UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2012

or

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

Commission File No. 333-164876-06

ANTERO RESOURCES LLC

(Exact name of registrant as specified in its charter)

Delaware	90-0522242
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
1625 17th Street Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(303) 357-7310

(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act: None.

Securities Registered Pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. x Yes o No

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 Act). o Yes x No

EXPLANATORY NOTE

In this Annual Report on Form 10-K, references to “Antero,” “we,” “the Company,” “us,” and “our” refer to Antero Resources LLC and the subsidiaries of Antero Resources LLC that conduct our operations (Antero Resources Appalachian Corporation and its wholly owned subsidiaries: Antero Resources Finance Corporation (“Antero Finance”), Antero Resources Arkoma LLC, Antero Resources Piceance LLC, Antero Resources Pipeline LLC and Antero Resources Bluestone LLC, unless otherwise indicated or the context otherwise requires.  Antero Resources LLC has no independent assets or operations.  Antero Resources Finance Corporation (“Antero Finance”) was formed to be the issuer of Antero’s $525 million principal amount of senior notes due 2017, $400 million principal amount of senior notes due 2019, and $525 million principal amount of senior notes due 2020.

Certain oil and gas terms used in this report are defined under the caption “Glossary of Oil and Natural Gas Terms” at the end of “Items 1 and 2.  Business and Properties” in this report.

TABLE OF CONTENTS

			Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			ii
PART I			1
	Items 1 and 2.	Business and Properties	1
	Item 1A.	Risk Factors	19
	Item 1B.	Unresolved Staff Comments	31
	Item 3.	Legal Proceedings	31
	Item 4.	Mine Safety Disclosures	31
PART II			31
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
	Item 6.	Selected Financial Data	31
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
	Item 8.	Financial Statements and Supplementary Data	50
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	50
	Item 9A.	Controls and Procedures	50
	Item 9B.	Other Information	51
PART III			51
	Item 10.	Directors, Executive Officers and Corporate Governance	51
	Item 11.	Executive Compensation	53
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	60
	Item 13.	Certain Relationships and Related Transactions and Director Independence	62
PART IV			63
	Item 14.	Principal Accountant Fees and Services	63
	Item 15.	Exhibits and Financial Statement Schedules	63
SIGNATURES			67

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this Annual Report on Form 10-K, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements.  When used, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.  These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.  When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Item 1A.  Risk Factors” in this Annual Report on Form 10-K.  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, natural gas liquids 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 report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs, and oil.  These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas, 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 this Annual Report on Form 10-K.

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Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be measured in an exact way.  The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers.  In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.  If significant, such revisions would change the schedule of any further production and development drilling.  Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs, and oil that are ultimately recovered.

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

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

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

iii

PART I

Items 1 and 2.Business and Properties

Our Company

Antero Resources is an independent oil and natural gas company engaged in the exploration, development and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of December 31, 2012, we held approximately 371,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our corporate headquarters are in Denver, Colorado.

The following table provides a summary of selected operating data of our Appalachian Basin natural gas, NGL, and oil assets as of the date and for the period indicated.

	At December 31, 2012						Three months ended December 31, 2012
	Proved reserves (Bcfe)(1)	PV-10 (in millions)(2)		Net proved developed wells(3)	Total net acres(4)	Gross potential drilling locations(5)	Average net daily production (MMcfe/d)
Appalachian Basin:
Marcellus Shale	4,796	$	1,766	122	294,000	3,046	311
Upper Devonian	10	$	9	2	—	1,250	4
Utica Shale	123	$	148	2	77,000	627	1
Total	4,929	$	1,923	126	371,000	4,923	316

(1)Estimated proved reserve volumes and values were calculated using the unweighted twelve-month average of the first-day-of-the-month reference prices for the period ended December 31, 2012, which were $2.78 per Mcf for natural gas, $19.61 per bbl for NGLs and $95.05 per bbl for oil.

(2)PV-10 is a non-GAAP financial measure. For a reconciliation of PV-10 to the standardized measure, please see “Our Operations—Estimated Proved Reserves.”

(3)Does not include 256 gross (224 net) shallow vertical wells that were acquired in conjunction with leasehold acreage acquisitions.

(4)Net acres allocable to the Upper Devonian are included in the net acres allocated to the Marcellus Shale because the Upper Devonian and the Marcellus Shale are multi-horizon shale formations attributable to the same leases.

(5)See Item 1A. Risk Factors for risks and uncertainties related to developing our potential well locations.

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year project inventory.

We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. We have drilled and operated 520 wells from inception through December 31, 2012, with a success rate of approximately 98%.  We have a multi-year drilling inventory and have approximately 4,900 potential well locations on our existing leasehold acreage, both proven and unproven.

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

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

2012 Developments and Highlights

Redeployment of Capital Resources to Appalachian Basin

We sold our Arkoma Basin assets in June 2012 and our Piceance Basin assets in December 2012 for total consideration of approximately $844 million of cash proceeds, which was used to pay down our borrowings under our senior secured revolving credit facility (our “Credit Facility”).  Ultimately, the capital from the sales of these properties has been or will be invested in our Appalachian Basin properties in the Marcellus and Utica Shale plays, where we believe we can achieve more favorable risked rates of return than were obtained in the Arkoma and Piceance Basins.  We are experiencing stronger well performance in the Appalachian Basin and better pricing because of the closer proximity of the Appalachian Basin to high density population centers and the related high demand for natural gas.  Additionally, much of our projected Appalachian Basin production is liquids rich, high-BTU content gas that we expect will yield higher prices, particularly after the rich gas is processed to yield NGLs.

