UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2013

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

For the transition period from to

Commission file number: 333-164876-06

ANTERO RESOURCES LLC

(Exact name of registrant as specified in its charter)

Delaware		90-0522242
(State or other jurisdiction of incorporation or organization)		(I.R.S. 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

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		(i)
PART I - FINANCIAL INFORMATION		2
Item 1.	Financial Statements	2
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	36
PART II—OTHER INFORMATION		36
Item 1.	Legal Proceedings	36
Item 1A.	Risk Factors	37
Item 6.	Exhibits	37
SIGNATURES		38

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included in this Quarterly Report on Form 10-Q. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

· business strategy;

· reserves;

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

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

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

· hedging strategy and results;

· future drilling plans;

· competition and government regulations;

· pending legal or environmental matters;

· marketing of natural gas, NGLs and oil;

· leasehold or business acquisitions;

· costs of developing our properties and conducting our 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, 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, NGLs, and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 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.

Table of Contents

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by 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, NGLs, and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

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

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

December 31, 2012 and June 30, 2013

(Unaudited)

(In thousands)

	2012			2013
Assets
Current assets:
Cash and cash equivalents	$	18,989		10,867
Accounts receivable — trade, net of allowance for doubtful accounts of $174 and $10 in 2012 and 2013, respectively	21,296			29,231
Notes receivable — short-term portion	4,555			4,444
Accrued revenue	46,669			66,432
Derivative instruments	160,579			205,221
Other	22,518			11,710
Total current assets	274,606			327,905
Property and equipment:
Oil and natural gas properties, at cost (successful efforts method):
Unproved properties	1,243,237			1,366,023
Proved properties	1,689,132			2,629,529
Gathering systems and facilities	168,930			334,096
Other property and equipment	9,517			11,282
	3,110,816			4,340,930
Less accumulated depletion, depreciation, and amortization	(173,343		)	(266,296	)
Property and equipment, net	2,937,473			4,074,634
Derivative instruments	371,436			388,694
Notes receivable — long-term portion	2,667			—
Other assets, net	32,611			33,915
Total assets	$	3,618,793		4,825,148
Liabilities and Equity
Current liabilities:
Accounts payable	$	181,478		233,751
Accrued liabilities and other	61,161			84,262
Derivative instruments	—			264
Revenue distributions payable	46,037			54,532
Current portion of long-term debt	25,000			25,000
Deferred income tax liability	62,620			79,722
Total current liabilities	376,296			477,531
Long-term liabilities:
Long-term debt	1,444,058			2,418,217
Deferred income tax liability	91,692			127,915
Other long-term liabilities	33,010			44,552
Total liabilities	1,945,056			3,068,215
Equity:
Members’ equity	1,460,947			1,460,947
Accumulated earnings	212,790			295,986
Total equity	1,673,737			1,756,933
Total liabilities and equity	$	3,618,793		4,825,148

See accompanying notes to condensed consolidated financial statements.

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Revenue:
Natural gas sales	$	44,688		172,332
Natural gas liquids sales	—			17,244
Oil sales	277			2,085
Realized and unrealized gain (loss) on derivative instruments (including unrealized gains (losses) of $(55,904) and $181,337 in 2012 and 2013, respectively)	(6,040		)	195,483
Total revenue	38,925			387,144
Operating expenses:
Lease operating expenses	1,866			1,454
Gathering, compression, processing, and transportation	20,079			48,670
Production taxes	3,371			10,108
Exploration expenses	2,952			7,300
Impairment of unproved properties	1,295			4,803
Depletion, depreciation, and amortization	22,321			52,589
Accretion of asset retirement obligations	24			267
General and administrative	10,473			13,567
Total operating expenses	62,381			138,758
Operating income (loss)	(23,456		)	248,386
Interest expense	(24,223		)	(33,468	)
Income (loss) from continuing operations before income taxes and discontinued operations	(47,679		)	214,918
Income tax (expense) benefit	14,442			(83,725	)
Income (loss) from continuing operations	(33,237		)	131,193
Discontinued operations:
Loss from results of operations and sale of discontinued operations	(444,850		)	—
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	(478,087	)	131,193

See accompanying notes to condensed consolidated financial statements.

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Six Months ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Revenue:
Natural gas sales	$	89,822		294,278
Natural gas liquids sales	—			27,816
Oil sales	325			2,962
Realized and unrealized gain on derivative instruments (including unrealized gains of $114,498 and $61,265 in 2012 and 2013, respectively)	211,214			123,542
Gain on sale of gathering system	291,305			—
Total revenue	592,666			448,598
Operating expenses:
Lease operating expenses	2,559			2,525
Gathering, compression, processing, and transportation	31,654			89,640
Production taxes	7,113			18,727
Exploration expenses	4,756			11,662
Impairment of unproved properties	1,581			6,359
Depletion, depreciation, and amortization	38,431			92,953
Accretion of asset retirement obligations	46			531
General and administrative	19,646			26,284
Total operating expenses	105,786			248,681
Operating income	486,880			199,917
Interest expense	(48,593		)	(63,396	)
Income from continuing operations before income taxes and discontinued operations	438,287			136,521
Income tax expense	(183,969		)	(53,325	)
Income from continuing operations	254,318			83,196
Discontinued operations:
Loss from results of operations and sale of discontinued operations	(404,674		)	—
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	(150,356	)	83,196

See accompanying notes to condensed consolidated financial statements.

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

Six Months ended June 30, 2012 and 2013

(Unaudited)

(In thousands)

	2012			2013
Cash flows from operating activities:
Net income (loss)	$	(150,356	)	83,196
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion	38,477			93,484
Impairment of unproved properties	1,581			6,359
Unrealized gains on derivative instruments, net	(114,498		)	(61,265	)
Gain on sale of assets	(291,305		)	—
Loss on sale of discontinued operations	427,232			—
Deferred income tax expense	165,669			53,325
Depletion, depreciation, amortization, accretion, and impairment of unproved properties — discontinued operations	64,359			—
Unrealized losses on derivative instruments, net — discontinued operations	636			—
Deferred income tax expense — discontinued operations	12,727			—
Other	2,422			2,575
Changes in current assets and liabilities:
Accounts receivable	(15,791		)	(7,935	)
Accrued revenue	18,535			(19,763	)
Other current assets	(3,162		)	10,808
Accounts payable	(17,058		)	(1,436	)
Accrued liabilities	10,641			20,137
Revenue distributions payable	575			8,495
Other	10,300			4,417
Net cash provided by operating activities	160,984			192,397
Cash flows from investing activities:
Additions to proved properties	(4,451		)	—
Additions to unproved properties	(263,737		)	(271,003	)
Drilling costs	(377,199		)	(757,877	)
Additions to gathering systems and facilities	(47,982		)	(151,737	)
Additions to other property and equipment	(1,300		)	(1,766	)
Proceeds from asset sales	811,253			—
Changes in other assets	(257		)	3,975
Net cash from (used in) investing activities	116,327			(1,178,408	)
Cash flows from financing activities:
Issuance of senior notes	—			231,750
Borrowings (repayments) on bank credit facility, net	(275,000		)	743,000
Payments of deferred financing costs	—			(5,663	)
Other	(79		)	8,802
Net cash provided by (used in) financing activities	(275,079		)	977,889
Net increase (decrease) in cash and cash equivalents	2,232			(8,122	)
Cash and cash equivalents, beginning of period	3,343			18,989
Cash and cash equivalents, end of period	$	5,575		10,867
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	(45,064	)	(62,246	)
Supplemental disclosure of noncash investing activities:
Increase in accounts payable for additions to properties, gathering systems and facilities	$	31,593		54,051

See accompanying notes to condensed consolidated financial statements.

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

(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, natural gas liquids (NGLs), and oil onshore in the United States in unconventional reservoirs, which can generally be characterized as fractured shales and tight sand formations. Our properties are primarily located in the Appalachian Basin in West Virginia, Ohio, and Pennsylvania. During 2012 we sold our Arkoma Basin properties and our Piceance Basin properties. We also have certain midstream gathering and pipeline operations which are ancillary to our interests in producing properties. Our corporate headquarters are in Denver, Colorado.

