,583			31,590			7,007			29	%
Depletion, depreciation and amortization	108,987			101,147			(7,840		)	(7	)%
Accretion of asset retirement obligations	194			227			33			17	%
General and administrative	14,396			14,464			68				*
Total operating expenses	194,565			210,313			15,748			8	%
Operating income (loss)	(63,140		)	224,241			287,381				*
Other income (expense):
Interest expense	(23,410		)	(41,783		)	18,373			78	%
Realized interest rate derivative losses	(7,667		)	(7,355		)	(312		)	(4	)%
Unrealized interest rate derivative gains	3,811			4,775			(964		)	25	%
Total other expense	(27,266		)	(44,363		)	17,097			63	%
Income (loss) before income taxes	(90,406		)	179,878			270,284				*
Deferred income tax (expense) benefit	3,029			(39,287		)	(42,316		)		*
Net income (loss)	(87,377		)	140,591			227,968				*
Non-controlling interest in net (loss) income of consolidated subsidiary	539			(1,612		)	(2,151		)		*
Net income (loss) attributable to Antero members	$	(86,838	)	$	138,979		$	225,817			*
Production data:
Natural gas (Bcf)	26.3			32.7			6.4			24	%
Oil (MBbl)	92.1			94.3			2.2			2	%
NGLs (MBbl)(1)	341.3			301.6			(39.7		)	(12	)%
Combined (Bcfe)	28.9			35.1			6.2			21	%
Daily combined production (MMcfe/d)	105.9			128.5			22.6			21	%
Average prices before effects of hedges (2):
Natural gas (per Mcf)	$	3.48		$	4.49		$	1.01		29	%
Oil (per Bbl)	$	46.16		$	64.70		$	18.54		40	%
Combined (per Mcfe)	$	3.57		$	4.59		$	1.02		29	%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	6.92		$	5.89		$	(1.03	)	(15	)%
Oil (per Bbl)	$	46.16		$	64.70		$	18.54		40	%
Combined (per Mcfe)	$	6.93		$	5.97		$	(0.96	)	(14	)%
Average Costs (per Mcfe):
Lease operating costs	$	0.54		$	0.51		$	(0.03	)	(6	)%
Gathering, compression and transportation	$	0.71		$	0.97		$	0.26		37	%
Production taxes	$	0.16		$	0.20		$	0.04		25	%
Depletion, depreciation, amortization and accretion	$	4.06		$	3.04		$	(1.02	)	(25	)%
General and administrative	$	0.54		$	0.43		$	(0.11	)	(20	)%

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(1) Represents NGLs retained by our midstream business as compensation for processing third-party gas under long term contracts. These amounts are not reflected in the per Mcfe data in this table.

* Not meaningful or applicable

Natural gas and oil sales. Revenues from production of natural gas and oil increased from $95.9 million for the nine months ended September 30, 2009 to $152.8 million for the nine months ended September 30, 2010, an increase of 59%. Our production, excluding NGLs retained by our midstream business, increased by 24% from 26.9 Bcfe for the nine months ended September 30, 2009 to 33.3 Bcfe for the nine months ended September 30, 2010 and prices increased by 29% before the effect of realized hedge gains. After the effect of realized hedge gains, our realized price per Mcfe decreased from $6.93 per Mcfe for the nine months ended September 30, 2009 to $5.97 per Mcfe for the nine months ended September 30, 2010. The net increase in realized oil and gas revenues resulted from price increases, which accounted for a $33.9 million increase in revenues (calculated as the increase in year-to-year average price times current year production volumes), and volume increases, which increased revenues by $23.0 million (calculated as the increase in year-to-year volumes times the prior year average price).

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 nine months ended September 30, 2009 and 2010, our hedges resulted in realized gains of $90.4 million and $45.9 million, respectively. For the nine months ended September 30, 2009 and 2010, our hedges resulted in unrealized gains (losses) of $(70.7) million and $217.4 million, respectively. Unrealized gains occurred as commodity prices at September 30, 2010 were below our fixed price swaps. These unrealized gains at September 30, 2010 may reverse to the extent natural gas strip prices increase from their September 30, 2010 levels or as such gains are realized through settlement.

