UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

OR

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

For the transition period from                    to                    

Commission file number: 333-164876-06

ANTERO RESOURCES LLC

(Exact name of registrant as specified in its charter)

Delaware	90-0522242
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

1625 17th Street Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
(Do not check if a smaller reporting company)

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

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		i
PART I - FINANCIAL INFORMATION		1
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	30
Item 4.	Controls and Procedures	32
PART II—OTHER INFORMATION		32
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 6.	Exhibits	32
SIGNATURES		33

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Form 10-Q”) 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 Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements.  When used, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.  These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.  These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

·business strategy;

·reserves;

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

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

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

·hedging strategy and results;

·future drilling plans;

·competition and government regulations;

·pending legal or environmental matters;

·marketing of natural gas, NGLs, and oil;

·leasehold or business acquisitions and dispositions;

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

·general economic conditions;

·credit markets;

·uncertainty regarding our future operating results; and

·plans, objectives, expectations and intentions contained in this Form 10-Q that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs, and oil.  These risks include, but are not limited to, low commodity prices and commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A.  Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”) on file with the Securities and Exchange Commission (Commission File No. 333-164876-06) and in “Item 1A. Risk Factors” of this Form 10-Q.

i

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 our 2011 Form 10-K, in this Form 10-Q or in our subsequent filings occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, express or implied, included in this Form 10-Q are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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

ii

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

ANTERO RESOURCES LLC

Condensed Consolidated Balance Sheets

December 31, 2011 and September 30, 2012

(Unaudited)

(In thousands)

	2011			2012
Assets
Current assets:
Cash and cash equivalents	$	3,343		16,555
Accounts receivable, net of allowance for doubtful accounts of $182 and $174 in 2011 and 2012, respectively	25,117			39,487
Notes receivable - short-term portion	7,000			6,222
Accrued revenue	35,986			18,609
Derivative instruments	248,550			172,123
Other	13,646			13,860
Total current assets	333,642			266,856
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties	834,255			1,134,725
Producing properties	2,497,306			2,196,746
Gathering systems and facilities	142,241			133,411
Other property and equipment	8,314			11,100
	3,482,116			3,475,982
Less accumulated depletion, depreciation, and amortization	(601,702		)	(391,227	)
Property and equipment, net	2,880,414			3,084,755
Derivative instruments	541,423			386,957
Notes receivable - long-term portion	5,111			2,667
Other assets, net	28,210			25,034
Total assets	$	3,788,800		3,766,269
Liabilities and Equity
Current liabilities:
Accounts payable	$	107,027		176,888
Accrued liabilities	35,011			42,867
Revenue distributions payable	34,768			34,748
Advances from joint interest owners	2,944			113
Current income tax liability	—			15,000
Deferred income tax liability	75,308			62,739
Total current liabilities	255,058			332,355
Long-term liabilities:
Long-term debt	1,317,330			1,399,091
Deferred income tax liability	245,327			341,506
Other long-term liabilities	12,279			12,545
Total liabilities	1,829,994			2,085,497
Equity:
Members’ equity	1,460,947			1,460,947
Accumulated earnings	497,859			219,825
Total equity	1,958,806			1,680,772
Total liabilities and equity	$	3,788,800		3,766,269

See accompanying notes to consolidated financial statements.

1

ANTERO RESOURCES LLC

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended September 30, 2011 and 2012

(Unaudited)

(In thousands)

	2011			2012
Revenue:
Natural gas sales	$	71,836		77,212
Natural gas liquids sales	5,886			6,357
Oil sales	4,775			6,202
Realized and unrealized gain (loss) on commodity derivative instruments (including unrealized gains (losses) of $124,567 and $(236,536) in 2011 and 2012, respectively)	141,114			(177,884	)
Loss on sale of gathering system	—			(115	)
Total revenue	223,611			(88,228	)
Operating expenses:
Lease operating expenses	6,087			3,943
Gathering, compression and transportation	15,439			32,976
Production taxes	5,473			5,397
Exploration expenses	968			3,251
Impairment of unproved properties	4,652			2,407
Depletion, depreciation and amortization	29,117			41,055
Accretion of asset retirement obligations	86			116
General and administrative	7,404			11,938
Total operating expenses	69,226			101,083
Operating income (loss)	154,385			(189,311	)
Interest expense	(20,608		)	(22,453	)
Income (loss) from continuing operations before income taxes and discontinued operations	133,777			(211,764	)
Income tax (expense) benefit	(49,578		)	84,086
Income (loss) from continuing operations	84,199			(127,678	)
Discontinued operations:
Income from results of operations and sale of discontinued operations	26,879			—
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	111,078		(127,678	)

See accompanying notes to consolidated financial statements.

2

ANTERO RESOURCES LLC

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2011 and 2012

(Unaudited)

(In thousands)

	2011			2012
Revenue:
Natural gas sales	$	168,797		184,493
Natural gas liquids sales	14,224			21,602
Oil sales	9,224			19,527
Realized and unrealized gain on commodity derivative instruments (including unrealized gains (losses) of $151,520 and $(111,649) in 2011 and 2012, respectively)	199,802			75,912
Gain on sale of gathering system	—			291,190
Total revenue	392,047			592,724
Operating expenses:
Lease operating expenses	17,487			16,123
Gathering, compression and transportation	37,331			78,888
Production taxes	12,141			15,191
Exploration expenses	5,902			8,150
Impairment of unproved properties	6,828			4,572
Depletion, depreciation and amortization	67,865			106,733
Accretion of asset retirement obligations	242			325
General and administrative	21,972			31,584
Loss on sale of assets	8,700			—
Total operating expenses	178,468			261,566
Operating income	213,579			331,158
Other expense:
Interest expense	(51,268		)	(71,046	)
Realized and unrealized losses on interest derivative instruments, net (including unrealized gains of $4,212 in 2011)	(94		)	—
Total other expense	(51,362		)	(71,046	)
Income from continuing operations before income taxes and discontinued operations	162,217			260,112
Income tax expense	(74,941		)	(112,610	)
Income from continuing operations	87,276			147,502
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations	39,490			(425,536	)
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	126,766		(278,034	)

See accompanying notes to consolidated financial statements.

3

ANTERO RESOURCES LLC

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2011 and 2012

Unaudited

(In thousands)

	2011			2012
Cash flows from operating activities:
Net income (loss)	$	126,766		(278,034	)
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	68,107			107,058
Impairment of unproved properties	6,828			4,572
Unrealized gains (losses) on derivative instruments, net	(151,520		)	111,649
Loss on sale of discontinued operations	—			427,232
Loss (gain) on sale of assets	8,700			(291,190	)
Depletion, depreciation, amortization, accretion and impairment of unproved properties - discontinued operations	50,580			36,365
Unrealized losses on derivative instruments, net - discontinued operations	(9,224		)	11,025
Deferred taxes	74,941			83,610
Other	1,561			3,603
Changes in current assets and liabilities:
Accounts receivable	3,736			(16,811	)
Accrued revenue	(11,840		)	17,378
Other current assets	957			(3,112	)
Accounts payable	(4,505		)	(9,812	)
Accrued liabilities	21,292			7,281
Revenue distributions payable	10,420			2,369
Advances from joint interest owners	1,647			(2,783	)
Current income taxes payable	—			15,000
Net cash provided by operating activities	198,446			225,400
Cash flows from investing activities:
Additions to proved properties	(105,405		)	(4,451	)
Additions to unproved properties	(145,200		)	(428,574	)
Drilling costs	(383,958		)	(619,344	)
Additions to gathering systems and facilities	(63,110		)	(58,748	)
Additions to other property and equipment	(2,083		)	(2,786	)
Proceeds from asset sales	15,379			816,167
Changes in other assets	(3,105		)	2,556
Net cash used in investing activities	(687,482		)	(295,180	)
Cash flows from financing activities:
Issuance of senior notes	400,000			—
Borrowings on bank credit facility, net	120,000			82,000
Payments of deferred financing costs	(6,800		)	—
Distribution to members	(28,858		)	—
Other	(114		)	992
Net cash provided by financing activities	484,228			82,992
Net increase (decrease) in cash and cash equivalents	(4,808		)	13,212
Cash and cash equivalents, beginning of period	8,988			3,343
Cash and cash equivalents, end of period	$	4,180		16,555
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(39,930	)	(61,930	)
Supplemental disclosure of noncash investing activities:
Increase in accounts payable for additions to properties, gathering systems and facilities	$	6,235		73,430

See accompanying notes to consolidated financial statements.