Our consolidated financial statements as of June 30, 2013 include the accounts of Antero Resources LLC, and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Corporation (ARC) (formerly Antero Resources Appalachian Corporation) and its wholly owned subsidiaries, Antero Resources Bluestone LLC and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities). Antero Resources LLC, the stand alone parent entity, has insignificant independent assets and no operations.

(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, 2012 consolidated financial statements and notes thereto for a more complete understanding of the Company’s operations, financial position, and accounting policies. The December 31, 2012 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, 2012.

The accompanying unaudited consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (GAAP) for interim financial information, and, accordingly, do not include all of the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, the accompanying unaudited consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of June 30, 2013, and the results of its operations for the three and six months ended June 30, 2012 and 2013, and its cash flows for the six months ended June 30, 2012 and 2013. 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 June 30, 2013 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.

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

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.

(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 are volatile; 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, which may include commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. From time to time, the Company may also enter 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 $593 million at June 30, 2013 includes the following asset values by bank counterparty: BNP Paribas — $150 million; Credit Suisse — $161 million; Wells Fargo — $99 million; JP Morgan — $102 million; Barclays — $65 million; Deutsche Bank — $11 million; Union Bank — $2 million; and Toronto Dominion Bank — $1 million. Additionally, contracts with Dominion Field Services account for $2 million of the fair value. The credit ratings of certain of these banks have

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

been downgraded 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 June 30, 2013 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.

(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 nonexchange traded derivatives, such as over-the-counter commodity price swaps, basis swaps, and interest rate swaps. Valuation models used to measure fair value of these instruments consider various Level 2 inputs including (i) quoted forward prices for commodities, (ii) time value, (iii) quoted forward interest rates, (iv) current market prices and contractual prices for the underlying instruments, (v) risk of nonperformance by the Company and the counterparty, and (vi) other relevant economic measures. The Company utilizes its counterparties to assess the reasonableness of its prices and valuation techniques. To the extent a legal right of offset with a counterparty exists, the derivative assets and liabilities are reported on a net basis.

(g) Income Taxes

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

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

Antero Resources Corporation and its subsidiaries recognize deferred tax assets and liabilities for temporary differences resulting from net operating loss carryforwards for income tax purposes and the differences between the financial statement and tax basis of assets and liabilities. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted. Deferred tax assets are reduced by a valuation allowance, when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Unrecognized tax benefits represent potential future tax obligations for uncertain tax positions taken on previously filed tax returns that may not ultimately be sustained. The Company recognizes interest expense related to unrecognized tax benefits in interest expense and fines and penalties as income tax expense. The tax years 2009 through 2012 remain open to examination by the U.S. Internal Revenue Service. The Company files tax returns with various state taxing authorities which remain open to examination for tax years 2008 through 2012.

(h) Impairment of Unproved Properties

Unproved properties 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.

Impairment of unproved properties during the three months ended June 30, 2012 and 2013 was $2 million and $5 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.

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

(j) Guarantees

In November 2009 and January 2010, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million and $150 million, respectively, of 9.375% senior notes due December 1, 2017. In August 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019. In November 2012 and February 2013, Antero Finance issued $300 million and $225 million, respectively, of 6.00% senior notes due December 1, 2020. For purposes of this footnote, we collectively refer to the 2017 senior notes, the 2019 senior notes and the 2020 senior notes as the “senior notes.”

Antero Resources LLC, as the parent company (for purposes of this footnote only, the Parent Company), has no independent assets or operations. Antero Finance is a 100% indirectly owned finance subsidiary of Parent Company. The senior notes are each guaranteed on a senior unsecured basis by Parent Company and all of Parent Company’s wholly owned subsidiaries (other than Antero Finance) and certain of its future restricted subsidiaries. The guarantees are full and unconditional and joint and several. The guarantor subsidiaries may be released from those guarantees upon the occurrence of certain events, including (i) the designation of that subsidiary guarantor as an unrestricted subsidiary; (ii) the release or discharge of any guarantee or indebtedness that resulted in the creation of the guarantee of the senior notes by such subsidiary guarantor; or (iii) the sale or other disposition, including the sale of substantially all of the assets, of that subsidiary guarantor. There are no significant restrictions on Antero Finance’s ability to obtain funds from the Parent Company or the subsidiary guarantors by dividend or loan, except those imposed by applicable law. However, the indentures governing the senior notes and the Credit Facility agreement contain significant restrictions on the ability of Antero Finance or the subsidiary guarantors to make distributions to the Parent Company. Finally, the Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

(3) Sale of Piceance and Arkoma Properties — Discontinued Operations

On December 21, 2012, the Company completed the sale of its Piceance Basin assets. The $316 million of net proceeds from the sale represented the purchase price of $325 million, adjusted for expenses of the sale and estimated income, expenses, and capital costs related to the Piceance Basin properties from the October 1, 2012 effective date of the sale through December 21, 2012. The Company recognized a loss of $364 million on the sale of the Piceance Basin assets in the fourth quarter of 2012. The purchaser also assumed all of the Company’s Rocky Mountain firm transportation obligations, which totaled approximately $100 million. In connection with the sale of the Piceance Basin assets, the Company also liquidated its hedge positions related to the Piceance Basin and realized additional proceeds of approximately $100 million.

On 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 $427 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 Company recognized a loss of $432 million on the sale of the Arkoma Basin assets in the second quarter of 2012.

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

Results of operations for the three months and six months ended June 30, 2012 for the Piceance Basin and Arkoma Basin assets are shown as discontinued operations on the accompanying Consolidated Statement of Operations and Comprehensive Income (Loss) and are comprised of the following (in thousands):

	Three months			Six months
	ended			ended
	June 30, 2012			June 30, 2012
Sales of oil, natural gas, and natural gas liquids	$	35,103		82,406
Realized gains on derivative instruments	32,647			65,874
Unrealized losses on derivative instruments	(33,197		)	(636	)
Total revenues	34,553			147,644
Lease operating expenses	6,331			13,965
Gathering, compression, and transportation	14,152			30,525
Production taxes	1,264			3,098
Exploration expenses	200			412
Impairment of unproved properties	243			993
Depletion, depreciation, and amortization	31,585			63,147
Accretion of asset retirement obligations	113			219
Loss on sale of discontinued operations	427,232			427,232
Total expenses	481,120			539,591
Loss from discontinued operations before income taxes	(446,567		)	(391,947	)
Income tax (expense) benefit	1,717			(12,727	)
Net losss from discontinued operations attributable to Antero equity owners	$	(444,850	)	(404,674	)

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

(4) Long-term Debt

Long-term debt consists of the following at December 31, 2012 and June 30, 2013 (in thousands):

	December 31,		June 30,
	2012		2013
Bank credit facility (a)	$	217,000	960,000
9.375% senior notes due 2017 (b)	525,000		525,000
7.25% senior notes due 2019 (c)	400,000		400,000
6.00% senior notes due 2020 (d)	300,000		525,000
9.00% senior note (d)	25,000		25,000
Net premium	2,058		8,217
	1,469,058		2,443,217
Less amounts due within one year	25,000		25,000
Total	$	1,444,058	2,418,217

(a) Bank Credit Facility

The Company has a senior secured revolving bank credit facility (the Credit Facility) with a consortium of bank lenders. The maximum amount of the Credit Facility is $2.5 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. The borrowing base is $1.75 billion and lender commitments are $1.45 billion. Lender commitments can be increased to the full amount of the borrowing base upon approval of the lenders. The next redetermination of the borrowing base is scheduled to occur in September 2013. 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. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all of the financial covenants under the Credit Facility as of December 31, 2012 and June 30, 2013.

As of June 30, 2013, the Company had an outstanding balance under the Credit Facility of $960 million, with a weighted average interest rate of 2.1%, and outstanding letters of credit of approximately $32 million. As of December 31, 2012, the Company had an outstanding balance under the Credit Facility of $217 million, with a weighted average interest rate of 1.91%, and outstanding letters of credit of approximately $43 million. Commitment fees on the unused portion of the Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization.