Gathering and processing revenues. Gathering and processing revenues increased from $15.9 million for the nine months ended September 30, 2009 to $18.5 million for the nine months ended September 30, 2010 because of increased utilization in our gas processing plants and increases in prices received for natural gas liquids from the 2009 period in the first half of 2010. On November 5, 2010, we completed the sale of our Oklahoma midstream assets; therefore, we anticipate future revenues from gathering and processing will be insignificant.

Lease operating expenses. Lease operating expenses increased from $14.4 million during the nine months ended September 30, 2009 to $16.9 million during the nine months ended September 30, 2010 because of workover expenses in the Piceance Basin and the commencement of production in the Appalachian Basin in 2010. On a per unit basis, lease operating expenses decreased from $0.54 per Mcfe for the nine months ended September 30, 2009 to $0.51 per Mcfe for the nine months ended September 30, 2010. The decrease in per unit costs results from lower per unit expenses in the Appalachian Basin compared to the other basins in which we operate. Decreased water disposal costs in the Piceance Basin as a result of the completion of two water injection wells during the nine months ended September 30, 2009 were offset by increased workover expenses in the Piceance Basin during the nine months ended September 30, 2010.

Gathering, compression and transportation. Gathering, compression and transportation expense increased from $19.2 million for the nine months ended September 30, 2009 to $32.1 million for the nine months ended September 30, 2010 primarily due to a 24% increase in production and more costly transportation. There was no production or gathering expense for Appalachia during the nine months ended September 30, 2009; Appalachia wells on production in 2010 under short-term

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transportation arrangements accounted for $5.2 million of the increase in gathering and transportation expenses for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. On a per unit basis, these expenses increased from $0.71 per Mcfe for the nine months ended September 30, 2009 to $0.97 per Mcfe for the nine months ended September 30, 2010 primarily because of short-term transportation cost premiums in Appalachia and increased contractual transportation costs for Arkoma Woodford, Appalachian Basin and Piceance Basin production related to new firm transportation contracts. Increased Arkoma and Piceance transportation costs were partially offset by increased revenues due to better pricing received at new delivery points. On September 27, 2010, we began delivering most of our current Appalachian Basin gas production under fixed long-term transportation contracts and, as a result, we expect future Appalachian Basin transportation expenses to decline on a per Mcfe basis compared to transportation expenses in the nine months ended September 30, 2010.

Production taxes. Total production taxes increased from $4.4 million for the nine months ended September 30, 2009 to $6.8 million for the nine months ended September 30, 2010, primarily as a result of the increase in natural gas and oil prices and the commencement of production in the Appalachian Basin. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 4.6% for the nine months ended September 30, 2009 and 4.4% for the nine months ended September 30, 2010. 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 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 decreased from $8.4 million for the nine months ended September 30, 2009 to $7.0 million for the nine months ended September 30, 2010, primarily because of the elimination of standby rig costs of $5.0 million which was partially offset by an increase in dry hole and other exploration costs of $3.6 million.

Impairment of unproved properties. Our impairment of unproved property expense increased from $24.6 million for the nine months ended September 30, 2009 to $31.6 million for the nine months ended September 30, 2010. We had higher costs in the current year because of our belief that we will not renew or drill on certain leaseholds within our non-core Ardmore Basin acreage and certain non-core Arkoma Basin acreage. 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 decreased from $109.0 million for nine months ended September 30, 2009 to $101.1 million for the nine months ended September 30, 2010, a decrease of $7.9 million, despite a 24% increase in production. DD&A per Mcfe decreased by 25%, from $4.06 per Mcfe during the nine months ended September 30, 2009 to $3.04 per Mcfe during the nine months ended September 30, 2010, primarily as a result of increased proved developed reserve quantities in 2010 compared to 2009 and lower per unit development costs across all of our basins.