4

ANTERO RESOURCES LLC

Notes to Condensed Consolidated Financial Statements

December 31, 2011 and September 30, 2012

(1)Business and Organization

Antero Resources LLC, a limited liability company, and its consolidated operating 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, Ohio and Pennsylvania and the Piceance Basin in Colorado. We also have midstream gathering and pipeline operations that 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, 2012 include the accounts of Antero Resources LLC, and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Corporation (Antero Arkoma), Antero Resources Piceance Corporation (Antero Piceance), Antero Resources Pipeline Corporation (Antero Pipeline), Antero Resources Appalachian Corporation and its subsidiary, Antero Resources Bluestone LLC (Antero Appalachian), and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities).  See Note 2 (g) for information regarding the reorganization of the Company’s legal structure which occurred on October 17, 2012.

(2)Basis of Presentation and Significant Accounting Policies

(a)Basis of Presentation

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the SEC) applicable to interim financial information and should be read in the context of the December 31, 2011 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2011 consolidated financial statements have been filed with the SEC in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.

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, 2012, the results of its operations for the three and nine months ended September 30, 2011 and 2012, and its cash flows for the nine months ended September 30, 2011 and 2012.  We have no items of other comprehensive income or loss; therefore, our net income (loss) is identical to our comprehensive income (loss).  All significant intercompany accounts and transactions have been eliminated. Operating results for the period ended September 30, 2012 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results, and other factors.

The Company’s exploration and production activities are accounted for under the successful efforts method. As of the date these financial statements were filed with the Securities and Exchange Commission, the Company completed its evaluation of potential subsequent events for disclosure and no items requiring disclosure were identified, other than the matter discussed in note 11.

5

(b)Use of Estimates

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

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

(c)Risks and Uncertainties

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

(d)Cash and Cash Equivalents

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

(e)Derivative Financial Instruments

In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. From time to time, the Company also enters into derivative contracts to mitigate the effects of interest rate fluctuations. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The fair value of our commodity derivative contracts of approximately $559 million at September 30, 2012 includes the following values by bank counterparty:  BNP Paribas - $164 million; Credit Suisse - $133 million; Wells Fargo - $92 million; JP Morgan - $67 million; Credit Agricole - $45 million; Barclays - $40 million; Deutsche Bank - $8 million; and Union Bank  — $2 million.  Additionally, contracts with Dominion Field Services account for $8 million of the fair value. The credit ratings of certain of these banks were downgraded in 2011 because of the sovereign debt crisis in Europe.  The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2012 for each of the European and American banks.  We believe that all of these institutions currently are acceptable credit risks.

The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues, and changes in the fair value of interest rate derivatives are classified as other income (expense).

6

(f)Fair Value Measurements

Authoritative accounting guidance defines fair value, establishes a framework for measuring fair value, and requires disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is 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 non-exchange traded derivatives, such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. The Company utilizes its counterparties to assess the reasonableness of its prices and valuation techniques. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.

(g)Income Taxes

For each tax year-end through December 31, 2011, Antero Resources LLC and each of its subsidiaries filed 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. On October 17, 2012, the Company completed a reorganization of its legal structure by contributing all of the outstanding shares owned by Antero Resources LLC in each of the Antero Arkoma, Antero Piceance, and Antero Pipeline corporations to Antero Appalachian.  Antero Arkoma, Antero Piceance and Antero Pipeline were then converted to limited liability companies.

The Company and its subsidiaries have combined net operating loss carryforwards (NOLs) as of December 31, 2011 of approximately $937 million. The Company’s deferred tax assets relate primarily to NOLs and its deferred tax liabilities relate primarily to oil and gas properties and unrealized gains on derivative instruments. In assessing the ability to realize 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.  As a result of the reorganization of the Company’s legal structure on October 17, 2012, during the fourth quarter, the Company expects to recognize benefits from certain NOLs for which valuation allowances have previously been provided.  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 35% to consolidated income for the three month and nine month periods ended September 30, 2011 and 2012 primarily because of state income taxes.

7

(h)Impairment of Unproved Properties

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

Impairment of unproved properties during the nine months ended September 30, 2011 and 2012 was $6.8 million and $4.6 million, respectively.

(i)Industry Segment and Geographic Information

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

(3)           Sale of Arkoma Properties - Discontinued Operations

Effective June 29, 2012 the Company completed its sale of its Arkoma Basin assets and the commodity hedges associated with the Arkoma assets.  Proceeds from the sale of $435 million represent the purchase price of $445 million adjusted for expenses of the sale and estimated income, expenses, and capital costs from the effective date of the sale through the closing date of June 29, 2012 (the “interim period”).  The purchase price is subject to adjustment for a final settlement to be conducted within 180 days from June 29, 2012 for actual income and costs for the interim period.

Results of operations and the loss on the sale of the assets are shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) and are comprised of the following:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011			2012	2011	2012
Sales of oil, natural gas, and natural gas liquids	$	26,851		—	83,633	36,702
Realized gains on commodity derivative instruments	8,682			—	25,505	33,681
Unrealized gains (losses) on commodity derivative instruments	15,628			—	9,224	(11,025	)
Total revenues	51,161			—	118,362	59,358
Lease operating expenses	1,485			—	5,069	4,344
Gathering, compression, and transportation	7,076			—	22,141	16,267
Production taxes	(123		)	—	446	417
Exploration expenses	137			—	636	269
Impairment of unproved properties	182			—	1,106	409
Depletion, depreciation, and amortization	15,500			—	49,400	35,900
Accretion of asset retirement obligations	25			—	74	56
Loss on sale of assets	—			—	—	427,232
Total expenses	24,282			—	78,872	484,894
Income (loss) from discontinued operations and sale of discontinued operations	$	26,879		—	39,490	(425,536	)

8

(4)Long-term Debt

Long-term debt consisted of the following at December 31, 2011 and September 30, 2012 (in thousands):

	December 31,		September 30,
	2011		2012
Bank credit facility (a)	$	365,000	447,000
9.375% senior notes due 2017 (b)	525,000		525,000
7.25% senior notes due 2019 (c)	400,000		400,000
9.0% senior note (d)	25,000		25,000
Net premium/discount	2,330		2,091
Total	$	1,317,330	1,399,091

(a)Bank Credit Facility

The Company has a $2.5 billion senior secured revolving bank credit facility (the Credit Facility) with a consortium of bank lenders. As amended on October 25, 2012, the borrowing base is $1.65 billion and lender commitments are $950 million. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved properties and hedge positions and are subject to regular semiannual redeterminations.  The maturity date of the Credit Facility is May 12, 2016.

The Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. 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.  Commitment fees on the unused portion of the Credit Facility are due quarterly at rates from 0.375% to 0.50% on the unused amounts of the facility.  The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. The Company was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2011 and September 30, 2012.

As of September 30, 2012, the Company had an outstanding balance under the Credit Facility of $447 million, with a weighted average interest rate of 2.00%, and outstanding letters of credit of approximately $43 million. As of December 31, 2011, the Company had an outstanding balance under the Credit Facility of $365 million, with a weighted average interest rate of 2.12%, and outstanding letters of credit of approximately $21 million.

(b)9.375% Senior Notes

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 (the “2017 notes”) at a discount of $2.6 million. In January 2010, Antero Finance issued an additional $150 million of the same series of 2017 notes at a premium of $6 million. The 2017 notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2017 notes are guaranteed on a full and unconditional basis and joint and severally by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the 2017 notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part of the 2017 notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate

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principal amount of the 2017 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 2017 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2017 notes plus a “make-whole” premium. If Antero Resources LLC undergoes a change of control (as defined in indenture governing the 2017 notes), Antero Finance may be required to offer to purchase the 2017 notes from the holders. Antero Resources LLC, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

(c)7.25% Senior Notes

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par (the “2019 notes”). The 2019 notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2019 notes rank pari passu to the 2017 notes. The 2019 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 2019 notes is payable on August 1 and February 1 of each year, commencing on February 1, 2012. Antero Finance may redeem all or part of the 2019 notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017. In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the 2019 notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the 2019 notes, plus accrued interest. At any time prior to August 1, 2014, Antero Finance may redeem the 2019 notes, in whole or in part, at a price equal to 100% of the principal amount of the 2019 notes plus a “make-whole” premium and accrued interest. If a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2013, Antero Finance may, at its option, redeem all, but not less than all, of the 2019 notes at a redemption price equal to 110% of the principal amount of the 2019 notes, plus accrued interest. If Antero Finance has not exercised its optional redemption rights upon a change of control, the 2019 note holders will have the right to require Antero Finance to repurchase all or a portion of the 2019 notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

(d)9.00% Senior Note

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

(e)Treasury Management Facility

The Company has a stand-alone revolving note with a lender under the Credit Facility which provides for up to $25 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the Credit Facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2013. There were no borrowings outstanding under this facility at December 31, 2011 or September 30, 2012.