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

(b) 9.375% Senior Notes Due 2017

On November 17, 2009 Antero Finance issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, the Company issued an additional $150 million of the same series of 9.375% senior notes at a premium of $6.0 million. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes are guaranteed on a full and unconditional basis and joint and severally by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015. At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

(c) 7.25% Senior Notes Due 2019

On August 1, 2011, Antero Finance issued $400 million of 7.25% senior notes due August 1, 2019 at par. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on August 1 and February 1 of each year. 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, the note holders will have the right to require Antero Finance to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

(d) 6.00% Senior Notes Due 2020

On November 19, 2012, Antero Finance issued $300 million of 6.00% senior notes due December 1, 2020 at par. In a subsequent transaction, on February 4, 2013 Antero Finance issued an additional $225 million of the 6.00% notes at 103% of par. The notes are unsecured and effectively subordinated to the Company’s Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% and 7.25% senior notes. The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries. Interest on the notes is payable on June 1 and December 1 of each year. Antero Finance may redeem all or part

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

of the notes at any time on or after December 1, 2015 at redemption prices ranging from 104.500% on or after December 1, 2015 to 100.00% on or after December 1, 2018. In addition, on or before December 1, 2015, 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 106.00% of the principal amount of the notes, plus accrued interest. At any time prior to December 1, 2015, Antero Finance may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium and accrued interest. If a change of control (as defined in the bond indenture) occurs at any time prior to January 1, 2014, Antero Finance may, at its option, redeem all, but not less than all, of the notes at a redemption price equal to 110% of the principal amount of the notes, plus accrued interest. If Antero Resources LLC undergoes a change of control, the note holders will have the right to require Antero Finance to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

(e) 9.00% Senior Note

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

(f) Treasury Management Facility

The Company has a stand-alone revolving note with a lender under the Credit Facility which provides for up to $25 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2014. At December 31, 2012 and June 30, 2013, there were no outstanding borrowings under this facility.

(5) Ownership Structure

At December 31, 2012 and June 30, 2013, 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

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.

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

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, 2012 and June 30, 2013, the Class I units had an aggregate liquidation priority, including the special allocation of 8% per annum, of $2.191 billion and $2.279 billion, respectively.

(6) Financial Instruments

The carrying values of trade receivables, trade payables, and the Credit Facility at December 31, 2012 and June 30, 2013 approximated market value. The carrying value of the Credit Facility at December 31, 2012 and June 30, 2013 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 $1.3 billion and $1.5 billion at December 31, 2012 and June 30, 2013, respectively.

(7) Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2013 (in thousands):

Asset retirement obligations — beginning of period	$	10,552
Obligations incurred	44
Accretion expense	531
Asset retirement obligations — end of period	$	11,127

(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 six months ended June 30, 2012 and 2013, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price, the Company receives the difference from the counterparty. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

The Company has no collateral from any counterparties. All but one of the Company’s 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 June 30, 2013, there were no past due receivables from or payables to any of our counterparties.

As of June 30, 2013, the Company’s positions in fixed price natural gas and oil swaps from July 1, 2013 through December 31, 2018 are summarized in the following table:

	MMbtu/day	Bbls/day	Price
Year ending December 31, 2013:
CGTAP	260,921	—	$	4.48
Dominion South	191,075	—	4.79
NYMEX-WTI	—	300	90.30
2013 Total	451,996	300
Year ending December 31, 2014:
CGLA	10,000		$	3.87
CGTAP	210,000		5.11
Dominion South	160,000		5.15
2014 Total	380,000
Year ending December 31, 2015:
CGLA	40,000		$	4.00
CGTAP	120,000		5.01
Dominion South	230,000		5.60
2015 Total	390,000
Year ending December 31, 2016:
CGLA	170,000		$	4.09
CGTAP	60,000		4.91
Dominion South	272,500		5.35
NYMEX	20,000		4.39
2016 Total	522,500

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

	MMbtu/day	Bbls/day	Price
Year ending December 31, 2017:
CGLA	420,000		$	4.27
NYMEX	140,000		4.53
CCG	70,000		4.57
2017 Total	630,000
Year ending December 31, 2018:
NYMEX	430,000		$	4.78

(b) 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, 2012 and June 30, 2013 (in thousands):

	December 31, 2012			June 30, 2013
	Balance			Balance
	sheet			sheet
	location	Fair value		location	Fair value
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	160,579	Current assets	$	205,221
Commodity contracts	Long-term assets	371,436		Long-term assets	388,694
Total asset derivatives		532,015			593,915
Liability derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current liabilities	—		Current liabilities	264
	Long-term liabilities	—		Long-term liabilities	371
Net asset value of derivatives		$	532,015		$	593,280

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

The following is a summary of realized and unrealized gains (losses) on derivative instruments and where such values are recorded in the consolidated statements of operations for the three months ended and six months ended June 30, 2012 and 2013 (in thousands):

	Statement of	Three months ended				Six months ended
	operations	June 30				June 30
	location	2012			2013	2012		2013
Realized gains on commodity contracts	Revenue	$	49,864		14,146	96,716		62,277
Unrealized gains (losses) on commodity contracts	Revenue	(55,904		)	181,337	114,498		61,265
Realized gains on commodity contracts	Discontinued operations	32,647			—	65,874		—
Unrealized losses on commodity contracts	Discontinued operations	(33,197		)	—	(636	)	—
Total gains (losses) on commodity contracts		$	(6,590	)	195,483	276,452		123,542

The following table summarizes the valuation of investments and financial instruments by the fair value hierarchy described in note 1 at June 30, 2013 (in thousands):

	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
Net derivatives asset:
Fixed price commodity swaps	$	—	593,280	—	593,280

(Continued)

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

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

	December 31, 2012					June 30, 2013
									Net amounts
					Net amounts				of assets
	Gross amounts		Gross amounts		of assets	Gross amounts	Gross amounts		(liabilities)
	of recognized		offset on		on balance	of recognized	offset on		on balance
	assets		balance sheet		sheet	assets	balance sheet		sheet
Commodity derivative assets	$	597,359	(65,344	)	532,015	656,696	(62,781	)	593,915
Commodity derivative liabilities	—		—		—	1,713	(2,348	)	(635	)

(9) Sale of Appalachian Gathering Assets

On March 26, 2012, the Company closed the 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 (subject to customary purchase price adjustments). The sale included approximately 25 miles of low pressure pipeline systems and gathering rights on 104,000 net acres held by the Company 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 a period of three years from the date of 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, a gain of approximately $291 million on the sale of the gathering system and rights was recognized during the first quarter of 2012.

(10) Contingencies

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

Table of Contents

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements

December 31, 2012 and June 30, 2013

(Unaudited)

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 the Company’s operations at several well sites are not in 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. The Company has responded to all pending orders and is actively cooperating with the relevant agencies. No fine or penalty relating to these matters has been proposed at this time, but the Company believes that these actions will result in monetary sanctions exceeding $100,000. The Company is 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.

Table of Contents

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes included elsewhere in this report.. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGL, and oil prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties, and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors” included elsewhere in this report. We do not undertake any obligation to publicly update any forward-looking statements.

In this section, references to “Antero,” “Antero Resources,” “we,” “us,” “our,” and “operating entities” refer to the subsidiaries that conduct Antero Resources LLC’s operations, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see note 1 to the consolidated financial statements included in our 2012 Form 10-K.

Our Company

Antero Resources is an independent natural gas and oil company engaged in the exploitation, development and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of June 30, 2013, we held approximately 420,000 net acres of rich gas and dry gas properties, which are located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our corporate headquarters are in Denver, Colorado.

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 dedicated to supporting the natural gas volumes we produce.

We sold our Arkoma Basin and Piceance Basin assets in 2012. Our financial statements have been recast to classify the 2012 revenues and expenses from these operations and the loss on the sale of these assets as discontinued operations in our financial statements.

Recent Events and Highlights

Financial Results and Production

For the three months ended June 30, 2013, we had net income of $131 million and EBITDAX of $133 million compared to a net loss from continuing operations for the three months ended June 30, 2012 of $33 million and EBITDAX from continuing operations of $60 million. Net income for the three months ended June 30, 2013 included $181 million of unrealized hedge gains and a provision for deferred income taxes of $84 million.