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. There were no impairment expenses recorded for the nine months ended September 30, 2009 or 2010 for proved properties.

General and administrative. General and administrative expenses increased slightly from $14.4 million for the nine months ended September 30, 2009 to $14.5 million for the nine months ended September 30, 2010. Increased costs of approximately $2.2 million for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 related to salaries, employee benefits, contract personnel and professional services expenses, which were offset by a reduction of non-cash stock compensation, legal expenses, bad debt expense, and franchise tax expense. Increased salary and related expenses in 2010 were incurred for personnel required to execute our capital expenditure program. On a per unit basis, general and administrative expense decreased from $0.54 per Mcfe during the nine months ended September 30, 2009 to $0.43 per Mcfe during the nine months ended September 30, 2010 due to production growth.

Interest expense and realized and unrealized gains and losses on interest rate derivatives. Interest expense increased from $23.4 million for the nine months ended September 30, 2009 to $41.8 million for the nine months ended September 30, 2010 due to increased interest costs resulting from the issuance of $375.0 million of 9.375% senior notes in November 2010 and $150.0 million of the same series of notes in January 2010. The fixed interest rate on these senior notes is significantly higher than the variable rate we have been paying on our credit facility borrowings and on our second lien debt facility (which was repaid in full with the net proceeds of the November 2009 senior notes offering). As a result, interest expense in 2010 is higher than 2009 levels. Interest expense includes $2.4 million and $3.1 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2009 and 2010, respectively.

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We have entered into various variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our senior secured revolving credit facility and second lien term loan facility. During 2009, we had interest rate swaps outstanding for a notional amount of $426.0 million with fixed pay rates ranging from 2.79% to 4.11% and terms expiring from December 2009 through July 2011. At September 30, 2010, we had one interest rate swap outstanding with a notional amount of $225.0 million which related to the $225.0 million second lien term loan facility which was repaid in November 2009. This swap expires in July 2011. During the nine months ended September 30, 2010, we realized a loss on interest rate swap agreements of $7.4 million; whereas, during the nine months ended September 30, 2009, we had a realized loss on interest rate swap agreements of $7.7 million. At September 30, 2010, the estimated fair value of our interest rate swap agreement was a liability of $6.3 million, which is included in current liabilities. As of September 30, 2010, we were in a liability position on the interest rate swap because of the large decline in interest rates since entering into the agreement. The amount of future gain or loss actually recognized on the swap is dependent upon future interest rates, which will affect the value of the swap.

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 have generated current taxable income in either the current or prior periods, 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 and other deferred tax assets exceed 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 sheets 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 September 30, 2010, resulting from unrealized gains on commodity derivatives and basis differences in assets, resulting in the provision of $39.3 million of deferred tax expense during the first nine months of 2010.

The tax benefit of $3.0 million for the nine months ended September 30, 2009 resulted from the reversal of previously recorded deferred tax liabilities as a result of operating losses incurred in the first nine months of 2009 by one of the operating entities.

Capital Resources and Liquidity

Our primary sources of liquidity have been through issuances of equity securities, borrowings under bank credit facilities, our senior notes, and net cash provided by operating activities. Our primary use of cash has been for the exploration, development and acquisition of 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 expenditure activities, and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.

In November 2009 and January 2010, we adjusted our capital structure by issuing $525 million of 9.375% senior notes due 2017 at a net premium of $3.4 million and raising approximately $125 million of additional equity. The proceeds of these issuances were used to repay in full our $225 million second lien term loan facility, which was due to mature in 2014, and to repay a portion of the borrowings outstanding under our senior secured revolving credit facility. At September 30, 2010, we had outstanding borrowings under the senior credit facility of $156.0 million and $18.1 million of outstanding letters of credit.