(5)Ownership Structure

At December 31, 2011 and September 30, 2012, the outstanding units in Antero Resources LLC are summarized as follows:

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

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

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

At December 31, 2011 and September 30, 2012, the Class I units have an aggregate liquidation priority, including the special allocation of 8% per annum, of $2.024 billion and $2.148 billion, respectively.

In February 2011, the Company distributed $28.5 million to its members to cover their tax liabilities resulting from the sale of the Company’s Oklahoma midstream assets during the fourth quarter of 2010.

(6)Financial Instruments

The carrying values of trade receivables, trade payables, and the Credit Facility at December 31, 2011 and September 30, 2012 approximated market value. The carrying value of the Credit Facility at December 31, 2011 and September 30, 2012 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 $977 million and $1.0 billion at December 31, 2011 and September 30, 2012, respectively.

(7)Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the nine months ended September 30, 2012 (in thousands):

Asset retirement obligations — beginning of period	$	6,715
Obligations incurred	859
Accretion expense	381
Sale of Arkoma assets	(1,379		)
Asset retirement obligations — end of period	$	6,576

(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, 2011 and 2012, 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

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Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

The Company has no collateral from any counterparties. All but one of our commodity 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, 2012, there are no past due receivables from or payables to any of our counterparties.

As of September 30, 2012, the Company’s positions in fixed price natural gas and oil swaps from October 1, 2012 through December 31, 2017 are summarized in the following table.  Hedge agreements referenced to the CIG and NYMEX-WTI indices are for production in the Piceance Basin. Hedge agreements referenced to the CGTAP, CGLA, and Dominion South indices are for production from the Appalachian Basin.

			Weighted
			average
	Natural gas	Oil	index
	MMbtu/day	Bbls/day	price
Three months ending December 31, 2012:
CIG	55,000		$	5.65
CGTAP	155,526		5.24
Dominion South	52,840		5.46
NYMEX-WTI		300	90.20
2012 Total	263,366	300
Year ending December 31, 2013:
CIG	60,000		$	5.54
CGTAP	122,631		5.02
Dominion South	191,702		4.77
NYMEX-WTI		300	90.30
2013 Total	374,333	300
Year ending December 31, 2014:
CIG	50,000		$	5.84
CGTAP	200,000		5.16
Dominion South	160,000		5.15
CGLA	10,000		3.87
2014 Total	420,000
Year ending December 31, 2015:
CIG	60,000		$	5.29
CGTAP	120,000		5.01
Dominion South	230,000		5.60
CGLA	40,000		4.00
2015 Total	450,000
Year ending December 31, 2016:
CIG	30,000		$	4.88
CGTAP	60,000		4.91
Dominion South	272,500		5.35
CGLA	170,000		4.09
2016 Total	532,500
Year ending December 31, 2017
CGLA	420,000		4.27

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(b)Interest Rate Derivatives

Historically, 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 swaps, the Company made payments to the swap counterparty when the variable LIBOR three-month rate fell below the fixed rate or received payments from the swap counterparty when the variable LIBOR three-month rate went above the fixed rate. The Company had no outstanding interest rate swap agreements at December 31, 2011 or September 30, 2012.

(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, 2011 and September 30, 2012.

		Fair value
				September
	Balance sheet	December 31,		30,
	location	2011		2012
	(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	248,550	172,123
Commodity contracts	Long-term assets	541,423		386,957
Total asset derivatives		$	789,973	559,080

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, 2011 and 2012:

		Three		Three		Nine		Nine
		months		months		months		months
	Statement	Ended		Ended		Ended		Ended
	of operations	September 30,		September 30,		September 30,		September 30,
	location	2011		2012		2011		2012
Realized gains on commodity contracts	Revenue	$	16,547	58,652		48,282		187,561
Unrealized gains (losses) on commodity contracts	Revenue	124,567		(236,536	)	151,520		(111,649	)
Realized gains on commodity contracts	Discontinued operations	8,682		—		25,505		33,681
Unrealized gains (losses) on commodity contracts	Discontinued operations	15,628		—		9,224		(11,025	)
Total gains (losses) on commodity contracts		165,424		(177,884	)	234,531		98,568
Realized losses on interest rate contracts	Other income (expense)			—		(4,306	)	—
Unrealized gains on interest rate contracts	Other income (expense)			—		4,212		—
Total net losses on interest rate contracts		—		—		(94	)	—
Net gains (losses) on derivative contracts		$	165,424	(177,884	)	234,437		98,568

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The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at September 30,2012:

	Fair value measurements using
	Quoted
	prices
	in active		Significant
	markets for		other	Significant
	identical		observable	unobservable
	assets		inputs	inputs
Description	(Level 1)		(Level 2)	(Level 3)	Total
Derivatives asset:
Fixed price commodity swaps	$	—	559,080	—	559,080

(9)Sale of Appalachian Gathering Assets

On March 26, 2012, the Company closed the previously announced sale of a portion of its Marcellus Shale gathering system assets along with exclusive rights to gather the Company’s gas for a 20-year period within an area of dedication (AOD) to a joint venture owned by Crestwood Midstream Partners and Crestwood Holdings Partners LLC (together “Crestwood”) for $375 million (and purchase price adjustments). The sale included approximately 25 miles of low pressure pipeline systems and gathering rights on 104,000 net acres held by Antero within a 250,000 acre AOD and had an effective date of January 1, 2012.  Other third-party producers will also have access to the Crestwood system.  During the first seven years of the contract, the Company is committed to deliver minimum volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies.  The Company can earn up to an additional $40 million of sale proceeds over the three years following the sale if it meets certain volume thresholds.  Crestwood is obligated to incur all future capital costs to build out gathering systems and compression facilities within the AOD to connect the Company’s wells as it executes its drilling program and has assumed the various risks and rewards of the system build-out and operations.  Because the Company has not retained the substantial risks and rewards of ownership associated with the gathering rights and systems transferred to Crestwood, it has recognized a gain on the sale of the gathering system and gathering rights of approximately $291 million.

(10)Contingencies

In March 2011, the Company received orders for compliance from the U.S. Environmental Protection Agency relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations pertaining to unpermitted discharges of fill material into wetlands or waters that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. No fine or penalty relating to these matters has been proposed at this time, but we believe that these actions will result in monetary sanctions exceeding $100,000. We are unable to estimate the total amount of such monetary sanctions or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations.

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

The Company is also party to various other legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of

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other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

(11)Subsequent Event

On November 1, 2012, the Company entered into an agreement to sell all of its exploration, production, and pipeline asses in the Piceance Basin to a private company for $325 million in cash plus the assumption of all of Antero’s Rocky Mountain firm transportation obligations.  The transaction is expected to close, subject to the satisfaction of customary closing conditions, by the end of 2012 with an effective date of October 1, 2012.  Proceeds from the sale will initially be used to repay bank debt.  The Piceance Basin assets consist of 61,000 net acres of leasehold and 30 miles of gathering pipeline.  The assets contain an estimated 205 Bcfe of proved developed reserves as of September 30, 2012 and are currently producing 60 MMcfed net from 284 gross operated wells.  As a result of the sale, Antero will also monetize its natural gas hedges related to the Piceance Basin which will result in approximately $100 million of additional cash liquidity to the Company. 

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Form 10-Q.  In addition, such analysis should be read in conjunction with the historical audited financial statements and the related notes included in our 2011 Form 10-K.  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 sustained low or volatile commodity prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.  See “Cautionary Statement Regarding Forward-looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A.  Risk Factors” included in our 2011 Form 10-K and, “Item 1A.Risk Factors” of this Form 10-Q.  We do not undertake any obligation to publicly update any forward-looking statements.

In this section, references to “Antero,” “we,” “the Company,” “us,” “our” and “operating entities” refer to the entities that conduct Antero Resources LLC’s operations (Antero Resources Corporation, Antero Resources Midstream Corporation (through November 5, 2010), Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation, and, beginning December 1, 2010, Antero Resources Bluestone LLC), unless otherwise indicated or the context otherwise requires.  Antero Resources Finance Corporation (“Antero Finance”), which was formed to be the issuer of the $525 million principal amount of senior notes due 2017 and the $400 million principal amount of senior notes due 2019, is wholly owned subsidiary of Antero Resources LLC.  For more information on our organizational structure, see “Items 1 and 2.  Business and Properties—Business—Corporate Sponsorship and Structure” included in our 2011 Form 10-K or note 1 to the consolidated financial statements included elsewhere in this Form 10-Q.