For the six months ended June 30, 2013, we generated cash flow from operations of $192 million, net income of $83 million, and EBITDAX of $251 million. For the comparative six month period ended June 30, 2012, we had cash flow from operations of $161 million, income from continuing operations of $254 million, and EBITDAX from continuing operations of $128 million. Net income of $83 million for the six months ended June 30, 2013 included $61 million of unrealized hedge gains and a provision for deferred income taxes of $53 million. Net income for the six months ended June 30, 2012 included unrealized hedge gains of $115 million, a gain on the sale of gathering assets of $291 million, and a provision for deferred income taxes of $184 million. See “—Non-GAAP Financial Measure” for a definition of EBITDAX and a reconciliation of EBITDAX to net income, the most comparable GAAP measure.

For the three months ended June 30, 2013, our production from the Appalachian Basin totaled approximately 42 Bcfe, or 458 MMcfe per day, compared to 19 Bcfe from continuing operations, or 213 MMcfe per day, for the three months ended June 30, 2012. The average price received for our production for the three months ended June 30, 2013 was $4.60 per Mcfe compared to $2.32 per

Table of Contents

Mcfe for the three months ended June 30, 2012. Average prices after the effects of commodity hedges were $4.94 per Mcfe for the three months ended June 30, 2013 compared to $4.90 for the three months ended June 30, 2012.

For the six months ended June 30, 2013, our production from the Appalachian Basin totaled approximately 76 Bcfe, or 421 MMcfe per day, compared to 35 Bcfe from continuing operations, or 195 MMcfe per day, for the six months ended June 30, 2012. The average price received for our production for the six months ended June 30, 2013 was $4.27 per Mcfe before the effects of commodity hedges compared to $2.54 per Mcfe for the six months ended June 30, 2012. Average prices after the effects of commodity hedges were $5.09 per Mcfe for the six months ended June 30, 2013 compared to $5.26 for the six months ended June 30, 2012.

2013 Capital Budget

For the six months ended June 30, 2013, our capital expenditures for drilling, leasehold, and gathering were approximately $1.18 billion. Our capital expenditure plan for 2013 is $1.95 billion, which includes $1.20 billion for drilling and completion, $250 million for leasehold acquisitions, and $500 million for construction of water handling infrastructure and gas gathering pipelines and facilities. 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

Our credit facility was amended as of June 27, 2013 to increase lender commitments from $1.2 billion to $1.45 billion. The borrowing base under the credit facility is currently $1.75 billion and is redetermined semiannually and is based on the lenders’ judgment of the volume of our proved oil and gas reserves and the estimated future cash flows from these reserves and our hedge positions. The next redetermination is scheduled to occur in September 2013.

At June 30, 2013, we had $992 million of borrowings and letters of credit outstanding under the credit facility and $458 million of available borrowing capacity, based on $1.45 billion of lender commitments at that date. The credit facility matures in May 2016.

Hedge Position

As of June 30, 2013, we had entered into hedging contracts covering a total of approximately 943 Bcfe of natural gas and oil volumes from July 1, 2013 through December 31, 2018 at a weighted average index price of $4.80 per Mcfe. These hedging contracts include hedges for the six month period ended December 31, 2013 of approximately 84 Bcfe of natural gas and oil volumes at a weighted average index price of $4.68 per Mcfe.

Principal Components of Our Cost Structure

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

· Gathering, compression, processing, and transportation. These are costs incurred to bring natural gas, NGLs, and oil to the market. Such costs include the costs to operate and maintain our low-pressure and high-pressure gathering and compression systems as well as fees paid to third parties who operate low-pressure and high-pressure gathering systems that transport our gas. It also includes costs to process and extract NGLs from our produced gas and to transport our products to market. Costs we incur for these expenses can vary based on industry drilling and production activity levels and the resulting demand fluctuations for oilfield services. We often enter into fixed-price long-term contracts that secure transportation and processing capacity that may include minimum volume commitments, the cost for which is included in these expenses.

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

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

Table of Contents

· Impairment of unproved and proved properties. These costs include unproved property impairment and costs associated with lease expirations. We could record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows. Through June 30, 2013, we have not recorded 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, NGLs, and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs to each unit of production using the units of production method.

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

· Interest expense. We finance a portion of our working capital requirements and acquisitions and development costs 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. At June 30, 2013, we also had a fixed interest rate of 9.375% on senior notes having a principal balance of $525 million, a fixed interest rate of 7.25% on senior notes having a principal balance of $400 million, and a fixed interest rate of 6.00% on senior notes having a principal balance of $525 million. We expect to continue to incur significant interest expense as we grow.

· Income tax expense. Antero Resources LLC is a partnership for income tax purposes and therefore is not subject to federal or state income taxes. The Company’s subsidiaries are subject to state and federal income taxes but are currently not in a tax paying position for regular Federal income taxes, primarily due to the current deductibility of intangible drilling costs and the deferral of unrealized commodity hedge gains for tax purposes until they are realized. We do pay some state income or franchise taxes where state income or franchise taxes are determined on a basis other than income. We have generated net operating loss carryforwards for federal income tax purposes of approximately $1.0 billion at December 31, 2012, which expire at various dates from 2024 through 2032. We have recognized the value of these net operating losses to the extent of our deferred tax liabilities. We recorded valuation allowances for deferred tax assets at December 31, 2012 of approximately $48 million primarily for capital loss and state loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

The calculation of our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that we believe are more likely than not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The financial statements included unrecognized benefits at December 31, 2012 and June 30, 2013 of $15 million that, if recognized, would result in a reduction of other long-term liabilities and an increase in noncurrent deferred tax liabilities. No impact to our 2012 effective tax rate would result from the recognition of the tax benefits.

Table of Contents

Results of Operations

Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2013

The following table sets forth selected operating data (as recast for discontinued operations) for the three months ended June 30, 2012 compared to the three months ended June 30, 2013:

	Three Months Ended June 30,						Amount of Increase
	2012			2013			(Decrease)			Percent Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	44,688		$	172,332		$	127,644		286	%
NGL sales	—			17,244			17,244			*
Oil sales	277			2,085			1,808			653	%
Realized gains on derivative instruments	49,864			14,146			(35,718		)	(72	)%
Unrealized gains (losses) on derivative instruments	(55,904		)	181,337			237,241			*
Total operating revenues	38,925			387,144			348,219			895	%
Operating expenses:
Lease operating expense	1,866			1,454			(412		)	(22	)%
Gathering, compression, processing, and transportation	20,079			48,670			28,591			142	%
Production taxes	3,371			10,108			6,737			200	%
Exploration expenses	2,952			7,300			4,348			147	%
Impairment of unproved properties	1,295			4,803			3,508			271	%
Depletion, depreciation, and amortization	22,321			52,589			30,268			136	%
Accretion of asset retirement obligations	24			267			243			1,013	%
General and administrative	10,473			13,567			3,094			30	%
Total operating expenses	62,381			138,758			76,377			122	%
Operating income (loss)	(23,456		)	248,386			271,842			*

Interest expense	(24,223		)	(33,468		)	(9,245		)	38	%
Income (loss) before income taxes	(47,679		)	214,918			262,597			*
Income tax benefit (expense)	14,442			(83,725		)	(98,167		)	*
Income (loss) from continuing operations	(33,237		)	131,193			164,430			*
Loss from discontinued operations	(444,850		)	—			444,850			*
Net income (loss) attributable to Antero members	$	(478,087	)	$	131,193		$	609,280		*

EBITDAX from continuing operations (1)	$	60,236		$	132,608		$	72,372		120	%

Total EBITDAX (1)	$	106,239		$	132,608		$	26,369		25	%

Production data:
Natural gas (Bcf)	19			39			20			104	%
NGLs (MBbl)	—			354			354			*
Oil (MBbl)	4			25			21			585	%
Combined (Bcfe)	19			42			23			115	%
Daily combined production (MMcfe/d)	213			458			245			115	%
Average prices before effects of hedges (2):
Natural gas (per Mcf)	$	2.31		$	4.37		$	2.06		89	%
NGLs (per Bbl)	$	—		$	48.70		$	*		*
Oil (per Bbl)	$	77.16		$	85.07		$	7.91		10	%
Combined (per Mcfe)	$	2.32		$	4.60		$	2.28		98	%
Average realized prices after effects of hedges (2):
Natural gas (per Mcf)	$	4.89		$	4.74		$	(0.15	)	(3	)%
NGls (per Bbl)	$	—		$	48.70		$	48.70		*
Oil (per Bbl)	$	77.16		$	80.70		$	3.54		5	%
Combined (per Mcfe)	$	4.90		$	4.94		$	0.04		1	%
Average costs (per Mcfe):
Lease operating costs	$	0.10		$	0.03		$	(0.07	)	(70	)%
Gathering, compression, processing, and transportation	$	1.04		$	1.17		$	0.13		13	%
Production taxes	$	0.17		$	0.24		$	0.07		41	%
Depletion, depreciation, amortization, and accretion	$	1.15		$	1.27		$	0.12		10	%
General and administrative	$	0.54		$	0.33		$	(0.21	)	(39	)%

Table of Contents

(1) See “—Non-GAAP Financial Measure” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX from continuing and discontinued operations to net income (loss) from continuing and discontinued operations attributable to Antero members and to cash flow provided by operating activities.