On November 4, 2010, we amended and restated our senior secured revolving credit facility to increase the borrowing base from $400 million to $550 million and to increase the maximum amount of the facility from $400 million to $1 billion. Additionally, on November 5, 2010, we closed the sale of our Oklahoma midstream assets for $268 million, plus $2 million of working capital adjustments, and used the net proceeds to paydown outstanding borrowings under our senior credit facility and for general corporate purposes, including to fund our capital expenditure program. We estimate that the combined effect of these two transactions is to increase our liquidity at November 5, 2010 by approximately $383 million. At November 5, 2010, we had $532 million of

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available borrowing capacity under our new credit facility, $18 million of outstanding letters of credit and $49 million of cash on hand, resulting in total liquidity of $581 million.

Our significant commodity hedge position provides us with additional liquidity as it provides us with the relative certainty of receiving a significant portion of our future expected cash flows from operations despite potential further declines in the price of natural gas. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. Over the last two years, dislocations in the credit markets, steep stock market declines, financial institution failures and government capital infusions reflected a weakened global economy and financing transactions have been difficult to complete as a result. Our current senior secured revolving credit facility is backed by a syndicate of 13 banks. We believe that our current syndicate of banks has the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of our credit facility.

We believe that funds from operating cash flows and available borrowings under our senior secured revolving credit facility should be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

For more information on our outstanding indebtedness, see “—Cash Flow Provided by Financing Activities.”

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $118.2 million and $106.5 million for the nine months ended September 30, 2009 and 2010, respectively. The decrease in cash flow from operations from the nine months ended September 30, 2009 to the nine months ended September 30, 2010 was primarily the result of increased gathering and transportation costs, increased 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 Disclosure About Market Risk” below.

Cash Flow Used in Investing Activities

During the nine months ended September 30, 2009 and 2010, we had cash flows used in investing activities of $230.0 million and $278.8 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 nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 was a result of higher levels of drilling activity. We expect that our cash used in investing activities for the remainder of 2010 will be at a similar quarterly rate based on our current capital budget and planned drilling activities.

Our capital budget for 2010 is approximately $381 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 nine months ended September 30, 2010 of $163.9 million was primarily the result of cash provided by the issuance of the senior notes having a principal amount of $150.0 million and a premium of $6 million, net borrowings on the senior secured revolving credit facility of $13.9 million, and $6.0 million used for other financing activities. Net cash provided by financing activities of $89.0 million during the nine months ended

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September 30, 2009, was primarily the result of the issuance of $105.0 million of Series B preferred stock, $10.0 million of net payments on the senior secured revolving credit facility, and $6.0 million used for other financing activities.

Senior Secured Revolving Credit Facility. On November 4, 2010, our senior secured revolving credit facility was amended and restated. The maturity date was extended from March 2012 to November 2015 and the borrowing base was increased from $400 million to $550 million. The maximum amount of the facility was increased from $400 million to $1 billion. Future borrowing bases will be computed based on proved natural gas and oil reserves and estimated future cash flow from these reserves and hedge positions, as well as any other outstanding indebtedness. The borrowing base is redetermined semiannually; the next redetermination is expected to occur in May 2011. As of September 30, 2010, we had borrowings outstanding under our senior secured revolving credit facility of $156.0 million and letters of credit outstanding of approximately $18.1 million. 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 senior revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requires us to maintain the following two financial ratios:

· a current ratio, which is the ratio of our consolidated current 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 leverage ratio, which is the ratio of our consolidated funded indebtedness (minus amounts of unsatisfied capital calls) as of the end of such fiscal quarter to our consolidated EBITDAX for the trailing four fiscal quarter period, of not greater than 4.25 to 1.0 until the fiscal quarter ending December 31, 2011 when the maximum leverage ratio will decrease to 4.0 to 1.0.

We were in compliance with such covenants and ratios as of December 31, 2009 and as of September 30, 2010.