Our Company

We are an independent oil and natural gas company engaged in the exploration, development and production of natural gas, NGLs, and oil located onshore in the United States.  We focus on unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations.  We hold a combination of rich gas and lean gas properties, which are primarily located in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania and the Piceance Basin in Colorado.  We sold our Arkoma Basin assets in June 2012 and results of Arkoma Basin operations are classified as discontinued operations in our September 30, 2012 financial statements.  Our corporate headquarters are in Denver, Colorado.

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

We believe we have secured sufficient long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in each of our core operating areas to accommodate our existing production.  We own gathering lines in the Appalachian Basin and the Piceance Basin.

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

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Recent Events and Highlights

Reserves and Financial Results

As of June 30, 3012, our estimated proved reserves were 4.3 Tcfe, consisting of 3.3 Tcf of natural gas, 155 MMBbl of NGLs and 15 MMBbl of oil.  Excluding the sale of the Arkoma Basin assets that were sold, proved reserves decreased by 1% compared to reserves at December 31, 2011.  At June 30, 2012, 76% of our estimated proved reserves by volume were natural gas, 19% were proved developed and 97% were operated by us.

For the nine months ended September 30, 2012, we generated cash flow from operations of $225 million, a net loss of $278 million, and EBITDAX of $324 million. The consolidated net loss of $278 million for the nine months ended September 30, 2012 included a loss on the sale of the Arkoma Basin assets of $427 million, $112 million of unrealized hedge losses, and a $291 million gain on the sale of Marcellus gathering assets and rights. Income tax expense of $113 million related primarily to unrealized hedge gains and the gain on the sale in of Marcellus gathering assets.  For the comparable nine month period ended September 30, 2011, we generated cash flow from operations of $198 million, net income of $127 million, and EBITDAX of $234 million.  See “—Non-GAAP Financial Measure” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income.

Sale of Arkoma Basin Assets

On June 29, 2012, we completed the sale of our exploration and production assets in the Arkoma Basin (along with the associated commodity hedges) to Vanguard Natural Resources, LLC (“Vanguard”). pursuant to that certain Purchase and Sale Agreement , dated June 1, 2012, between Antero Resources Corporation and Vanguard.  The assets sold consisted of 66,000 net acres in the Woodford Shale play and 5,300 net acres in the Fayetteville Shale play, located in the Arkoma Basin in Oklahoma and Arkansas, respectively.  Proceeds from the sale were $435 million, representing the purchase price of $445 million, as adjusted for expenses of the sale and estimated income, expenses and capital costs related to the Arkoma Basin properties and associated commodity hedges from the April 1, 2012 (May 1, 2012 for the associated commodity hedges) effective date of the sale through June 29, 2012 (the “interim period”).  The purchase price is subject to further adjustment for a final settlement to be conducted within 180 days from June 29, 2012 for actual income, and expenses, and capital costs for the interim period.  We recognized a $427 million noncash loss on the sale of the properties in the second quarter.  Proceeds from the sale were used to reduce outstanding borrowings under our senior secured revolving bank credit facility (the “Credit Facility”).

Sale of Piceance Basin Assets

On November 1, 2012, the Company entered into an agreement to sell all of its exploration, production, and pipeline asses in the Piceance Basin to a private company for $325 million in cash plus the assumption of all of Antero’s Rocky Mountain firm transportation obligations that have an undiscounted liability of $91 million, based on the difference between the pricing upgrade that can be obtained in the futures market at the tailgate of the pipeline and the fixed fee pipeline tariff.  The transaction is expected to close, subject to the satisfaction of customary closing conditions, by the end of 2012 with an effective date of October 1, 2012.  Proceeds from the sale will initially be used to repay bank debt.  The Piceance Basin assets consist of 61,000 net acres of leasehold and 30 miles of gathering pipeline.  The assets contain an estimated 205 Bcfe of proved developed reserves as of September 30, 2012 and are currently producing 59 MMcfed net from 284 gross operated wells.  As a result of the sale, Antero will also monetize its natural gas hedges related to the Piceance Basin over time which have a current value of approximately $100 million.  We estimate that we will recognize a loss between $375 and $400 million upon closing.

2012 Capital Budget

For the nine months ended September 30, 2012, our capital expenditures were approximately $1.1 billion for drilling, leasehold, and gathering.  Our revised capital expenditure budget for 2012, as approved by our Board of Directors, is $1.6 billion, which includes $838 million for drilling and completion, $639 million for leasehold acquisitions, and $123 million for construction of gathering pipelines and facilities.  Approximately 93% of the budget is allocated to the Marcellus Shale and 6% is allocated to the Piceance Basin.  The remainder of the 2012 capital budget has already been spent in the Woodford Shale and the Fayetteville Shale on drilling costs incurred prior to the divestiture of those properties on June 29, 2012.  Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, commodity prices and drilling results.

Credit Facility Amendment

On October 25, 2012, the borrowing base under our revolving credit facility (the “Credit Facility”) was increased to $1.65 billion.  This represents a $300 million increase over Antero’s previous borrowing base which was determined in May 2012 and further revised following the Arkoma asset sale in June 2012.  Lender commitments under the facility were raised to $950 million, a $200 million increase.  The $950 million commitment can be expanded to the full $1.65 billion borrowing base upon bank approval.

Upon closing of the above mentioned sale of the Piceance Basin assets, the Company expects the borrowing base under the Credit Facility to be reduced to approximately $1.35 billion.  The Company plans to maintain lender commitments at $950 million.

The bank syndicate, which is co-led by J.P. Morgan Securities, LLC and Wells Fargo Securities, LLC, is a diversified group consisting of nine domestic and seven foreign institutions.  As of September 30, 2012, Antero had $447 million drawn under the credit facility and $43 million in letters of credit outstanding, resulting in approximately $460 million of readily available liquidity and over $1.1 billion of unused borrowing base capacity.  The next regular borrowing base redetermination is scheduled to occur in May 2013.  The Credit Facility matures in May 2016.  Antero has only $25 million of debt maturing before 2016.

Hedge Position

As of September 30, 2012, we had entered into hedging contracts covering a total of approximately 827 Bcfe of our projected natural gas and oil production from October 1, 2012 through December 31, 2017 at a weighted average index price of $4.94 per Mcfe.

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For the three months ending December 31, 2012, we have hedged approximately 24 Bcfe of our projected natural gas and oil production at a weighted average index price of $5.43 per Mcfe.  As a result of the sale, Antero will also monetize its natural gas hedges related to the Piceance Basin over time which have a current value of approximately $100 million.

Commodity Prices and Derivative Instruments

Our production revenues from continuing operations are entirely from the continental United States and were comprised of approximately 82% natural gas, 9% NGLs, and 9% oil for the nine months ended September 30, 2012.  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 and oil swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold.  At each period end we estimate the fair value of these swaps and recognize an unrealized gain or loss.  We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings.  During the nine months ended September 30, 2011 and 2012, we recognized significant unrealized commodity gains or losses on these swaps.  We expect continued volatility in the fair value of these swaps.

Principal Components of Our Cost Structure

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

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

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

·Impairment of unproved and proved properties.  These costs include unproved property impairment and costs associated with lease expirations.  We could also record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows.  From our inception through September 30, 2012, it has not been necessary to record any impairment for proved properties.

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

·General and administrative expense.  These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees, and legal compliance.

·Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our Credit Facility.  As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions.  We also have fixed interest on our outstanding senior notes.  We will likely continue to incur significant interest expense as we continue to grow.

·Income tax expense.  Each of our subsidiary corporations file separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities.  We are subject to state and federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”).  We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.  Collectively, the operating entities have generated net operating loss carryforwards which expire at various dates from 2024 through 2031.  We have recognized the value of these net operating losses to the extent of our deferred tax liabilities; however, we have not recognized the full value of these net operating losses on our balance sheets because our management

18

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.  However, the amount of deferred tax assets considered realizable could change in the near term as we generate taxable income or if estimates of future taxable income are reduced or tax laws are changed.  As a result of the sale of a portion of our Appalachian gathering assets in March 2012, we estimate that we will incur a federal alternative minimum tax liability of approximately $29 million for our 2012 tax year.

On October 17, 2012, we completed a reorganization of our legal structure by contributing all of the outstanding shares owned by Antero Resources LLC in each of the Antero Arkoma, Antero Piceance, and Antero Pipeline subsidiary corporations to Antero Appalachian.  Antero Arkoma, Antero Piceance and Antero Pipeline were then converted to limited liability companies.  As a result of this reorganization, we expect to recognize benefits from certain previously unrecognized loss carryforwards during the fourth quarter of 2012.

19

Results of Operations

Three months ended September 30, 2011 Compared to Three months ended September 30, 2012

The following table sets forth selected operating data for the three months ended September 30, 2011 compared to the three months ended September 30, 2012.  Revenues, expenses and loss on the sale of the Arkoma Basin assets are included in discontinued operations for both periods presented.  Production data excludes Arkoma Basin production.