During 2012, we grew our Appalachian Basin proved reserves by 2,085 Bcfe, or 73%, and have replaced approximately the same quantity of reserves divested in 2012.  During 2012, we drilled 64 horizontal wells in the Marcellus and Utica Shales, all of which were successful.  We have also added significantly to our Appalachian Basin acreage position through the acquisition of approximately 157,000 acres during 2012, including a significant position in the Utica Shale play in Ohio.  Our 2012 year-end acreage position in the Appalachian Basin was approximately 371,000 net acres, and we had a multi-year inventory of approximately 4,900 potential drilling locations in the Marcellus and Utica Shale plays at that date.

During 2012, we also sold a portion of our Marcellus Shale gathering system assets, along with exclusive rights to gather and compress our natural gas for a 20-year period within an area of dedication to a third-party midstream provider, for $376 million.  We are committed to deliver minimum annual volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies.  The third-party midstream provider is obligated to incur all future capital costs to build out gathering systems and compression facilities within the area of dedication.  We reinvested the proceeds from the transaction into development drilling and land acquisition.

In connection with the redeployment of capital resources to the Appalachian Basin, we also streamlined our operating and capital structure by transferring the ownership of our Arkoma, Piceance, and Pipeline operating subsidiaries to Antero Resources Appalachian Corporation, which will be our primary employer and operating company going forward.  We believe this simpler structure will provide both greater operating efficiencies and increased transparency to capital and credit markets as we finance our expanding capital budgets.

Our financial statements included elsewhere herein have been recast to show the results of the Arkoma Basin and Piceance Basin operations for all periods presented in discontinued operations.

Reserves, Production, and Financial Results

As of December 31, 2012, our estimated proved reserves were 4.9 Tcfe, consisting of 3.7 Tcf of natural gas, 203 MMBbl of NGLs and 3 MMBbl of oil. As of December 31, 2012, 75% of our estimated proved reserves by volume were natural gas and 21% were proved developed. From December 31, 2007 through December 31, 2012, we have increased our estimated proved reserves at a compounded annual growth rate of 84%, while our net production has increased over the three-year period ended December 31, 2012 at a compounded annual growth rate of 47% to an estimated 334 MMcfe/d in 2012 (including both continuing and discontinued operations). Our net production averaged an estimated 368 MMcfe/d in the fourth quarter of 2012 (including 47 MMcfe/d attributable to our Piceance Basin properties that were sold in mid-December 2012).

For the year ended December 31, 2012, we generated cash flow from operations of $332 million, a net loss of $285 million and EBITDAX of $434 million.  The net loss in 2012 includes, (i) a pre-tax loss of $796 million on the sale of the Arkoma and Piceance Basin properties, (ii) deferred tax benefit related to the loss on the sale of the Arkoma and Piceance properties and discontinued operations of $273 million, (iii) a pre-tax gain on the sale of certain Appalachian gathering systems of $291 million, and (iv) a noncash tax provision related to continuing operations of $121 million.  In contrast, for the year ended December 31, 2011, we generated cash flow from operations of $266 million, net income of $393 million, and EBITDAX of $341 million.  See “Item 6.  Selected Financial Data” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

2

Hedge Position

As of December 31, 2012, we had entered into hedging contracts covering a total of approximately 757 Bcfe of our projected natural gas and oil production from January 1, 2013 through December 31, 2018 at a weighted average index price of $4.88 per MMBtu.  For the year ending December 31, 2013, we have hedged approximately 115 Bcfe of our projected natural gas and oil production at a weighted average index price of $4.93 per MMBtu.  We believe this hedge position provides us with protection to future cash flows to support our operations and capital spending plans for 2013.

Credit Facility Availability

Our current borrowing base under the Credit Facility is $1.22 billion and lender commitments are $700 million.  Lender commitments under the Credit Facility can be expanded from $700 million to the full $1.22 billion borrowing base upon bank approval.  The borrowing base under the Credit Facility is redetermined semi-annually and is based on the estimated future cash flows from our proved natural gas, NGL, and oil reserves and our hedge positions.  The next redetermination is scheduled to occur in May 2013.  The Credit Facility provides for a maximum availability of $2.5 billion.  At December 31, 2012, we had $260 million of borrowings and letters of credit outstanding under the Credit Facility and $440 million of available borrowing capacity, based on $700 million of lender commitments at that date.  Pro forma for the issuance of $225 million of 6.00% senior notes due 2020 subsequent to year-end, we would have had $657 million of available borrowing capacity at December 31, 2012.  The Credit Facility matures in May 2016.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Debt Agreements and Contractual Obligations — Senior Secured Revolving Credit Facility” for a description of the Credit Facility agreement.

Senior Notes Issuance

On November 19, 2012, we issued $300 million of 6.00% senior notes due December 2020 at par.  On February 4, 2013, we issued an additional $225 million of the 6.00% senior notes at 103% of par.  We used the proceeds to pay down amounts outstanding under the Credit Facility, for development of our properties, and for general corporate purposes.

2012 Capital Spending and 2013 Capital Budget

For the year ended December 31, 2012, our capital expenditures were approximately $1.69 billion for drilling, leasehold, and gathering.  Our capital budget for 2013 is $1.65 billion, including $1.15 billion for drilling and completion, $350 million for the construction of gathering pipelines and facilities in the Appalachian Basin (including $150 million for water-handling infrastructure, primarily in the Marcellus Shale) and $150 million for leasehold. We do not budget for acquisitions. Substantially all of the $1.15 billion allocated for drilling and completion is allocated to our operated drilling in rich gas areas. Approximately 87% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 13% is allocated to the Utica Shale. During 2013, we plan to operate an average of 12 drilling rigs in the Marcellus Shale and 2 drilling rigs in the Utica Shale. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.

Corporate Sponsorship

We began operations in 2004 and the Company, as it exists today, was formed in October 2009.  We have funded our development and operating activities primarily through equity capital raised from private equity sponsors and institutional investors, issuance of debt securities, sales of non-core assets, borrowings under our bank credit facilities, and operating cash flows.  Our primary private equity sponsors are affiliates of Warburg Pincus, Yorktown Energy Partners and Trilantic Capital Partners.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 1625 17th Street, Denver, Colorado 80202 and our telephone number is (303) 357-7310. Our website is located at http://www.anteroresources.com.