(2) Average prices shown in the table reflect the sales prices we received before and after giving effect to 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 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 $45 million from continuing operations for the three months ended June 30, 2012 to $192 million for the three months ended June 30, 2013, an increase of $147 million, or 326%. Our production increased by 115% over that same period, from 19 Bcfe from continuing operations for the three months ended June 30, 2012 to 42 Bcfe for the three months ended June 30, 2013. Net equivalent prices before the effects of realized hedge gains increased from $2.32 per Mcfe for the three months ended June 30, 2012 to $4.60 for the three months ended June 30, 2013, an increase of 98%. Increased production volumes accounted for an approximate $52 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price), and commodity price increases accounted for an approximate $95 million increase in year-over-year revenues (calculated as the change in year-to-year average price times current year production volumes). Production increases resulted from additional producing wells as a result of the ongoing Appalachian Basin drilling program. Additionally, natural gas prices were significantly higher than the depressed price levels during the previous year’s quarter, increasing from an average of $2.31 during the three months ended June 30, 2012 to $4.37 during the three months ended June 30, 2013.

Commodity hedging activities. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge treatment and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate from the fixed price we will receive on future production.

For the three months ended June 30, 2012 and 2013, our hedges resulted in realized gains of $50 million and $14 million, respectively, and unrealized gains (losses) of $(56) million and $181 million, respectively. Futures prices increased from March 31, 2012 to June 30, 2012 and decreased from March 31, 2013 to June 30, 2013, which, along with the reversal of previously recognized unrealized gains on settled hedge agreements, accounted for the unrealized losses for the three months ended June 30, 2012 and the unrealized gains for the three months ended June 30, 2013. Derivative asset or liability positions at the end of any accounting period may reverse to the extent natural gas 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 22% from the three months ended June 30, 2012 to the three months ended June 30, 2013 from $1.9 million to $1.5 million due primarily to workover expenses of $1.1 million incurred in the previous year that did not recur in 2013. On a per unit basis, lease operating expenses decreased by 70%, from $0.10 per Mcfe for the three months ended June 30, 2012 to $0.03 for the three months ended June 30, 2013, primarily because of the decrease in workover expenses. Excluding the 2012 workover expenses, lease operating expenses per Mcfe increased from $0.02 in 2012 to $0.03 in 2013.

Table of Contents

Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from $20 million for the three months ended June 30, 2012 to $49 million for the three months ended June 30, 2013, primarily due to an increase in production volumes, increased costs on firm transportation commitments and processing charges incurred in the 2013 period but not the 2012 period. On a per unit basis, gathering, compression, processing, and transportation expense increased by $0.13 per Mcfe, or 13%, for the three months ended June 30, 2013 compared to the three months ended June 30, 2012. We began processing gas in order to extract NGLs in October 2012 and this resulted in an increase of $0.13 per Mcfe. Increased gathering and compression charges of $0.15 per Mcfe were offset by a reduction of per unit firm transportation fees of $0.15 per unit. Firm transportation charges increased by $3 million for the three months ended June 30, 2013 compared to the prior year period, but decreased on a per unit basis by $0.15 per Mcfe as total production increased from the prior year period. We enter into long-term firm transportation agreements for a significant part of our current and expected future production in order to secure guaranteed capacity on major pipelines.

Production taxes. Total production taxes increased by approximately $7 million for the three months ended June 30, 2013 compared to the three months ended June 30, 2012, primarily as a result of increased production. On a per unit basis, production taxes increased from $0.17 to $0.24 per Mcfe. Production taxes as a percentage of natural gas, NGL, and oil revenues were 7.5% and 5.3% for the three months ended June 30, 2012 and 2013, respectively. Production taxes declined as a percent of production revenues because of higher per unit sales prices during the three months ended June 30, 2013 compared to the three months ended June 30, 2012 and the impact of this on the West Virginia production tax liability.

Exploration expense. Exploration expense increased from $3 million for the three months ended June 30, 2012 to $7 million for the three months ended June 30, 2013 primarily due to an increase in the cost of unsuccessful lease acquisition efforts as we increased the number of third-party lease brokers contracted in the Appalachian Basin.

Impairment of unproved properties. Impairment of unproved properties was approximately $1 million for the three months ended June 30, 2012 compared to $5 million for the three months ended June 30, 2013. The increase in impairment charges was due to an increase in expiring acreage and ongoing evaluation of our undeveloped Marcellus acreage. We charge impairment expense for expired or soon-to-be-expired leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks, expected well economics ,or future plans to develop the acreage.

DD&A. DD&A increased from $22 million for the three months ended June 30, 2012 to $53 million for the three months ended June 30, 2013, primarily because of increased production. DD&A per Mcfe increased by 10% from $1.15 per Mcfe during the three months ended June 30, 2012 to $1.27 per Mcfe during the three months ended June 30, 2013 as a result of increased depreciation on gathering systems and facilities and increased proved property costs subject to depletion.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the three months ended June 30, 2012 or 2013 for proved properties.

General and administrative expense. General and administrative expense increased from $10 million for the three months ended June 30, 2012 to $14 million for the three months ended June 30, 2013, primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses, all of which resulted from our growth in production levels and development activities. On a per unit basis, general and administrative expense decreased by 39%, from $0.54 per Mcfe during the three months ended June 30, 2012 to $0.33 per Mcfe during the three months ended June 30, 2013, primarily due to a 115% increase in production during that time. We had 132 employees as of June 30, 2012 and 184 employees as of June 30, 2013.

Interest expense. Interest expense increased from $24 million for the three months ended June 30, 2012 to $33 million for the three months ended June 30, 2013, primarily due to the issuance of a total of $525 million of 6.00% senior notes due 2020 during the fourth quarter of 2012 and the first quarter of 2013. Interest expense includes approximately $2 million of non-cash amortization of deferred financing costs for both the three months ended June 30, 2012 and 2013.

Income tax benefit (expense). Income tax benefit (expense) changed from a deferred benefit of $14 million for the three months ended June 30, 2012 to a deferred expense of $84 million for the three months ended June 30, 2013. The deferred benefit in 2012 resulted primarily from unrealized commodity derivative losses. The deferred expense in 2013 resulted from pre-tax income of $215 million which included $181 million of unrealized commodity derivative gains.

Table of Contents

At December 31, 2012, we had approximately $1.0 billion of U.S. federal net operating loss carryforwards (“NOLs”) and approximately $1.3 billion of state NOLs, which expire starting in 2024 through 2032. From time to time, there has been proposed legislation in the U.S. Congress to eliminate or limit future deductions for intangible drilling costs; such legislation could significantly affect our future taxable position if passed. The impact of any change will be recorded in the period that such legislation might be enacted.

The calculation of our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that we believe are more likely than not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. Our financial statements included unrecognized benefits at June 30, 2013 of $15 million that, if recognized, would result in a reduction of other long-term liabilities and an increase in noncurrent deferred tax liabilities. As of June 30, 2013, we had accrued approximately $0.4 million of interest on unrecognized tax benefits.