	Three Months Ended September 30,						Amount of Increase			Percent
	2011			2012			(Decrease)			Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	71,836		77,212			5,376			7	%
NGL sales	5,886			6,357			471			8	%
Oil sales	4,775			6,202			1,427			30	%
Realized commodity derivative gains	16,547			58,652			42,105			254	%
Unrealized commodity derivative gains (losses)	124,567			(236,536		)	(361,103		)	*
Loss on sale of assets				(115		)	(115		)	*
Total operating revenues	223,611			(88,228		)	(311,839		)	*
Operating expenses:
Lease operating expense	6,087			3,943			(2,144		)	(35	)%
Gathering, compression and transportation	15,439			32,976			17,537			114	%
Production taxes	5,473			5,397			(76		)	(1	)%
Exploration expenses	968			3,251			2,283			236	%
Impairment of unproved properties	4,652			2,407			(2,245		)	(48	)%
Depletion, depreciation and amortization	29,117			41,055			11,938			41	%
Accretion of asset retirement obligations	86			116			30			35	%
General and administrative	7,404			11,938			4,534			61	%
Total operating expenses	69,226			101,083			31,857			44	%
Operating income (loss)	154,385			(189,311		)	(343,696		)	*
Interest expense	(20,608		)	(22,453		)	(1,845		)	9	%
Income (loss) before income taxes	133,777			(211,764		)	(345,541		)	*
Income tax benefit (expense)	(49,578		)	84,086			133,664			*
Income (loss) from continuing operations	84,199			(127,678		)	(211,877		)	*
Income from discontinued operations and sale of discontinued operations	26,879			—			(26,879		)	(100	)%
Net income (loss) attributable to Antero members	$	111,078		(127,678		)	(238,756		)	*
EBITDAX (1)	$	91,921		95,165			3,244			4	%
Production data:
Natural gas (Bcf)	17			27			10			57	%
NGLs (MBbl)	138			203			65			48	%
Oil (MBbl)	62			78			16			28	%
Combined (Bcfe)	18			28			10			57	%
Daily combined production (MMcfe/d)	196			308			112			57	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	4.26		$	2.90		$	(1.36	)	(32	)%
NGLs (per Bbl)	$	42.78		$	31.28		$	(11.50	)	(27	)%
Oil (per Bbl)	$	77.63		$	79.30		$	1.67		2	%
Combined (per Mcfe)	$	4.57		$	3.17		$	(1.40	)	(31	)%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	5.24		$	5.10		$	(0.14	)	(3	)%
NGls (per Bbl)	$	42.78		$	31.28		$	(11.50	)	(27	)%
Oil (per Bbl)	$	77.16		$	78.60		$	1.40		2	%
Combined (per Mcfe)	$	5.49		$	5.24		$	(0.25	)	(5	)%
Average Costs (per Mcfe):
Lease operating costs	$	0.34		$	0.14		$	(0.20	)	(59	)%
Gathering, compression and transportation	$	0.86		$	1.16		$	0.30		35	%
Production taxes	$	0.30		$	0.19		$	(0.11	)	(37	)%
Depletion, depreciation, amortization and accretion	$	1.61		$	1.45		$	(0.16	)	(10	)%
General and administrative	$	0.41		$	0.42		$	0.01		2	%

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(1)	See “—Non-GAAP Financial Measure” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income attributable to Antero members.
(2)	Average prices shown in the table reflect both of the before-and-after effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.
*	Not meaningful or applicable

Natural gas, NGLs, and oil sales.  Revenues from production of natural gas, NGLs, and oil increased from $82 million for the three months ended September 30, 2011 to $90 million for the three months ended September 30, 2012, an increase of $8 million, or 9%.  Our production increased by 57% over that same period, from 18 Bcfe for the three months ended September 30, 2011 to 28 Bcfe for the three months ended September 30, 2012, and prices decreased by 31%, before the effect of realized hedge gains.  Increased production volumes would have accounted for an approximately $47 million increase in revenues (calculated as the change in year-to-year volumes times the prior year average price), and commodity price decreases would have accounted for an approximately $40 million decrease in revenues (calculated as the change in year-to-year average price times current year production volumes).  Production increases from our Appalachian Basin properties accounted for 9 Bcfe out of the total 10 Bcfe increase in production from the prior year quarter.

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, 2011 and 2012, our hedges resulted in realized gains of $17 million and $59 million, respectively.  For the three months ended September 30, 2011 and 2012, our hedges resulted in unrealized gains (losses) of $125 million and $(237) million, respectively.  Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas strip prices increase or decrease from their levels at the end of the accounting period or as gains or losses are realized through settlement.

Lease operating expenses.  Lease operating expenses decreased by $2 million from the three months ended September 30, 2011 compared to the three months ended September 30, 2012, primarily because of reduced workover expenses in the Piceance Basin.  On a per unit basis, lease operating expenses decreased by 59%, from $0.34 per Mcfe for the three months ended September 30, 2011 to $0.14 for the three months ended September 30, 2012 primarily because of the combined effect of reduced Piceance Basin expenses and because per unit lease operating expenses during the early stages of production for the relatively high production rate Marcellus Shale wells are lower than more mature properties.

Gathering, compression and transportation expenses.  Gathering, compression and transportation expense increased from $15 million for the three months ended September 30, 2011 to $33 million for the three months ended September 30, 2012, primarily due to an increase in production volumes and increased costs on firm transportation commitments which we have executed to facilitate future production growth.  On a per unit basis, gathering, compression, and transportation expenses increased by 35% from $0.86 per Mcfe for the three months ended September 30, 2011 to $1.16 per Mcfe for the three months ended September 30, 2012.  Increased unit costs were driven primarily by low pressure gathering fees payable for the first time to Crestwood (who purchased our Marcellus gathering assets in March 2012).

Production taxes.  Total production taxes remained constant at $5 million for each of the three months ended September 30, 2011 and September 30, 2012.   On a per unit basis, production taxes decreased from $0.30 to $0.19 per Mcfe due to declining natural gas prices.  Production taxes as a percentage of natural gas, NGL, and oil revenues were 7% and 6% for the three months ended September 30, 2011 and 2012, respectively.  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 expenses increased from $1 million for the three months ended September 30, 2011 to $3 million for the three months ended September 30, 2012 primarily due to an increase in contract landmen and contract landman costs for unsuccessful efforts related to lease acquisitions.

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Impairment of unproved properties.  Impairment of unproved properties was approximately $5 million for the three months ended September 30, 2011 and $2 million for the three months ended September 30, 2012.  We have no unimpaired acreage expiring in the near-term in the Piceance Basin and our Marcellus and Utica acreage is generally held by production or consists of new leases with expirations several years in the future.  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.

DD&A.  DD&A increased from $29 million for the three months ended September 30, 2011 to $41 million for the three months ended September 30, 2012, primarily because of increased production.  DD&A per Mcfe decreased by 8% from $1.61 per Mcfe during the three months ended September 30, 2011 to $1.45 per Mcfe during the three months ended September 30, 2012, primarily as a result of increased reserves in the Marcellus Shale.

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, 2011 or 2012 for proved properties.

General and administrative expense.  General and administrative expense increased from $7 million for the three months ended September 30, 2011 to $12 million for the three months ended September 30, 2012, primarily as a result of increased staffing levels and related salary and benefits expenses, franchise tax expense, and increases in legal and other general corporate expenses, all of which resulted from our growth in production levels and development activities.  On a per unit basis, general and administrative expense was $0.41 per Mcfe during the three months ended September 30, 2011 and  $0.42 per Mcfe during the three months ended September 30, 2012.

Interest expense.  Interest expense increased from $21 million for the three months ended September 30, 2011 to $22 million for the three months ended September 30, 2012, due to the issuance of $400 million 7.25% senior notes due 2019 in August 2011 and increased borrowings under the Credit Facility.  Interest expense includes approximately $2 million of non-cash amortization for the three months ended September 30, 2012 and $1 million for the three months ended September 30, 2011.

Income tax benefit (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.  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, 2012, resulting from unrealized gains on commodity derivatives and basis differences in assets.  Deferred income tax benefit of $84 million during the three months ended September 30, 2012 is due to the partial reversal of previously recognized gains on commodity derivatives during the quarter as a result of natural gas prices increasing from June 30, 2012 levels.

As a result of the gain on the sale of the Appalachian gathering assets in the first quarter of 2012 and the expected utilization of NOLs in 2012, we estimate that we will have a federal alternative minimum tax liability of approximately $29 million in 2012.