We make available, our Annual Reports on Form 10-K and our Quarterly Reports on Form 10-Q. These documents are located on our website at http://www. anteroresources.com — by selecting the “Investor Info” link and then selecting the “SEC Filings” link.

The above information is available to anyone who requests it and is free of charge either in print from our website or upon request by contacting Chad Green, Finance Director, using the contact information listed above. Information on our website is not incorporated into this Annual Report or our other securities filings and is not a part of them.

3

Our Operations

Estimated Proved Reserves

The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”).

Reserves Presentation

The following table summarizes our estimated proved reserves and related standardized measure and PV-10 at December 31, 2010, 2011 and 2012.  Our estimated proved reserves as of December 31, 2012 are based on evaluations prepared by our internal reserve engineers, which have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”).  Our estimated proved reserves as of December 31, 2011 were based on evaluations prepared by our internal reserve engineers, which were audited by D&M and Ryder Scott & Company (“Ryder Scott”).  Over 99% of our estimated proved reserves as of December 31, 2010 were prepared by D&M or Ryder Scott.  We refer to these firms collectively as our independent engineers. Copies of the summary reports of D&M with respect to our reserves at December 31, 2012 are filed as Exhibits 99.1 and 99.2, respectively, to this Annual Report on Form 10-K.  The information in the following table does not give any effect to or reflect our commodity hedges.

	At December 31,
	2010			2011			2012
Estimated proved reserves:
Proved developed reserves:
Natural gas (Bcf)	400			718			828
NGLs (MMBbl)	9			19			36
Oil (MMBbl)	1			2			1
Total equivalent proved developed reserves (Bcfe)	457			844			1,047
Proved undeveloped reserves:
Natural gas (Bcf)	2,143			3,213			2,866
NGLs (MMBbl)	95			145			167
Oil (MMBbl)	9			15			2
Total equivalent proved undeveloped reserves (Bcfe)	2,774			4,173			3,882
Total estimated proved reserves (Bcfe)	3,231			5,017			4,929
Proved developed producing (Bcfe)	416			804			935
Proved developed non-producing (Bcfe)	41			40			112
Percent developed	14		%	17		%	21		%
PV-10 (in millions)(1)	$	1,466		$	3,445		$	1,923
Standardized measure (in millions)(1)	$	1,097		$	2,470		$	1,601

(1)PV-10 was prepared using average yearly prices computed using SEC rules, discounted at 10% per annum, without giving effect to taxes.  PV-10 is a non-GAAP financial measure.  We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure.  While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies.  Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis.  The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax.  For more information about the calculation of standardized measure, see footnote 16 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.

The following table sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows before income tax (PV-10), the present value of those net cash flows after income tax (standardized measure) and the prices used in projecting future net cash flows at December 31, 2010, 2011 and 2012:

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	At December 31,
(In millions, except per Mcf data)	2010(1)			2011(2)			2012(3)
Future net cash flows	$	5,990		$	11,470		$	7,221
Present value of future net cash flows:
Before income tax (PV-10)	$	1,466		$	3,445		$	1,923
Income taxes	$	(369	)	(975		)	(322		)
After income tax (Standardized measure)	$	1,097		$	2,470		$	1,601

(1)12-month average prices used at December 31, 2010 were $4.18 per Mcf for the Arkoma Basin, $3.93 per Mcf for the Piceance Basin and $4.51 per Mcf for the Appalachian Basin.

(2)12-month average prices used at December 31, 2011 were $3.90 per Mcf for the Arkoma Basin, $3.84 per Mcf for the Piceance Basin and $4.16 per Mcf for the Appalachian Basin.

(3) 12-month average prices used at December 31, 2012 were $2.78 per Mcf for natural gas, $19.61 per bbl for NGLs, and $95.05 per bbl for oil. (all reserves in Appalachian Basin).

Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Prices for 2010, 2011, and 2012 were based on 12-month unweighted average of the first-day-of-the-month pricing, without escalation. Costs are based on costs in effect for the applicable year without escalation.  There can be no assurance that the proved reserves will be produced as estimated or that the prices and costs will remain constant.  There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.

Changes in Proved Reserves During 2012

The following table summarizes the changes in our estimated proved reserves during 2012 (in Bcfe):

Proved reserves, December 31, 2011	5,017
Extensions, discoveries, and other additions	1,951
Price and performance revisions	222
Sales of reserves in place (1)	(2,174	)
Production	(87	)
Proved reserves, December 31, 2012	4,929

(1)Includes 2012 production from Arkoma and Piceance Basins of 35 Bcfe.

Extensions, discoveries, and other additions during 2012 of 1,951 Bcfe were added through the drillbit in the Marcellus and Utica Shales, including the addition of 709 Bcfe attributable to NGLs and oil. Downward price revisions resulted in a reduction of proved reserves of 102 Bcfe and performance revisions increased proved reserves by 324 Bcfe.  Sales of proved reserves of 2,174 Bcfe resulted from the sale of our Arkoma and Piceance Basin properties.  Our estimated proved reserves as of December 31, 2012 totaled approximately 4.9 Tcfe.  Our proved developed reserves increased year over year by 24% to 1,047 Bcfe at December 31, 2012.