Loss from discontinued operations. The loss from discontinued operations for the three months ended June 30, 2012 resulted from the recasting of the revenues and direct expenses from the Piceance and Arkoma properties, which were sold during 2012, as discontinued operations. The loss from discontinued operations for the three months ended June 30, 2012 includes a $432 million loss on the sale of the Arkoma properties. We did not reclassify any general and administrative expenses or interest expense from continuing operations to discontinued operations.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2013

The following table sets forth selected operating data (as recast for discontinued operations) for the six months ended June 30, 2012 compared to the six months ended June 30, 2013:

	Six Months Ended June 30,						Amount of Increase
	2012			2013			(Decrease)			Percent Change
	(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales	$	89,822		$	294,278		$	204,456		228	%
NGL sales	—			27,816			27,816			*
Oil sales	325			2,962			2,637			811	%
Realized gains on derivative instruments	96,716			62,277			(34,439		)	(36	)%
Unrealized gains on derivative instruments	114,498			61,265			(53,233		)	(46	)%
Gain on sale of gathering system	291,305			—			(291,305		)	*
Total operating revenues	592,666			448,598			(144,068		)	(24	)%
Operating expenses:
Lease operating expense	2,559			2,525			(34		)	(1	)%
Gathering, compression, processing, and transportation	31,654			89,640			57,986			183	%
Production taxes	7,113			18,727			11,614			163	%
Exploration expenses	4,756			11,662			6,906			145	%
Impairment of unproved properties	1,581			6,359			4,778			302	%
Depletion, depreciation, and amortization	38,431			92,953			54,522			142	%
Accretion of asset retirement obligations	46			531			485			1,054	%
General and administrative	19,646			26,284			6,638			34	%
Total operating expenses	105,786			248,681			142,895			135	%
Operating income (loss)	486,880			199,917			(286,963		)	(59	)%

Interest expense	(48,593		)	(63,396		)	(14,803		)	30	%
Income before income taxes	438,287			136,521			(301,766		)	(69	)%
Income tax expense	(183,969		)	(53,325		)	130,644			(71	)%
Income from continuing operations	254,318			83,196			(171,122		)	(67	)%
Loss from discontinued operations	(404,674		)	—			404,674			*
Net income (loss) attributable to Antero members	$	(150,356	)	$	83,196		$	233,552		*

EBITDAX from continuing operations (1)	$	127,887		$	251,357		$	123,470		97	%

Total EBITDAX (1)	$	228,579		$	251,357		$	22,778		10	%

Production data:
Natural gas (Bcf)	35			73			38			105	%
NGLs (MBbl)	—			559			559			*
Oil (MBbl)	4			35			31			764	%
Combined (Bcfe)	35			76			41			116	%
Daily combined production (MMcfe/d)	195			421			226			116	%
Average prices before effects of hedges (2):
Natural gas (per Mcf)	$	2.53		$	4.05		$	1.52		60	%
NGLs (per Bbl)	$	—		$	49.75		$	49.75		*
Oil (per Bbl)	$	80.05		$	85.36		$	5.31		7	%
Combined (per Mcfe)	$	2.54		$	4.27		$	1.73		68	%
Average realized prices after effects of hedges (2):
Natural gas (per Mcf)	$	5.26		$	4.91		$	(0.35	)	(7	)%
NGls (per Bbl)	$	—		$	49.75		$	49.75		*
Oil (per Bbl)	$	80.05		$	79.14		$	(0.91	)	(1	)%
Combined (per Mcfe)	$	5.26		$	5.09		$	(0.17	)	(3	)%
Average costs (per Mcfe):
Lease operating costs	$	0.07		$	0.03		$	(0.04	)	(57	)%
Gathering, compression, and transportation	$	0.89		$	1.18		$	0.29		33	%
Production taxes	$	0.20		$	0.25		$	0.05		25	%
Depletion, depreciation, amortization, and accretion	$	1.08		$	1.23		$	0.15		14	%
General and administrative	$	0.55		$	0.35		$	(0.20	)	(36	)%

Table of Contents

* Not meaningful or applicable

Natural gas, NGLs, and oil sales. Revenues from production of natural gas, NGLs, and oil increased from $90 million from continuing operations for the six months ended June 30, 2012 to $325 million for the six months ended June 30, 2013, an increase of $235 million, or 261%. Our production increased by 116% over that same period, from 35 Bcfe from continuing operations for the six months ended June 30, 2012 to 76 Bcfe for the six months ended June 30, 2013. Net equivalent prices before the effects of realized hedge gains increased from $2.54 per Mcfe for the six months ended June 30, 2012 to $4.27 for the six months ended June 30, 2013, an increase of 68%. Increased production volumes accounted for an approximate $103 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price), and commodity price increases accounted for an approximate $132 million increase in year-over-year revenues (calculated as the change in year-to-year average price times current year production volumes). Production increases resulted from additional producing wells as a result of the ongoing Appalachian Basin drilling program. Additionally, natural gas prices were significantly higher than the depressed price levels during the previous year period, increasing from an average of $2.53 during the six months ended June 30, 2012 to $4.05 during the six months ended June 30, 2013.

Commodity hedging activities. For the six months ended June 30, 2012 and 2013, our hedges resulted in realized gains of $97 million and $62 million, respectively, and unrealized gains of $114 million and $61 million, respectively. Futures prices decreased from December 31, 2011 to June 30, 2012 and also from December 31, 2012 to June 30, 2013, which accounted for the unrealized gains for the six months ended June 30, 2012 and 2013. 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.

Table of Contents

Lease operating expenses. Lease operating expenses were approximately $3 million during each of the six month periods ending June 30, 2012 and 2013. On a per unit basis, lease operating expenses decreased by 57%, from $0.07 per Mcfe for the six months ended June 30, 2012 to $0.03 for the six months ended June 30, 2013, primarily because of a decrease in workover expenses and because, during the early stages of production for Appalachian Basin wells, operating and maintenance expenses are low and initial production rates are higher than for wells that have been producing for longer periods of time. Excluding the effect of workover expenses in 2012, lease operating expenses on a per unit basis were $0.03 per Mcfe during both the six months ended June 30, 2012 and 2013.

Gathering, compression, processing, and transportation expense. Gathering, compression, and transportation expense increased from $32 million for the six months ended June 30, 2012 to $90 million for the six months ended June 30, 2013, primarily due to an increase in production volumes, increased costs on firm transportation commitments, and processing charges incurred in the 2013 period but not the 2012 period. On a per unit basis, gathering, compression, and transportation expense increased by $0.29 per Mcfe, or 33%, for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. In October 2012, we began processing gas in order to extract NGLs and the resulting processing charges accounted for $0.14 per Mcfe of the increase in gathering, compression, processing, and transportation expense from the six months ended June 30, 2012 to June 30, 2013. Increased gathering, fuel, and compression charges accounted for $0.26 per Mcfe of the year-over-year increase and were offset by a $0.12 per Mcfe decrease in firm transportation charges. Firm transportation charges increased by $7 million for the six months ended June 30, 2013 compared to the prior year period, but decreased by $0.12 per Mcfe as total production increased from the prior year period. We enter into long-term firm transportation agreements for a significant part of our current and expected future production in order to secure guaranteed capacity on major pipelines.

Production taxes. Total production taxes increased by approximately $12 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily as a result of increased production. On a per unit basis, production taxes increased from $0.20 to $0.25 per Mcfe. Production taxes as a percentage of natural gas, NGL, and oil revenues were 7.9% and 5.8% for the six months ended June 30, 2012 and 2013, respectively. Production taxes declined as a percent of production revenues because of higher per unit sales prices during the six months ended June 30, 2013 compared to the six months ended June 30, 2012 and the impact of this on the West Virginia production tax liability.

Exploration expense. Exploration expense increased from $5 million for the six months ended June 30, 2012 to $12 million for the six months ended June 30, 2013 primarily due to an increase in the cost of unsuccessful lease acquisition efforts as we have increased the number of third-party lease brokers contracted in the Appalachian Basin.