At December 31, 2011, the operating entities had a combined total of approximately $937 million of NOLs, which expire starting in 2024 and through 2031.  Proposed legislation in the U.S. Congress would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position.  The impact of any change will be recorded in the period that legislation is enacted.

Income from discontinued operations and sale of discontinued operations.  On June 29, 2012, we completed the sale of our exploration and production assets in the Arkoma Basin (along with the associated commodity hedges) to Vanguard Natural Resources.  Results of our Arkoma Basin operations and the loss on the sale of the Arkoma Basin assets are included in discontinued operations for the current and prior year periods.  We had income from discontinued operations of $27 million for the three months ended September 30, 2011.  The sale of the Arkoma operations occurred at the end of the second quarter of 2012 and there were no Arkoma operations included in our results for the third quarter of 2012.

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Nine months ended September 30, 2011 Compared to Nine months ended September 30, 2012

The following table sets forth selected operating data for the nine months ended September 30, 2011 compared to the nine months ended September 30, 2012.  Revenues, expenses and loss on the sale of the Arkoma Basin assets are included in discontinued operations for both periods presented.  Production data excludes Arkoma Basin production.

	Nine months Ended September 30,						Amount of Increase			Percent
	2011			2012			(Decrease)			Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	168,797		184,493			15,696			9	%
NGL sales	14,224			21,602			7,378			52	%
Oil sales	9,224			19,527			10,303			112	%
Realized commodity derivative gains	48,282			187,561			139,279			288	%
Unrealized commodity derivative gains (losses)	151,520			(111,649		)	(263,169		)	(174	)%
Gain on sale of assets	—			291,190			291,190			*
Total operating revenues	392,047			592,724			200,677			51	%
Operating expenses:
Lease operating expense	17,487			16,123			(1,364		)	(8	)%
Gathering, compression and transportation	37,331			78,888			41,557			111	%
Production taxes	12,141			15,191			3,050			25	%
Exploration expenses	5,902			8,150			2,248			38	%
Impairment of unproved properties	6,828			4,572			(2,256		)	(33	)%
Depletion, depreciation and amortization	67,865			106,733			38,868			57	%
Accretion of asset retirement obligations	242			325			83			34	%
General and administrative	21,972			31,584			9,612			44	%
Loss on sale of compressor station	8,700			—			(8,700		)	(100	)%
Total operating expenses	178,468			261,566			83,098			47	%
Operating income	213,579			331,158			117,579			55	%
Interest expense and loss on interest rate derivatives	(51,362		)	(71,046		)	(19,684		)	38	%
Income before income taxes	162,217			260,112			97,895			60	%
Income tax expense	(74,941		)	(112,610		)	(37,669		)	50	%
Income from continuing operations	87,226			147,502			60,226			69	%
Income (loss) from discontinued operations and sale of discontinued operations	39,940			(425,536		)	(464,422		)	*
Net income (loss) attributable to Antero members	$	126,766		(278,034		)	(404,800		)	*
EBITDAX (1)	$	233,786		323,744			89,958			38	%
Production data:
Natural gas (Bcf)	38			69			31			81	%
NGLs (MBbl)	315			618			303			96	%
Oil (MBbl)	115			235			120			104	%
Combined (Bcfe)	41			74			33			82	%
Daily combined production (MMcfe/d)	150			272			122			82	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	4.40		$	2.66		$	(1.74	)	(40	)%
NGLs (per Bbl)	$	45.21		$	34.95		$	(10.26	)	(23	)%
Oil (per Bbl)	$	80.17		$	82.93		$	2.76		3	%
Combined (per Mcfe)	$	4.70		$	3.03		$	(1.67	)	(36	)%
Average realized prices after effects of hedges(2):
Natural gas (per Mcf)	$	5.67		$	5.38		$	(0.29	)	(5	)%
NGls (per Bbl)	$	45.21		$	34.95		$	(10.26	)	(23	)%
Oil (per Bbl)	$	75.36		$	80.83		$	5.47		7	%
Combined (per Mcfe)	$	5.88		$	5.55		$	(0.33	)	(6	)%
Average Costs (per Mcfe):
Lease operating costs	$	0.43		$	0.22		$	(0.21	)	(49	)%
Gathering, compression and transportation	$	0.91		$	1.06		$	0.15		16	%
Production taxes	$	0.30		$	0.20		$	(0.10	)	(33	)%
Depletion, depreciation, amortization and accretion	$	1.66		$	1.43		$	(0.23	)	(14	)%
General and administrative	$	0.54		$	0.42		$	(0.12	)	(22	)%

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(1)	See “—Non-GAAP Financial Measure” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income attributable to Antero members.
(2)	Average prices shown in the table reflect both of the before-and-after effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil and NGL production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.
*	Not meaningful or applicable

Natural gas, NGLs, and oil sales.  Revenues from production of natural gas, NGLs, and oil increased from $192 million for the nine months ended September 30, 2011 to $226 million for the nine months ended September 30, 2012, an increase of $34 million, or 17%.  Our production increased by 82% over that same period, from 41 Bcfe for the nine months ended September 30, 2011 to 74 Bcfe for the nine months ended September 30, 2012, and prices decreased by 36%, before the effect of realized hedge gains.  Increased production volumes would have accounted for an approximately $158 million increase in revenues (calculated as the change in year-to-year volumes times the prior year average price), and commodity price decreases would have accounted for an approximately $124 million decrease in revenues (calculated as the change in year-to-year average price times current year production volumes).  Production increases from our Appalachian Basin properties accounted for 29 Bcfe out of the total 33 Bcfe increase in production from the prior year quarter.

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, 2011 and 2012, our hedges resulted in realized gains of $48 million and $188 million, respectively.  For the nine months ended September 30, 2011 and 2012, our hedges resulted in unrealized gains (losses) of $152 million and $(112) million, respectively.  Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas strip prices increase or decrease from their levels at the end of the accounting period or as gains or losses are realized through settlement.

Lease operating expenses.  Lease operating expenses decreased by approximately $1 million from the nine months ended September 30, 2011 compared to the nine months ended September 30, 2012, primarily because of decreased workover expenses in the Piceance Basin.  On a per unit basis, lease operating expenses decreased by 49%, from $0.43 per Mcfe for the nine months ended September 30, 2011 to $0.22 per Mcfe for the nine months ended September 30, 2012 primarily because of the combined effect of lower Piceance Basin expenses and because per unit lease operating expenses during the early stages of production for the relatively high production rate Marcellus Shale wells are lower than more mature properties.

Gathering, compression and transportation expenses.  Gathering, compression and transportation expense increased from $37 million for the nine months ended September 30, 2011 to $79 million for the nine months ended September 30, 2012, primarily due to an increase in production volumes and increased costs for firm transportation commitments, some of which have been incurred in anticipation of increased future production.  On a per unit basis, gathering, compression, and transportation expenses increased by 16% from $0.91 per Mcfe for the nine months ended September 30, 2011 to $1.06 per Mcfe for the nine months ended September 30, 2012.  We incurred increased costs during the third quarter of 2012 primarily because of fees payable beginning April 1, 2012  to Crestwood (who purchased our Marcellus gathering assets in March 2012).

Production taxes.  Total production taxes increased by $3 million for the nine months ended September 30, 2012 compared to the prior year period, primarily as a result of increased production.  On a per unit basis, production taxes decreased from $0.30 to $0.20 per Mcfe.  Production taxes as a percentage of natural gas, NGL, and oil revenues were 6% and 7% for the nine months ended September 30, 2011 and 2012, respectively.  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.

24

Exploration expense.  Exploration expense was $6 million for the nine months ended September 30, 2011 compared to $8 million for the nine months ended September 30, 2012.  The year over year increase is due to an increase in contract landman costs for unsuccessful efforts related to lease acquisitions.

Impairment of unproved properties.  Impairment of unproved properties was approximately $7 million for the nine months ended September 30, 2011compared to $5 million for the nine months ended September 30, 2012.   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.

DD&A.  DD&A increased from $68 million for nine months ended September 30, 2011 to $107 million for the nine months ended September 30, 2012, primarily because of increased production.  DD&A per Mcfe decreased by 13% from $1.66 per Mcfe during the nine months ended September 30, 2011 to $1.43 per Mcfe during the nine months ended September 30, 2012, primarily as a result of increased reserves.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.  If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value.  No impairment expenses were recorded for the nine months ended September 30, 2011 or 2012 for proved properties.

General and administrative expense.  General and administrative expense increased from $22 million for the nine months ended September 30, 2011 to $32 million for the nine months ended September 30, 2012, primarily as a result of increased staffing levels and related salary and benefits expenses, franchise tax expense, and increases in legal and other general corporate expenses, all of which resulted from our growth in production levels and development activities.  On a per unit basis, general and administrative expense decreased by 22%, from $0.54 per Mcfe during the nine months ended September 30, 2011 to $0.42 per Mcfe during the nine months ended September 30, 2012, primarily due to an 82% increase in production.