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves.  The following table summarizes the changes in our estimated proved undeveloped reserves during 2012 (in Bcfe):

Proved undeveloped reserves, December 31, 2011	4,173
Extensions, discoveries, and other additions	1,692
Price and performance revisions	(233	)
Sales of reserves in place	(1,750	)
Proved undeveloped reserves, December 31, 2012	3,882

Extensions, discoveries, and other additions during 2012 of 1,692 Bcfe proved undeveloped reserves were added through the drillbit in the Marcellus and Utica Shales, including the addition of 613 Bcfe attributable to NGLs and oil. Downward price revisions resulted in a reduction of proved undeveloped reserves by 95 Bcfe and performance revisions reduced proved undeveloped reserves by 138 Bcfe.  Sales of proved undeveloped reserves of 1,750 Bcfe resulted from the sale of our Arkoma and Piceance Basin properties.  Our estimated proved undeveloped reserves as of December 31, 2012 totaled approximately 3.9 Tcfe.

During the year ended December 31, 2012, we converted our beginning Appalachian Basin proved undeveloped reserves to proved developed reserves at a rate of 13%.  The Company incurred costs of approximately $396 million in 2012 to develop proved undeveloped reserves.  Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2012 are approximately $3.3 billion over the next five years, which we expect to finance through cash flow from

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operations, borrowings under our Credit Facility, sales of non-core assets, and other sources of capital financing. Our drilling programs to date have focused on proving our undeveloped leasehold acreage through delineation drilling.  While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves.  All of our proved undeveloped reserves are expected to be developed over the next five years.  See “Item 1A. Risk Factors—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.  Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

Preparation of Reserve Estimates

Our proved reserve estimates as of December 31, 2012 included in this report were prepared by our internal reserve engineers in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  The internally prepared reserve estimates were audited by our independent reserve engineers.  Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.  The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our internal staff of petroleum engineers and geoscience professionals work closely with our independent engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent engineers in their reserve auditing process.  Periodically, our technical team meets with the independent engineers to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Our internally prepared reserve estimates and related reports are reviewed and approved by our Vice President of Reserves, Planning & Midstream, Ward McNeilly, and our Vice President of Production, Kevin J. Kilstrom.  Mr. McNeilly has been with the Company since October 2010.  Mr. McNeilly has 34 years of experience in oil and gas operations, reservoir management, and strategic planning.  From 2007 to October 2010 Mr. McNeilly was the Operations Manager for BHP Billiton’s Gulf of Mexico operations.  From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP.  From 1979 through 1996 Mr. McNeilly served in various domestic and international operations and reservoir and asset management positions with Amoco.  Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada.

Mr. Kilstrom has served as Vice President of Production since June 2007.  Mr. Kilstrom was a Manager of Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007.  Prior to AGL, Mr. Kilstrom was with Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2007 and as a Business Unit Manager for Marathon’s Powder River coal bed methane assets from 2001 to 2003.  Mr. Kilstrom also served as a member of the board of directors of three Marathon subsidiaries from October 2003 through May 2005.  Mr. Kilstrom was an Operations Manager and reserve engineer at Pennaco Energy from 1999 to 2001.  Mr. Kilstrom was at Amoco for more than 22 years prior to 1999 where he served in various operating roles with a focus on unconventional resources.  Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul University.  Our senior management also reviews our reserve estimates and related reports with Mr. McNeilly and Mr. Kilstrom and other members of our technical staff.  Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.

Proved reserves are those quantities of oil, natural gas, and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations.  The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate.  To achieve reasonable certainty, we and the independent engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.  The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available downhole and production data, seismic data, and well test data.

Production, Revenues and Price History

Natural gas, NGLs, and oil are commodities; therefore, the price that we receive for our production is largely a function of market supply and demand.  While demand for natural gas in the United States has increased dramatically since 2000, natural gas and NGL supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and gas from various shale formations throughout the United States.  Demand is impacted by general economic conditions, weather and other seasonal conditions.  Over or under supply of natural gas can result in substantial price volatility.  Historically, commodity prices have been volatile, and we expect that volatility to continue in the future.  A substantial or extended decline in gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of gas reserves that may be economically produced and our ability to access capital markets.  See “Item 1A. Risk Factors — Natural gas prices are volatile.  A substantial or extended decline in natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

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The following table sets forth information regarding our production, our revenues and realized prices, and production costs from continuing operations in the Appalachian Basin for the years ended December 31, 2010, 2011, and 2012. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Continuing Operations Data- Appalachian Basin

	Year Ended December 31,
	2010		2011		2012
Production data:
Natural gas (Bcf):	11		45		87
NGLs (MBbl):	—		—		71
Oil (MBbl):	—		2		19
Total combined production (Bcfe)	11		45		87
Average daily combined production (MMcfe/d)	30		124		239
Gas and oil production revenues (in millions)	$	47	$	195	$	265
Average prices:
Natural gas (per Mcf)	$	4.39	$	4.33	$	2.99
NGLs (per Bbl)	$	—	$	—	$	52.09
Oil (per Bbl)	$	—	$	97.19	$	80.34
Combined average prices before effects of hedges (per Mcfe)(1)	$	4.39	$	4.33	$	3.03
Combined realized prices after-effects of hedges (per Mcfe)(1)	$	5.78	$	5.44	$	5.08
Average costs per Mcfe:
Lease operating costs	$	0.11	$	0.10	$	0.07
Gathering, compression and transportation	$	0.85	$	0.83	$	1.04
Production taxes	$	0.27	$	0.26	$	0.23
Depreciation, depletion, amortization and accretion	$	1.71	$	1.24	$	1.17
General and administrative	$	2.03	$	0.74	$	0.52

(1)Average prices shown reflect both of the before-and-after effects of our realized commodity hedging transactions.  Our calculation of such 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.

Discontinued Operations Data- Arkoma and Piceance Basins

The table above does not include the following production or revenue from discontinued operations from the Arkoma and Piceance Basin properties which were sold in 2012:

Production (combined Bcfe)	36		44		35
Gas, NGL and oil production revenues (in millions)	$	159	$	197	$	125

See footnote 3 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K for the results of discontinued operations.