As of December 31, 2009 and September 30, 2010, borrowings outstanding under our senior secured revolving credit facility totaled $142.1 million and $156.0 million, respectively, and had a weighted average interest rate (excluding the impact of our interest rate swaps) of 2.36% and 2.34%, respectively. At September 30, 2010, we also had $18.1 million of letters of credit outstanding under the senior secured revolving credit facility.

Interest Rate Hedges. We have entered into various variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our senior secured revolving credit facility and second lien term loan facility. At September 30, 2010, we had an interest rate swap outstanding for a notional amount of $225.0 million with a fixed pay rate of 4.11% with a term expiring in July 2011. During the nine months ended September 30, 2009 and 2010, we had realized losses on interest rate swap agreements of $7.7 million and $7.4 million, respectively. At September 30, 2010, we had unrealized losses on our interest rate swap agreement of $6.3 million. The amount of future gain or loss actually recognized on such swap is dependent upon future interest rates. See Item 3. “—Quantitative and Qualitative Disclosure About Market Risk—Interest Rate Risk and Hedges.” We did not terminate the interest rate swap related to the $225.0 million second lien term facility when the facility was retired in November 2009; therefore, this swap does not currently have debt associated with it.

Capital Leases. We lease certain compressors and computer equipment under agreements that are classified as capital leases having a balance of approximately $1.2 million and $1.5 million at December 31, 2009 and September 30, 2010, respectively. Capital leases at September 30, 2010 include $1.1 million of liabilities classified as liabilities related to assets held for sale.

Contractual Obligations. Our contractual obligations have not changed materially from those disclosed in our Form S-4 with the exception of the issuance of an additional $150.0 million of 9.375% senior notes in January 2010. The total of such senior notes outstanding at September 30, 2010 is $525 million with a maturity date of December 1, 2017. In addition, we have entered into contracts for the services of five drilling rigs. Commitments under these agreements are approximately $16.2 million as of the date of this report.

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

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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 senior secured revolving 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.

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 nine months ended September 30, 2009 and 2010:

	Nine Months Ended September 30,
	2009			2010
	(in thousands)
Net income (loss) attributable to Antero members	$	(86,838	)	$	138,979
Unrealized (gains) losses on derivative contracts	70,742			(217,399		)
Interest expense and other	27,266			44,363
Provision (benefit) for income taxes	(3,029		)	39,287
Depreciation, depletion, amortization and accretion	109,181			101,374
Impairment of unproved properties	24,583			31,590
Exploration expense	8,440			7,043
Other	1,663			110
EBITDAX	$	152,008		$	145,347

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for oil and gas production activities, estimates of natural gas and oil reserve quantities and standardized measures of future cash flows, and impairment of unproved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in the Form S-4. We believe these accounting policies reflect our more significant estimates and assumptions used

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in preparation of our consolidated financial statements. Also, see Note 2 of the notes to our audited consolidated financial statements, included in the Form S-4 for a discussion of additional accounting policies and estimates made by management.

New Accounting Pronouncement

Revised Natural Gas and Oil Standard

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting, or Modernization. The Modernization disclosure requirements require reporting of natural gas and oil reserves using an average price based upon the prior 12 month period rather than year end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Companies are also allowed to disclose probable and possible reserves to investors in SEC filed documents. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditors and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements became effective for the year ending December 31, 2009. The FASB has issued Accounting Standards Update 2010-03 (ASU 2010-03) “Extractive Industries—Oil and Gas” to align its rules for oil and gas reserve estimation and disclosure requirements with the SEC’s final rule. In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), which revises portions of the interpretive guidance included in the section of the Staff Accounting Bulletin Series titled Topic 12: Oil and Gas Producing Activities. The principal changes involve revisions to bring Topic 12 into conformity with the contents of the Modernization. We adopted the Modernization standard in the preparation of our December 31, 2009 (and subsequent) reserve estimates and related disclosures.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements other than operating leases.

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 received 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) 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.