Interest expense and realized and unrealized gains and losses on interest rate derivatives.  Interest expense increased from $51 million for the nine months ended September 30, 2011 to $71 million for the nine months ended September 30, 2012, due to the issuance of $400 million 7.25% senior notes due 2019 in August 2011 and increased borrowings under the Credit Facility.  Interest expense includes approximately $4 million of non-cash amortization of deferred financing costs and bond discount and premium for the nine months ended September 30, 2012 and $3 million for the nine months ended September 30, 2011.

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 our operating entities.  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, 2012, resulting from unrealized gains on commodity derivatives and basis differences in assets.  Deferred income tax expense of $113 million during the nine months ended September 30, 2012 is due to income for financial reporting purposes and cumulative unrealized gains on commodity derivatives and basis differences on oil and gas assets.

As a result of the gain on the sale of the Appalachian gathering assets in the first quarter of 2012 and the expected utilization of NOLs in 2012, we estimate that we will have a federal alternative minimum tax liability of approximately $29 million in fiscal 2012.

At December 31, 2011, the operating entities had a combined total of approximately $937 million of NOLs, which expire starting in 2024 and through 2031.  Proposed legislation in the U.S. Congress would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position.  The impact of any change will be recorded in the period that legislation is enacted.

Income (loss) from discontinued operations and sale of discontinued operations.  On June 29, 2012, we completed the sale of our exploration and production assets in the Arkoma Basin (along with the associated commodity hedges) to Vanguard.  Results of our Arkoma Basin operations and the loss on the sale of the Arkoma Basin assets are included in discontinued operations for the current and prior year periods.  In 2012, a loss was recorded on the sale of the Arkoma Basin assets of $427 million for the excess of the net

25

book value in the assets over the proceeds received of $435 million.  Because of the net deferred tax asset position in Antero Resources Corporation, there was no current or deferred tax effect from the sale.

Capital Resources and Liquidity

Our primary sources of liquidity have been proceeds from issuances of equity securities and senior notes, borrowings under bank credit facilities, asset sales, and net cash provided by operating activities.  Our primary use of cash has been for the exploration, development and acquisition of unconventional natural gas and oil properties.  As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditures, and liquidity requirements.  Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us.

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

The following table summarizes our cash flows for the nine months ended September 30, 2011 and 2012:

	Nine months Ended September 30,
	2011			2012
	(in thousands)
Net cash provided by operating activities	$	198,446		225,400
Net cash used in investing activities	(687,482		)	(295,180	)
Net cash provided by financing activities	484,228			82,992
Net increase (decrease) in cash and cash equivalents	$	(4,808	)	13,212

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $198 million and $225 million for the nine months ended September 30, 2011 and 2012, respectively.  The increase in cash flow from operations from the nine months ended September 30, 2011 to the nine months ended September 30, 2012 was primarily the result of increased production volumes and revenues (including derivative settlements), net of the increase in cash operating costs, interest expense, and changes in working capital levels.

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

Cash Flow Used in Investing Activities

During the nine months ended September 30, 2012, we had cash flows used in investing activities of $295 million.  Cash flow used for investments in land, drilling and gathering systems totaled $1.1 billion and was partially offset by proceeds from the sale of the Arkoma Basin assets and the Marcellus gathering systems and rights of $816 million.  During the nine months ended September 30, 2011, we used cash flow in investing activities of $687 million primarily for land, drilling, and gathering systems.

Our revised capital expenditure budget for 2012, as approved by our Board of Directors, is $1.6 billion, which includes $836 million for drilling and completion, $641 million for leasehold acquisitions and $123 million for the construction of gathering pipelines and facilities.  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 of $83 million during the nine months ended September 30, 2012 resulted primarily from an increase in borrowings under the Credit Facility.  Net cash provided by financing activities during the nine months ended September 30, 2011 of $484 million was the result of the issuance of $400 million of 7.25% senior subordinated notes,  net borrowings under the Credit Facility of $120 million, net of payments of financing costs of  $7 million and $29 million of distributions

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to members.  The distribution to members was required by our limited liability company operating agreement to cover income taxes owed by the members as a result of the gain realized on the sale of the Arkoma midstream assets in the fourth quarter of 2010.

Credit Facility.   Our Credit Facility provides for a maximum amount of $2.5 billion.  As a result of the regular semiannual redetermination of the borrowing base, on October 25, 2012, the borrowing base was increased from $1.35 billion to $1.65 billion and lender commitments were increased from $750 million to $950 million. The borrowing base is redetermined semiannually, based on the lenders’ determination of the amount of our proved oil and gas reserves and estimated cash flows from those reserves and our hedge positions.  The next redetermination is scheduled to occur in May 2013.  As of December 31, 2011 and September 30, 2012, borrowings and letters of credit outstanding under our Credit Facility totaled $386 million and $490 million, respectively, and had a weighted average interest rate of 2.12% and 2.0%, respectively.  At September 30, 2012, we had $260 million of available borrowing capacity based on $750 million of lender commitments at that date.  The Credit Facility matures in May 2016.

Upon closing of the sale of the Piceance Basin assets described elsewhere herein, the Company expects the borrowing base under the Credit Facility to be reduced to approximately $1.40 billion.  The Company plans to maintain lender commitments at $950 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 Credit Facility contains certain covenants, including restrictions on indebtedness, asset sales, investments, liens, dividends, and certain other transactions without the prior consent of the lenders.  We are required to maintain the following two financial ratios:

·a current ratio, which is the ratio of our consolidated current assets (includes unused commitment under Credit Facility and excludes derivative assets) to our consolidated current liabilities, of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

·a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX to consolidated interest expense, of not less than 2.5 to 1.0.

We were in compliance with covenants and ratios under our Credit Facility as of December 31, 2011 and as of September 30, 2012.

Senior Notes.  We have $525 million of 9.375% senior notes outstanding which are due December 1, 2017.  The notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.  The notes were issued by Antero Finance and are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on June 1 and December 1 each year.  Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015.  In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%.  At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium and accrued interest.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par.  The notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.  The notes rank pari passu to the existing 9.375% senior notes due 2017.  The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on August 1, and February 1 of each year, commencing on February 1, 2012.  Antero Finance may redeem all or part of the notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017.  In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the notes, plus accrued interest.  At any time prior to August 1, 2014, Antero Finance may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium and accrued interest.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

We used the proceeds from the offering of the notes to repay borrowings outstanding under our Credit Facility, for development of our oil and natural gas properties and for general corporate purposes.

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The senior notes indentures contain restrictive covenants and a minimum interest coverage ratio requirement of 2.25:1.  We were in compliance with such covenants and the coverage ratio requirement as of December 31, 2011 and September 30, 2012.

Treasury Management Facility.  We executed a stand-alone revolving note with a lender under the Credit Facility which provides for up to $25 million of cash management obligations in order to facilitate our daily treasury management.  Borrowings under the revolving note are secured by the collateral for the Credit Facility.  Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%.  The note matures on June 1, 2013.  At December 31, 2011 and September 30, 2012 there were no outstanding borrowings under this facility.

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

Interest Rate Hedges.  We currently have no outstanding interest rate swaps.  From time to time in the past, we have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our Credit Facility and previously outstanding second lien term loan facility.

Non-GAAP Financial Measure

“EBITDAX” is a non-GAAP financial measure that we define as net income before interest, income taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized hedge gains or losses, franchise taxes, and gains or losses on sales of assets.  “EBITDAX,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP.  EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.  EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, working capital movement or tax position.  EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, and other commitments and obligations.  However, our management team believes EBITDAX is useful to an investor in evaluating our operating performance because this measure:

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

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

·is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our Credit Facility.  EBITDAX is also used as a measure of our operating performance pursuant to a covenant under the indentures governing our $525 million principal amount of 9.375% senior notes due 2017 and our $400 million principal amount of 7.25% senior notes due 2019.

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

The following table represents a reconciliation of our net income (loss) to EBITDAX:

	Year Ended December 31,			Three Months Ended September 30,				Nine months Ended September 30,
	2011			2011		2012		2011		2012
Net income (loss) attributable to Antero members	$	392,678		111,078		(127,678	)	126,766		(278,034	)
Unrealized losses (gains) on derivative contracts(1)	(559,596		)	(140,195	)	236,536		(160,744	)	122,674
Net loss on sale of assets	8,700					115		8,700		136,042
Interest expense and other	74,498			20,608		22,453		51,362		71,046
Provision (benefit) for income taxes	230,452			49,578		(84,086	)	74,941		112,610
Depreciation, depletion, amortization and accretion(1)	170,956			44,728		41,171		117,581		143,014
Impairment of unproved properties(1)	11,051			4,834		2,407		7,934		4,981
Exploration expense(1)	9,876			1,105		3,251		6,538		8,419
Other	2,206			185		996		708		2,992
EBITDAX	$	340,821		91,921		95,165		233,786		323,744

(1)     Includes results from discontinued operations.