Productive Wells

As of December 31, 2012, we had a total of 381 gross (341 net) producing wells, averaging an 88% working interest.  This well count includes 256 gross and 224 net shallow vertical wells that were acquired in conjunction with leasehold acreage acquisitions.  Our wells are gas wells, many of which also produce oil, condensate and NGLs.  We do not have interests in any wells that only produce oil or NGLs.

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Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2012.  A majority of our developed acreage is subject to liens securing our Credit Facility.  Approximately 55% of our Marcellus acreage and 23% of our Utica acreage is held by production.  Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

	Developed Acres		Undeveloped Acres		Total Acres
Basin	Gross	Net	Gross	Net	Gross	Net
Marcellus	20,078	19,740	366,376	274,035	386,454	293,775
Utica	1,645	1,272	91,963	75,540	93,608	76,812
Other	—	—	6,609	6,599	6,609	6,599
Total	21,723	21,012	464,948	356,174	486,671	377,186

Undeveloped Acreage Expirations

The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2012 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such acreage is extended or renewed.

	Gross	Net
2013	16,618	10,023
2014	9,151	5,624
2015	30,374	19,408

Drilling Activity

The following table summarizes our drilling activity for the years ended December 31, 2010, 2011 and 2012. Gross wells reflect the sum of all wells in which we own an interest and includes historical drilling activity in the Appalachian, Arkoma, and Piceance Basins. Net wells reflect the sum of our working interests in gross wells.

	Year Ended December 31,
	2010		2011		2012
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	128	24	135	65	106	91
Dry	—	—	—	—	—	—
Total development wells	128	24	135	65	106	91
Exploratory wells:
Productive	56	22	74	30	22	17
Dry	11	5	—	—	—	—
Total exploratory wells	67	27	74	30	22	17

Our Core Operating Area — Appalachian Basin — Marcellus and Utica Shales

Our properties in the Appalachian Basin are located in northern West Virginia, southeastern Ohio, and southeastern Pennsylvania.  As of December 31, 2012, we had approximately 371,000 net leasehold acres in the Appalachian Basin containing rights to the Marcellus Shale and the Utica Shale, 48% of which was held by production.  For the year ended December 31, 2012, we had 239 MMcfe/d of average net daily production from the Appalachian Basin.

As of December 31, 2012, we had a total of 381 gross (341 net) producing wells in the area.  This well count includes 256 gross and 224 net shallow vertical wells that were acquired in conjunction with leasehold acreage acquisitions. From March 2009, when we drilled our first well in the Appalachian Basin, through December 31, 2012, we have completed a total of 125 gross (118 net) horizontal wells and 1 gross (1 net) vertical well in the area.  We completed 64 gross (60 net) horizontal wells in 2012.  We have an additional 40 gross (39 net) wells drilling or waiting on completion as of December 31, 2012.  As of mid-March 2013, we have 13 drilling rigs operating in the Appalachian Basin.  In addition to the 13 rigs, we employ 2 small drilling rigs to drill certain wells to the horizontal kickoff point. As of December 31, 2012, we had approximately 4,900 gross undrilled horizontal well locations in the basin.

In October 2012, the MarkWest operated Sherwood I facility, with an Antero contracted capacity of 200 MMcf/d, commenced operations in the Marcellus Shale. We have contracted for an additional 200 MMcf/d at the Sherwood II, processing plant, which is currently under construction and is expected to be operational in the second quarter of 2013. We have also contracted for 200 MMcf/d at the Sherwood III, processing plant, which is expected to be operational in the fourth quarter of 2013. We have a total of 550 MMcf/d of

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contracted capacity in the Sherwood I, II and III processing facilities. We have further committed to capacity in a fourth 200 MMcf/d processing plant, Sherwood IV, which could be operational during the second quarter of 2014, contingent on the timing of the final decision to install the fourth plant. In addition, we have contracted capacity at the Seneca I processing plant in the Utica Shale. The Seneca I processing plant will have a capacity of 200 MMcf/d and is expected to be operational in the fourth quarter of 2013. We will have a total of 150 MMcf/d of contracted capacity in the Seneca I processing facility. We expect to have 50 MMcf/d of interim processing capacity in MarkWest’s Cadiz processing facility beginning late in the second quarter of 2013.  We have secured 905,000 MMBtu/d of long-haul firm transportation or firm sales capacity with various entities, including 460,000 MMBtu/d of back-haul firm transportation to the Gulf Coast. We have also committed to 20,000 Bbl/d of ethane takeaway capacity on the Enterprise ATEX pipeline to Mont Belvieu, which we expect to go into service in early 2014. We continue to actively identify and evaluate additional processing and takeaway capacity to enhance the value of both our Marcellus and Utica Shale positions.

Gathering Systems

As of December 31, 2012, we owned and operated approximately 54 miles of gathering pipelines and two compressor stations in West Virginia and Pennsylvania to support our drilling activities in the Marcellus Shale play.  During 2012, we sold 33 miles of gathering lines and entered into a contract with a third party to provide gas gathering and compression services for a significant part of our Marcellus Shale production. Eight additional compressor stations, which are owned and operated by third parties, are connected to the gathering systems and provide compression and dehydration services on a fixed fee basis. At year end 2012, we had approximately 28 miles of Antero-owned gathering lines and two compressor stations under construction to support our planned 2013 drilling activities.