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At December 31, 2009 and September 30, 2010, we had in place natural gas swaps covering portions of production from 2010 through 2014. Our senior secured revolving credit facility allows us to hedge up to 85% of our estimated production from proved reserves for up to 12 months in the future, 75% for 13 to 24 months in the future, 65% for 25 to 36 months in the future, 55% for 37 to 48 months in the future and 45% for 49 to 60 months in the future. Based on our production for the nine months ended September 30, 2010 and our fixed price swap contracts in place during that period, our income before taxes for the nine months ended September 30, 2010 would have decreased by approximately $0.6 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $90,000 for each $1.00 per barrel decrease in crude 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, 2009, the estimated fair value of our commodity derivative instruments was a net asset of $41.1 million comprised of current and noncurrent assets. At September 30, 2010, the estimated fair value of our commodity derivative instruments was a net asset of $258.5 million comprised of current and noncurrent assets.

As of September 30, 2010, we have entered into fixed price natural gas swaps in order to hedge a portion of our natural gas production from 2010 through 2014 as summarized in note 8 to our consolidated financial statements included elsewhere in this report.

By removing price volatility from a portion of our expected natural gas production through December 2014, 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 seven different counterparties, all of which are lenders in our senior secured revolving credit facility. As of September 30, 2010, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, KeyBank, Barclays, Union Bank, and CreditSuisse accounted for approximately 47%, 26%, 12%, 3%, 6%, 3%, and 3%, respectively, of the net fair value of our commodity derivative assets position. We believe all of these institutions currently are acceptable credit risks. 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 September 30, 2010, we have no past due receivables from or payables to any of our counterparties.

Interest Rate Risks and Hedges

During the nine months ended September 30, 2010, we had indebtedness outstanding under our $400 million senior secured revolving credit facility, which has a floating interest rate. The average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2010, was approximately 2.6%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2010, would have resulted in an estimated $550,000 increase in interest expense for the nine months ended September 30, 2010 before giving effect to interest rate swaps. During the nine months ended September 30, 2010, our indebtedness consisted primarily of fixed rate 9.375% senior notes due 2017 having an outstanding principal amount of $525 million.

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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 September 30, 2010.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended September 30, 2010 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.

We are party to various legal proceedings and claims in the ordinary course of its business. We believe 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. For a discussion of certain legal matters in which we are involved, see “Business—Legal Matters” in our Registration Statement on Form S-4 (Commission File No. 333-164876) filed with the SEC on June 3, 2010 (the “Form S-4”). There have been no material changes to the legal matters described in the Form S-4.

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 “Risk Factors” in the Form S-4 and under Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “June 30, 2010 Form 10-Q”). The risks described in the Form S-4 and the June 30, 2010 Form 10-Q could materially and adversely affect our business, financial condition, cash flows, and results of operations. There have been no material changes to the risks described in the Form S-4 and the June 30, 2010 Form 10-Q. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

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

There were no sales of unregistered equity securities during the period covered by this report.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. (Removed and Reserved.)

Item 5. Other Information.

Not applicable.

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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		Limited Liability Company Agreement of Antero Resources LLC dated as of November 3, 2009. (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 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		Purchase and Sale Agreement by and among Antero Resources LLC, Antero Resources Midstream Corporation and Cardinal Arkoma Midstream, LLC, dated as of October 1, 2010 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on October 4, 2010).
4.6		Stock Purchase Agreement by and between Antero Resources LLC and Cardinal Arkoma, Inc., dated as of October 1, 2010 (incorporated by reference to Exhibit 2.2 to Current Report on Form 8-K (Commission File No. 333-164876) filed on October 4, 2010).
10.1		Fourth Amended And Restated Credit Agreement dated as of November 4, 2010 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, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, Bank of Scotland Plc, Union Bank, N.A., Credit Agricole Corporate and Investment Bank, BNP Paribas and Deutsche Bank Trust Company Americas, as Co- Documentation Agents and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 8, 2010).
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).

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: November 12, 2010	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 - FORM 10-Q - November 12, 2010

Attached files

Antero Resources Finance Corp Reports