Impairment of unproved properties. Impairment of unproved properties was approximately $2 million for the six months ended June 30, 2012 compared to $6 million for the six months ended June 30, 2013. The increase in impairment charges was due to an increase in expiring acreage and ongoing evaluation of our undeveloped Marcellus acreage. We charge impairment expense for expired or soon-to-be-expired leases when we determine they are impaired through lack of drilling activities or based on other factors, such as remaining lease terms, reservoir performance, commodity price outlooks, expected well economics, or future plans to develop the acreage.

DD&A. DD&A increased from $38 million for the six months ended June 30, 2012 to $93 million for the six months ended June 30, 2013, primarily because of increased production. DD&A per Mcfe increased by 14% from $1.08 per Mcfe during the six months ended June 30, 2012 to $1.23 per Mcfe during the six months ended June 30, 2013 as a result of increased depreciation on gathering systems and facilities and increased proved property costs subject to depletion.

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. No impairment expenses were recorded for the six months ended June 30, 2012 or 2013 for proved properties.

General and administrative expense. General and administrative expense increased from $20 million for the six months ended June 30, 2012 to $26 million for the six months ended June 30, 2013, primarily as a result of increased staffing levels and related salary and benefits expenses and increases in legal and other general corporate expenses, all of which resulted from our growth in production levels and development activities. On a per unit basis, general and administrative expense decreased by 36%, from $0.55 per Mcfe during the six months ended June 30, 2012 to $0.35 per Mcfe during the six months ended June 30, 2013, primarily due to a 116% increase in production during that time. We had 150 employees as of December 31, 2012 and 184 employees as of June 30, 2013.

Interest expense. Interest expense increased from $49 million for the six months ended June 30, 2012 to $63 million for the six months ended June 30, 2013, primarily due to the issuance of a total of $525 million of 6.00% senior notes due 2020 during the fourth

Table of Contents

quarter of 2012 and the first quarter of 2013. Interest expense includes approximately $2 million and $3 million of non-cash amortization of deferred financing costs for the six months ended June 30, 2012 and 2013, respectively.

Income tax benefit (expense). Income tax expense of $184 million and $53 million for the six months ended June 30, 2012 and 2013, respectively, relates to pre-tax income from continuing operations of $438 million and $137 million for the six months ended June 30, 2012 and 2013, respectively. Pre-tax income includes unrealized commodity derivative gains of $114 million and $61 million during the six months ended June 30, 2012 and 2013, respectively, and a $291 million gain on the sale of assets in 2012.

The calculation of our tax liabilities involves uncertainties in the application of complex tax laws and regulations. We give financial statement recognition to those tax positions that we believe are more likely than not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. Our financial statements included unrecognized benefits at June 30, 2013 of $15 million that, if recognized, would result in a reduction of other long-term liabilities and an increase in noncurrent deferred tax liabilities. As of June 30, 2013, we have accrued approximately $0.4 million of interest on unrecognized tax benefits.

Loss from discontinued operations. The loss from discontinued operations for the six months ended June 30, 2012 resulted from the recasting of the revenues and direct expenses from the Piceance and Arkoma properties, which were sold during 2012, as discontinued operations. The loss from discontinued operations of $405 million for the six months ended June 30, 2012 includes a $432 million loss on the sale of the Arkoma properties. We did not reclassify any general and administrative expenses or interest expense from continuing operations to discontinued operations.

Capital Resources and Liquidity

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

Our board of directors has approved a capital budget for 2013 of up to $1.95 billion. Our capital budget may be adjusted as business conditions warrant. The amount, timing, and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow, and other factors both within and outside our control.

As of June 27, 2013, our credit facility was amended to increase lender commitments to $1.45 billion from $1.2 billion. The borrowing base under the credit facility is $1.75 billion. Although we believe this increase in available borrowings together with cash flow from operations will be sufficient to meet our cash requirements for the next 12 months, we are considering other alternatives to further increase our liquidity, including selling non-core gathering assets and further capital market transactions. We may pursue a combination of these alternatives. If necessary, we will revise our capital spending plans to adjust for our available cash flow from operations and other financing sources.

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.

Table of Contents

The following table summarizes our cash flows for the six months ended June 30, 2012 and 2013:

	Six Months Ended June 30,
	2012			2013
	(in thousands)
Net cash provided by operating activities	$	160,984		$	192,397
Net cash from (used in) investing activities	116,327			(1,178,408		)
Net cash provided by (used in) financing activities	(275,079		)	977,889
Net increase (decrease) in cash and cash equivalents	$	2,232		$	(8,122	)

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $161 million and $192 million for the six months ended June 30, 2012 and 2013, respectively. The increase in cash flow from operations from the six months ended June 30, 2013 compared to the six months ended June 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 natural gas, NGL, and oil prices. 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 From (Used in) Investing Activities

During the six months ended June 30, 2013, we used cash totaling $1.2 billion in investing activities, including $271 million of undeveloped leasehold acquisitions, $758 million of drilling costs, and $152 million of expenditures for gathering systems and facilities. During the six months ended June 30, 2012, we had positive cash flows from investing activities of $116 million as a result of proceeds realized from the sale of the Marcellus gathering systems and rights and the Arkoma Basin properties totaling $811 million, partially offset by $695 million in land acquisitions, drilling and development, and gathering systems.

Cash Flow Provided by (Used in) Financing Activities

Net cash provided by financing activities for the six months ended June 30, 2013 of $978 million resulted from the issuance of $225 million of our 6.00% senior notes for net proceeds of approximately $232 million in February 2013, $743 million of net additional borrowings under our credit facility and other items of $3 million. Net cash used in financing activities of $275 million during the six months ended June 30, 2012 resulted from paying down credit facility borrowings.

Credit Facility. Our credit facility was amended as of June 27, 2013 to provide for lender commitments of $1.45 billion. The maximum borrowing base is $1.75 billion. The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions. The next redetermination is scheduled to occur in September 2013. At June 30, 2013, we had $960 million of borrowings and $32 million of letters of credit outstanding under the credit facility. At December 31, 2012, we had $217 million of borrowings and $43 million of letters of credit outstanding under the credit facility. The credit facility matures in May 2016.

The credit facility is secured by mortgages on substantially all of our properties and guarantees from our subsidiaries. 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, hedging, and certain other transactions without the prior consent of the lenders. We are required to maintain the following two financial ratios:

· a current ratio, which is the ratio of our consolidated current assets (includes unused commitment under Credit Facility and excludes derivative assets) to our consolidated current liabilities of 1.0 to 1.0 at the end of each fiscal quarter; and

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

We were in compliance with such covenants and ratios as of December 31, 2012 and June 30, 2013.

Table of Contents

Senior Notes. See Note 4 (b), (c), (d), and (e) to our condensed consolidated financial statements included elsewhere in this Form 10-Q for a description of the terms of the 9.375% senior notes due 2017 in a principal amount of $525 million, the 7.25% senior notes due 2019 in a principal amount of $400 million, the 6.00% senior notes due 2020 in a principal amount of $525 million, and the 9.00% senior note due 2013 in a principal amount of $25 million.

Treasury Management Facility. We have a stand-alone revolving note with a lender under the Credit Facility, which provides for up to $25 million of cash management obligations in order to facilitate our daily treasury management. Borrowings under the revolving note are secured by the collateral for the credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2014. We expect that the treasury management facility will be renewed for an additional one-year period when it expires. At December 31, 2012 and June 30, 2013, there were no outstanding borrowings under this facility.

Non-GAAP Financial Measure

“EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income, realized and unrealized gains or losses on interest rate derivative instruments, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized commodity hedge gains or losses, franchise taxes, stock compensation, business acquisition costs, and gain or loss on sale 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, and working capital movement, or tax position. EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations. However, our management team believes EBITDAX is useful to an investor in evaluating our financial performance because this measure:

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

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

· is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting, and by our lenders pursuant to covenants under our credit facility and the indentures governing our senior notes.