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States.  The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities.  Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.  We evaluate our estimates and assumptions on a regular basis.  We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.  Our more significant accounting policies and estimates include the successful efforts method of accounting for oil and gas production activities, estimates of natural gas and oil reserve quantities and standardized measures of future cash flows, and impairment of unproved properties.  We provide an expanded discussion of our more significant accounting policies, estimates and judgments in our 2011 Form 10-K.  We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements.  Also, see note 2 of the notes to our audited consolidated financial statements, included in our 2011 Form 10-K for a discussion of additional accounting policies and estimates made by management.

New Accounting Pronouncements

There were no new accounting pronouncements issued during the three months ended September 30, 2012 that had a material effect on our financial reporting.

Off-Balance Sheet Arrangements

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

Contractual Obligations

A summary of our contractual obligations as of September 30, 2012 is provided in the following table.

	Year
(in millions)	1		2	3	4	5	Thereafter	Total
Credit Facility(1)	$	—	—	—	447.0	—	—	447.0
Senior notes—principal(2)	—		25.0	—	—	—	925.0	950.0
Senior notes—interest(2)	80.4		78.2	78.2	78.2	78.2	82.6	475.8
Drilling rig and frac service commitments(3)	122.3		58.1	22.1	—	—	—	202.5
Firm transportation (4)	46.1		90.1	124.4	128.3	126.3	921.5	1,436.7
Gas processing, gathering, and compression service (5)	55.2		69.6	77.7	83.0	82.9	355.0	723.4
Office and equipment leases	1.6		2.1	2.8	2.6	2.3	14.3	25.7
Asset retirement obligations(6)	—		—	—	—	—	6.6	6.6
Total	$	305.6	323.1	305.2	739.1	289.7	2,305.0	4,267.7

(1)Includes outstanding principal amount at September 30, 2012. This table does not include future commitment fees, interest expense or other fees on the Credit Facility because they are floating rate instruments and we cannot determine with accuracy the

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timing of future loan advances, repayments or future interest rates to be charged.

(2)Includes the 9.375% senior notes due 2017, the 7.25% senior notes due 2019, and a $25.0 million senior note due 2013.

(3)At September 30, 2012, we had contracts for the services of 12 rigs which expire at various dates from December 2013 through July 2015. We also had two frac services contracts which expire in 2013 and 2014. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(4)We have entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. The contracts expire at various dates from 2020 to 2028. Yearly commitments after year 5 and through 2028 range in amount from $44 million to $117 million. These contracts commit us to transport minimum daily natural gas or NGL volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent our minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

(5)Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term agreements for the Piceance Basin production and certain Appalachian Basin production as well as various gas compression agreements in both basins. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

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

Item 3.Quantitative and Qualitative Disclosures about Market Risk.

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

Commodity Price Risk

Our primary market risk exposure is in the price we receive for our natural gas 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 Colorado Interstate Gas (CIG) Hub, Columbia Gas Transmission (CGTAP), Columbia Gas Louisiana (CGLA), and Dominion South indices.

Our financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas price fluctuations.  The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price.  We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price.  These contracts may include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and cashless price collars that set a floor and ceiling price for the hedged production.  If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we and the counterparty to the collars would be required to settle the difference.

At December 31, 2011 and September 30, 2012, we had in place natural gas and oil swaps covering portions of our projected production from 2012 through 2017.  Our hedge position as of September 30, 2012 is summarized in note 8 to our consolidated financial statements included elsewhere in this Form 10-Q.  Our Credit Facility allows us to hedge up to 85% of our estimated

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production from proved reserves for up to 12 months in the future, 80% for 13 to 24 months in the future, 75% for 25 to 36 months in the future, 70% for 37 to 48 months in the future and 65% for our estimated 2018 production.  Based on our production for the nine months ended September 30, 2012 and our fixed price swap contracts in place during that period, our income from continuing operations before taxes for the nine months ended September 30, 2012 would have decreased by approximately $0.7 million for each $0.10 decrease per MMBtu in natural gas prices and $0.2 million for each $1.00 decline in oil prices.

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

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 September 30, 2012, the estimated fair value of our commodity derivative instruments was a net asset of $559 million comprised of current and noncurrent assets.  At December 31, 2011, the estimated fair value of our commodity derivative instruments was a net asset of $790 million comprised of current and noncurrent assets.

By removing price volatility from a portion of our expected natural gas production through December 2017, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods.  While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($559 million at September 30, 2012), joint interest receivables ($14 million at September 30, 2012), and accrued revenue from the sale of our oil and gas production ($19 million at September 30, 2012).

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties.  Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk.  To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.  The creditworthiness of our counterparties is subject to periodic review.  We have economic hedges in place with ten different counterparties, all but one of which is a lender under our Credit Facility.  We have exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The fair value of our commodity derivative contracts of approximately $559 million at September 30, 2012 includes the following values by bank counterparty:  BNP Paribas - $164 million; Credit Suisse - $133 million; Wells Fargo - $92 million; JP Morgan - $67 million; Credit Agricole - $45 million; Barclays - $40 million; Deutsche Bank - $8 million; and Union Bank  — $2 million.  Additionally, contracts with Dominion Field Services account for $8 million of the fair value. The credit ratings of certain of these banks were downgraded in 2011 because of the sovereign debt crisis in Europe.  The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) at September 30, 2012 for each of the European and American banks.  We believe that all of these institutions currently are acceptable credit risks.  Other than as provided by the Credit Facility, we are not required to provide credit support or collateral to any of our counterparties under our contracts, nor are they required to provide credit support to us.  As of September 30, 2012, we have no past due receivables from or payables to any of our counterparties.

Joint interest receivables arise from billing entities that own partial interests in the wells we operate.  These entities participate in our wells primarily based on their ownership in leases on which we wish to drill.  We can do very little to choose who participates in our wells.

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

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Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which has a floating interest rate.  The average annual interest rate incurred on this indebtedness for the nine months ended September 30, 2012 was approximately 2.0%.  A 1.0% increase in each of the average LIBOR rate and federal funds rate would have resulted in an estimated $2.3 million increase in interest expense for the nine months ended September 30, 2012.

Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report.  Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2012 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

In March 2011, we received orders for compliance from the U.S. Environmental Protection Agency (“the EPA”) relating to certain of our activities in West Virginia.  The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations pertaining to unpermitted discharges of fill material into wetlands or waters that are potentially in violation of the Clean Water Act.  We have responded to all pending orders and are actively cooperating with the relevant agencies.  No fine or penalty relating to these matters has been proposed at this time, but we believe that these actions will result in monetary sanctions exceeding $100,000.  We are unable to estimate the total amount of such monetary sanctions or costs to remediate these locations in order to bring them into compliance with applicable environmental laws and regulations.

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

The Company is currently party to various other legal proceedings and claims in the ordinary course of its business.  The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not have a material adverse effect on its consolidated financial position, results of operations, or liquidity.  However, we may not be able to predict the timing, outcome or the availability of insurance coverage for any future claims and proceedings with certainty, and an unfavorable resolution of one or more of such future matters could have a material adverse effect on our financial condition, results of operations or liquidity.

Item 1A.Risk Factors.

We are subject to certain risks and hazards due to the nature of the business activities we conduct.  For a discussion of these risks, see “Item 1A.  Risk Factors” in our 2011 Form 10-K.  The risks described in our 2011 Form 10-K could materially and adversely affect our business, financial condition, cash flows, and results of operations.  There have been no material changes to the risks described in our 2011 Form 10-K.  We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Item 6.Exhibits.

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

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SIGNATURES

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

	ANTERO RESOURCES LLC
Date: November 7, 2012	By:	/s/ GLEN C. WARREN, JR.
		Glen C. Warren, Jr.
		President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

Exhibit Number	Description of Exhibits
3.1	Certificate of Incorporation of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.2	Bylaws of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.3	Certificate of Formation of Antero Resources LLC (incorporated by reference to Exhibit 3.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.4	Amended and Restated Limited Liability Company Agreement of Antero Resources LLC dated as of December 1, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 3, 2010).
31.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*	Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*	Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101*	The following financial information from this Form 10-Q of Antero Resources LLC for the quarter ended September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as blocks of text.

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

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