Takeaway Capacity

We have contracted for firm transportation for approximately 564,000 MMBtu per day on the Columbia Gas Transmission Pipeline and 460,000 MMBtu per day on the Columbia Gulf Pipeline.  The contracts begin from various dates from 2009 through November 1, 2014.  Columbia Pipeline contracts for 10,000 MMBtu per day expire in 2013; the remainder of the commitments expire at various dates from 2017 through 2025.  We also have firm transportation on the Equitrans pipeline for 50,000 MMBtu per day for a ten-year term, which began on August 1, 2012. We have firm transportation on the M3 Appalachia Gathering system for 100 MMBtu per day beginning with the in-service date of the system (projected to be May 1, 2013). We also have 3,500 MMBtu per day of firm transportation capacity on the Dominion Transmission Gateway expansion project for a term of 10 years from the initial in-service date of September 2012. In addition to the firm transportation that we control, we also have term firm sales commitments to third parties who hold firm capacity on downstream interstate pipelines, or will utilize our firm transportation, for approximately 250,000 MMBtu per day.  Of the 250,000 MMBtu per day of firm sales, 100,000 MMBtu per day utilizes our firm transportation capacity.  In December 2011, we entered into an agreement for firm transportation of 20,000 Bbl/d of ethane on the Enterprise Products Partners L.P. ATEX pipeline from Appalachia to Mont Belvieu, Texas.  The pipeline is expected to be in service in the first quarter of 2014.

We market the majority of the natural gas production from properties we operate for both our account and the account of the other working interest and royalty owners in these properties.  We sell substantially all of our production to a variety of purchasers under short-term contracts or spot gas purchase contracts with terms ranging from one day to several months, all at market prices.  We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business.

Based on the current demand for natural gas, NGLs, and oil and availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations.  See “Note 2(o)—Concentrations of Credit Risk” in our consolidated financial statements for the years ended December 31, 2010, 2011 and 2012 included in Item 8 of this Annual Report on Form 10-K.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards.  As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition.  Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.  Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties.  Burdens on properties may include:

·customary royalty interests;

·liens incident to operating agreements and for current taxes;

·obligations or duties under applicable laws;

·development obligations under natural gas leases; or

·net profits interests.

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Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months.  However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation.  In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer.  This can also lessen seasonal demand fluctuations.  These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do.  Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis.  These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel.  In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices.  Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.  Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.  In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties.

Regulation of the Natural Gas and Oil Industry

Our operations are substantially affected by federal, state and local laws and regulations.  In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations.  All of the jurisdictions in which we own or operate producing natural gas and oil properties have statutory provisions regulating the exploration for and production of natural gas and oil, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells.  Our operations are also subject to various conservation laws and regulations.  These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties.  The regulatory burden on the industry increases the cost of doing business and affects profitability.  Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted.  Therefore, we are unable to predict the future costs or impact of compliance.  Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Environmental Protection Agency (“EPA”), the Federal Energy Regulatory Commission (“FERC”), and the courts.  We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.  However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Natural Gas and Oil

The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations.  Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations.  All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells.  The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density.  Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

We own interests in properties located onshore in three U.S. states.  These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells,

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and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells.  The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells.  Some states have the power to prorate production to the market demand for oil and gas.

The failure to comply with these rules and regulations can result in substantial penalties.  Our competitors in the natural gas and oil industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC.  FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.  Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis.  FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

In the past, the federal government has regulated the prices at which natural gas could be sold.  While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.  Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993.  The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (“NGA”) and by regulations and orders promulgated under the NGA by FERC.  In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Beginning in 1992, FERC issued a series of orders to implement its open access policies.  As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas.  Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The Domenici Barton Energy Policy Act of 2005 (“EP Act of 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry.  Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority.  The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day.  The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce.  On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing.  The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person.  The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704.  The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing.  Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.  It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704.  Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

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On November 20, 2008, FERC issued Order 720, a final rule on the daily scheduled flow and capacity posting requirements.  Under Order 720, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day and interstate pipelines are required to post information regarding the provision of no-notice service. In October 2011, Order 720, as clarified, was vacated by the Court of Appeals for the Fifth Circuit with respect to its application to non-interstate pipelines. In December 2011, the Fifth Circuit confirmed that Order 720, as clarified, remained applicable to interstate pipelines with respect to posting information regarding the provision of no-notice service.

We cannot accurately predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold.  Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts.  The natural gas industry historically has been very heavily regulated.  Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by FERC will continue.  However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters.  Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations.  State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements.  Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA.  We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company.  However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”) and regulations promulgated thereunder by the Commodity Futures Trading Commission (“CFTC”).  The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity.  The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies.  The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state.  Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.  Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take.  We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply.  These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings.  In addition, these laws and regulations may restrict the rate of production.

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The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

National Environmental Policy Act

Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act (the “NEPA”).  NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency prepares an Environmental Assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project.  If impacts are considered significant, the agency will prepare a more detailed environmental impact study (“EIS”) that is made available for public review and comment.  All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA.  This environmental impact assessment process has the potential to delay or limit, or increase the cost of, the development of natural gas and oil projects.  Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred.  Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  We are able to control directly the operation of only those wells with respect to which we act as operator.  Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us.  We generate materials in the course of our operations that may be regulated as hazardous substances but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes.  RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes.  However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws.  Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future.  A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position.  In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that are regulated as hazardous wastes.  Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years.  Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal.  In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control.  These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

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Water Discharges

The Federal Water Pollution Control Act(the “Clean Water Act”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into federal and state waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state.  The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers.  Obtaining permits has the potential to delay the development of natural gas and oil projects.  These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil.  We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof.  We are currently undertaking a review of recently acquired natural gas properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.  These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.  The need to obtain permits has the potential to delay the development of oil and natural gas projects.  Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.  For example, on August 16, 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs.  With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted:  wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells.  All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012.  However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015.  These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013.  We are currently reviewing this new rule and assessing its potential impacts on our operations.  Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our costs of development and production, which costs could be significant.  However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of “Greenhouse Gas” Emissions

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.  These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.  In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, which include certain of our operations.  We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.  If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may

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include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.  Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.  Severe limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.  Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations as does most of the domestic oil and gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels.  In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations.  In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. Although we do not have insurance policies in effect that are intended to provide coverage for third party pollution losses of a gradual nature having gone undetected for a period of time that allegedly had arisen from our hydraulic fracturing operations, we believe our general liability and excess liability insurance policies would cover third-party pollution losses, including associated legal expenses, that are of a sudden and accidental nature that are alleged to have arisen from or are related to our hydraulic fracturing operations, subject to the terms of such policies.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees.  In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens.  We believe that our operations are in substantial compliance with the applicable worker health and safety requirements.