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) from continuing operations to EBITDAX from continuing operations, a reconciliation of our loss from discontinued operations to EBITDAX from discontinued operations, and a reconciliation of our total EBITDAX to net cash provided by operating activities per our consolidated statements of cash flows, in each case for the periods presented:

	Year Ended December 31,			Three Months Ended June 30,						Six Months Ended June 30,
	2012			2012			2013			2012			2013

Net income (loss) from continuing operations	$	225,276		$	(33,237	)	$	131,193		$	254,318		$	83,196
Unrealized losses (gains) on derivative contracts	(1,055		)	55,904			(181,337		)	(114,498		)	(61,265		)
Gain on sale of assets	(291,190		)				—			(291,305		)	—
Interest expense and other	97,510			24,223			33,468			48,593			63,396
Provision (benefit) for income taxes	121,229			(14,442		)	83,725			183,969			53,325
Depreciation, depletion, amortization, and accretion	102,127			22,345			52,856			38,477			93,484
Impairment of unproved properties	12,070			1,295			4,803			1,581			6,359
Exploration expense	14,675			2,952			7,300			4,756			11,662
Other	4,068			1,196			600			1,996			1,200
EBITDAX from continuing operations	284,710			60,236			132,608			127,887			251,357
Loss from discontinued operations	(510,345		)	(444,850		)	—			(404,674		)	—
Unrealized losses on derivative contracts	45,808			33,197			—			636			—
Loss on sale of assets	795,945			427,232			—			427,232			—
Provision (benefit) for income taxes	(272,553		)	(1,717		)	—			12,727			—
Depreciation, depletion, amortization, and accretion	89,124			31,698			—			63,366			—
Impairment of unproved properties	962			243			—			993			—
Exploration expense	664			200			—			412			—
EBITDAX from discontinued operations	149,605			46,003			—			100,692			—
Total EBITDAX	434,315			106,239			132,608			228,579			251,357
Interest expense and other	(97,510		)	(24,223		)	(33,468		)	(48,593		)	(63,396
Exploration expense	(15,339		)	(3,152		)	(7,300		)	(5,168		)	(11,662		)
Changes in current assets and current liabilities	9,887			(16,654		)	(10,238		)	4,040			14,723
Other	902			(1,717		)	588			(17,874		)	1,375
Net cash provided by operating activities	$	332,255		$	60,493		$	82,190		$	160,984		$	192,397

Table of Contents

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 of America. 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 2012 Form 10-K. We believe these accounting policies reflect our more significant estimates, and assumptions used in preparation of our condensed consolidated financial statements. Also, see note 2 of the notes to our audited consolidated financial statements, included in our 2012 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 June 30, 2013 that had a material effect on our financial reporting.

Off-Balance Sheet Arrangements

As of June 30, 2013, we did not have any off-balance sheet arrangements other than operating leases and contractual commitments for drilling rigs, frac services, firm transportation, and gas processing, gathering, and compression. See “—Contractual Obligations” for commitments under operating leases, drilling rig and frac service agreements, firm transportation, and gas processing, gathering, and compression service agreements.

Table of Contents

Contractual Obligations

A summary of our contractual obligations as of June 30, 2013 is provided in the following table:

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

Credit Facility(1)	$	—	$	—	$	960	$	—	$	—	$	—	$	960
Senior notes—principal(2)	25		—		—		—		525		925		1,475
Senior notes—interest(2)	111		110		110		110		85		122		648
Drilling rig and frac service commitments(3)	168		100		26		—		—		—		294
Firm transportation (4)	72		130		141		139		138		959		1,579
Gas processing, gathering, and compression service (5)	137		149		163		163		159		680		1,451
Office and equipment leases	2		4		5		4		4		17		36
Asset retirement obligations(6)	—		—		—		—		—		11		11
Total	$	515	$	493	$	1,405	$	416	$	911	$	2,714	$	6,454

(1)		Includes outstanding principal amount at June 30, 2013. This table does not include future commitment fees, interest expense, or other fees on the Credit Facility because they are floating-rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

(2)		Includes the 9.375% senior notes due 2017, the 7.25% senior notes due 2019, and the 6.00% senior notes issued in November 2012 and February 2013 and due 2020, and the $25 million note due 2013 assumed in the acquisition of Bluestone Energy Partners.

(3)		At June 30, 2013, we had contracts for the services of 14 rigs which expire at various dates from 2013 through 2016. 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 liquid markets. 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 gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGL, 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.

Table of Contents

Commodity Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas and oil production. Realized pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for crude oil. 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 hedge part of our production at 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 sales point prices. Part of our production is also hedged at NYMEX prices.

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.

At June 30, 2013, we had in place natural gas and oil swaps covering portions of our projected production from 2013 through 2018. Our commodity hedge position as of June 30, 2013 is summarized in note 8 to our consolidated financial statements included elsewhere herein. Our financial hedging activities are intended to support natural gas, NGL, 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. Our Credit Facility allows us to hedge up to 85% of our estimated production from proved reserves for up to 12 months in the future, 80% for 13 to 24 months in the future, 75% for 25 to 36 months in the future, 70% for 37 to 48 months in the future, 65% for 49 to 60 months in the future, and 65% of production for 2019. Based on our annual production and our fixed price swap contracts in place during 2013, our income before taxes for the six months ended June 30, 2013 would have decreased by approximately $0.4 million for each $0.10 decrease per MMBtu in natural gas 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 U.S. GAAP and are included in the condensed consolidated balance sheets as assets or liabilities. Fair values are adjusted for non-performance risk. Because we do not designate these hedges as accounting hedges, we do not receive accounting hedge treatment and all mark-to-market gains or losses as well as realized gains or losses on the derivative instruments are recognized in our results of operations. We present realized and unrealized gains or losses on commodity derivatives in our operating revenues as “Realized and unrealized gains (losses) on commodity derivative instruments.”

Mark-to-market adjustments of derivative instruments produce earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. At June 30, 2013 and December 31, 2012, the estimated fair value of our commodity derivative instruments was a net asset of $593 million and $532 million, respectively, comprised of current and noncurrent assets and current and noncurrent liabilities. None of these commodity derivative instruments were entered into for trading or speculative purposes.

By removing price volatility from a portion of our expected natural gas production through December 2016, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($593 million at June 30, 2013) and the sale of our oil and gas production ($66 million at June 30, 2013), which we market to energy companies.

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

Table of Contents

creditworthiness of our counterparties is subject to periodic review. We have economic hedges in place with eleven different counterparties, all but one of which is a lender under our Credit Facility. The fair value of our commodity derivative contracts of approximately $593 million at June 30, 2013 includes the following asset values by bank counterparty: BNP Paribas — $150 million; Credit Suisse — $161 million; Wells Fargo — $99 million; JP Morgan — $102 million; Barclays — $65 million; Deutsche Bank — $11 million; Union Bank — $2 million; and Toronto Dominion Bank — $1 million. Additionally, contracts with Dominion Field Services account for $2 million of the fair value. The credit ratings of certain of these banks have been downgraded 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 June 30, 2013 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 June 30, 2013, we did not have past-due receivables from or payables to any of our counterparties.

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

Interest Rate Risks

Our primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility, which has a floating interest rate. The average annual interest rate incurred on this indebtedness for the six months ended June 30, 2013 was approximately 2.0%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2013 would have resulted in an estimated $2.1 million increase in interest expense for that period. We had no outstanding interest rate derivatives for hedging purposes at June 30, 2013.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2013 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 June 30, 2013 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

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

Table of Contents

actions will result in monetary sanctions exceeding $100,000. The Company is 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.

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 2012 Form 10-K. The risks described in our 2012 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 2012 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.

Table of Contents

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: August 9, 2013	By:	/s/ GLEN C. WARREN, JR.
		Glen C. Warren, Jr.
		President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

Table of Contents

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).

4.1		Registration Rights Agreement, dated as of February 4, 2013, by and among Antero Resources Finance Corporation, the several guarantors named therein and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K (Commission File No. 333-164876) filed on February 4, 2013).

10.1*		Seventh Amendment to Fourth Amended and Restated Credit Agreement dated June 27, 2013 by and among Antero Resources Corporation and JPMorgan Chase Bank, N.A., as administrative agent for the lenders, to increase the borrowing base and lender commitments and amend the current ratio covenant under the Fourth Amended and Restated Credit Agreement dated as of November 4, 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 June 30, 2013, 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.

Antero Resources LLC 10-Q