Endangered Species Act

The federal Endangered Species Act (“ESA”) was established to protect endangered and threatened species.  Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat.

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Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.  We may conduct operations on natural gas and oil leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species, such as the sage grouse, that potentially could be listed as threatened or endangered under the ESA may exist.  The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species.  A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for natural gas and oil development.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year.  The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations.  Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue.  We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2012, nor do we anticipate that such expenditures will be material in 2013.

Employees

As of December 31, 2012, we had 150 full-time employees, including 12 in executive, treasury and finance, 16 in geology, 41 in production and engineering, 20 in accounting and administration, 50 in land, and 11 in midstream.  We also employed approximately 91 contract personnel who assist our full-time employees with specific tasks.  Our future success will depend partially on our ability to attract, retain and motivate qualified personnel.  We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages.  We consider our relations with our employees to be satisfactory.  We utilize the services of independent contractors to perform various field and other services.

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

“3D.”  Method for collecting, processing, and interpreting seismic data in three dimensions.

“Bbl.”  One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or NGLs.

“Bcf.”  One billion cubic feet of natural gas.

“Bcfe.”  One billion cubic feet of natural gas equivalent with one barrel of oil, condensate or NGLs converted to six thousand cubic feet of natural gas.

“Basin.”  A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.”  The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.”  Depreciation, depletion, amortization and accretion.

“Delineation.”  The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage.”  The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.”  A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole.”  A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Exploratory well.”  A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Field.”  An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition.  The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.”  A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres or gross wells.”  The total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling.”  A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“MBbl.”  One thousand barrels of crude oil, condensate or NGLs.

“Mcf.”  One thousand cubic feet of natural gas.

“MMBbl.”  One million barrels of crude oil, condensate or NGLs.

“MMBoe.” One million barrels of oil equivalent.

“MMBtu.”  One million British thermal units.

“MMcf.”  One million cubic feet of natural gas.

“MMcfe.”  One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

“MMcfe/d.”  MMcfe per day.

“NGLs.”  Natural gas liquids.  Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.”  The New York Mercantile Exchange.

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“Net acres.”  The percentage of total acres an owner has out of a particular number of acres, or a specified tract.  An owner who has 50% interest in 100 acres owns 50 net acres.

“Potential well locations.”  Total gross resource play locations that we may be able to drill on our existing acreage.  Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

“Productive well.”  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect.”  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved developed reserves.”  Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.”  The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves (“PUD”).”  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10.”  When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.  PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues.  Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our natural gas and oil properties.  We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

“Recompletion.”  The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reservoir.”  A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Simul-frac.”  Simultaneously fracture treating two or more wells within the same fracture plane in order to create pressure interference between the wells and thereby increasing the stimulated reservoir volume.

“Spacing.”  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure.”  Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves.  Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows.  Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties.  Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Undeveloped acreage.”  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“Unit.”  The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.  Also, the area covered by a unitization agreement.

“Wellbore.”  The hole drilled by the bit that is equipped for natural gas production on a completed well.  Also called well or borehole.

“Working interest.”  The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals.  The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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Item 1A.Risk Factors

Our business involves a high degree of risk.  If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occur, our business, financial condition or results of operations could suffer.  Additional risks not presently known to us or which we currently consider immaterial also may adversely affect our company.

Natural gas prices are volatile.  A substantial or extended decline in natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth.  Natural gas is a commodity and, therefore, its prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.  Historically, the market for natural gas has been volatile.  This market will likely continue to be volatile in the future.  The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control.  These factors include the following:

·worldwide and regional economic conditions impacting the global supply and demand for natural gas;

·the price and quantity of imports of foreign natural gas, including liquefied natural gas;

·political conditions in or affecting other natural gas-producing countries, including conflicts in the Middle East, Africa, South America, and Russia;

·the level of global natural gas exploration and production;

·the level of global natural gas inventories;

·prevailing prices on local natural gas price indexes in the areas in which we operate;

·localized and global supply and demand fundamentals and transportation availability;

·weather conditions;

·technological advances affecting energy consumption;

·the price and availability of alternative fuels; and

·domestic, local and foreign governmental regulation and taxes.

Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world.  This has reduced worldwide demand for energy and resulted in lower natural gas prices.  Natural gas spot prices have been particularly volatile and declined from record high levels in early July 2008 of over $13.00 per Mcf to approximately $3.50 per Mcf in March 2013 as a result of increased natural gas supplies and economic conditions.

Continued lower natural gas prices will reduce our cash flows and borrowing ability.  We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves as existing reserves are depleted.  Continued lower natural gas prices may also reduce the amount of natural gas that we can produce economically.

If natural gas prices remain at their current levels for a significant period of time, a significant portion of our exploration, development and exploration projects could become uneconomic.  This may result in our having to make significant downward adjustments to our estimated proved reserves.  As a result, a substantial or extended decline in natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our exploration, development and exploitation projects require substantial capital expenditures.  We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

The natural gas industry is capital intensive.  We make and expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of natural gas reserves.  Our cash flow used in investing activities related to capital and exploration expenditures was approximately $1.69 billion in 2012.  Our board of directors has approved a capital budget

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for 2013 of $1.65 billion, including $1.15 billion for drilling and completion, $350 million for the construction of gathering pipelines and facilities in the Appalachian Basin (including $150 million for water-handling infrastructure, primarily in the Marcellus Shale) and $150 million for leasehold. Our capital budget excludes acquisitions.  We expect to fund these capital expenditures with cash generated by operations, through borrowings under our Credit Facility, the issuance of senior notes in February 2013, and possibly through additional sales of gathering assets or capital market transactions.  The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.  A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures.  Conversely, a significant improvement in product prices could result in an increase in our capital expenditures.  We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our Credit Facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.  The issuance of additional indebtedness may require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including:

·our proved reserves;

·the level of natural gas we are able to produce from existing wells;

·the prices at which our natural gas is sold;

·our ability to acquire, locate and produce new reserves; and

·the ability of our banks to lend.

If our revenues or the borrowing base under our Credit Facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels.  If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.  If cash flow generated by our operations or available borrowings under our Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves, and could adversely affect our business, financial condition and results of operations.

Drilling for and producing natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities.  Our natural gas exploration, exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production.  Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.  For a discussion of the uncertainty involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”  In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

·delays imposed by or resulting from compliance with regulatory requirements;

·pressure or irregularities in geological formations;

·shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

·equipment failures or accidents;

·adverse weather conditions, such as blizzards, tornados, hurricanes, and ice storms;

·issues related to compliance with environmental regulations;

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·environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

·declines in natural gas prices;

·limited availability of financing at acceptable rates;

·title problems, including in connection with our Utica operations in Ohio, where we have faced claims that certain leases we have acquired are invalid due to production from other horizons being insufficient to hold title by production with respect to the Utica formation rights that we have purchased; and

·limitations in the market for natural gas.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our Credit Facility, our 9.375% senior notes due 2017, our 7.25% senior notes due 2019, and our 6.00% senior notes due 2020, depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control.  We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the senior notes.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness, including the senior notes.  Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time.  Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.  The terms of existing or future debt instruments, including the indentures governing our series of senior notes, may restrict us from adopting some of these alternatives.  In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.  In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations.  Our Credit Facility and the indentures governing our series of senior notes currently restrict our ability to dispose of assets and use the proceeds from such disposition.  We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.  These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

The borrowing base under our Credit Facility is currently $1.22 billion, and lender commitments under the Credit Facility are $700 million.  Our next scheduled borrowing base redetermination is expected to occur in May 2013.  In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent semi-annual borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion.  Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base.  As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out our business plan, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our Credit Facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness).  Our Credit Facility contains restrictive covenants that may limit our ability to, among other things:

·sell assets;

·make loans to others;

·make investments;

·enter into mergers;

·make certain payments;

·Hedge future production;

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·incur liens; and

·engage in certain other transactions without the prior consent of the lenders.

The indentures governing our series of senior notes contain similar restrictive covenants.  In addition, our Credit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios.  These restrictions, together with those in the indentures governing our series of senior notes, may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities.  We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing our series of senior notes and our Credit Facility impose on us.

Our Credit Facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas properties securing our loan.  The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Credit Facility.  Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments.  If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral.  We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our Credit Facility.  The borrowing base under our Credit Facility is currently $1.22 billion and lender commitments are $700 million.  Our next scheduled borrowing base redetermination is expected to occur in May 2013.

A breach of any covenant in our Credit Facility would result in a default under that agreement after any applicable grace periods.  A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements.  The accelerated indebtedness would become immediately due and payable.  If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness.  Even if new financing were available at that time, it may not be on terms that are acceptable to us.  See “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” and “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Agreements and Contractual Obligations—Senior Notes.”.

Currently, we receive significant incremental cash flows as a result of our hedging activity.  To the extent we are unable to obtain future hedges at effective prices consistent with those we have received to date and natural gas prices do not improve, our cash flows may be adversely impacted.  Additionally, if development drilling costs increase significantly in the future, our hedged revenues may not be sufficient to cover our costs.

To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, we have entered into a number of hedge contracts for approximately 757 Bcf of our natural gas production from January 1, 2013 through December 31, 2018.  We are currently realizing a significant benefit from these hedge positions.  For example, for the years ended December 31, 2011 and 2012, we received approximately $117 million and $271 million, respectively, in cash flows pursuant to our hedges.  If future natural gas prices remain comparable to current prices, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through December 2018.  If we are unable to enter into new hedge contracts in the future at favorable pricing and for a sufficient amount of our production, our financial condition and results of operations could be materially adversely affected.

Additionally, since we hedge a significant part of our estimated future production, we have fixed a significant part of our future revenue stream.  If development drilling costs increase significantly because of inflation, increased demand for oilfield services, increased costs to comply with regulations governing our industry, or other factors, future hedged revenues may not be sufficient to cover our costs.

For additional information regarding our hedging activities, please see “Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.”

Reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating natural gas and oil reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices.  Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

In order to prepare our estimates, we must project production rates and timing of development expenditures.  We must also analyze available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary.  The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

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Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas reserves.  We generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate.  Actual future prices and costs may differ materially from those used in the present value estimate.

Our identified potential well locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.  In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential well locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage.  These well locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors.  Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential well locations.  In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire.  As such, our actual drilling activities may materially differ from those presently identified.

We have approximately 4,900 potential well locations.  As a result of the limitations described above, we may be unable to drill many of our potential well locations.  In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so.  Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.  Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2012, 79% of our total estimated proved reserves were classified as proved undeveloped.  Our approximately 4.9 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of development capital over the next five years.  Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate.  Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.  In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

If commodity prices decrease or remain at current levels for a significant period of time, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment.  Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties.  A write-down constitutes a non-cash charge to earnings.  We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors.  Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced.  Our future

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natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.  We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.  If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including collars and price-fix swaps.  Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

·production is less than the volume covered by the derivative instruments;

·the counter-party to the derivative instrument defaults on its contractual obligations;

·there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

·there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties.  If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, including the notes, and which could also limit the size of our borrowing base.  Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

As of December 31, 2012, the estimated fair value of our commodity derivative contracts was approximately $532 million.  Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.  The fair value of our commodity derivative contracts of approximately $532 million at December 31, 2012 includes the following values by bank counterparty: JP Morgan - $94 million; BNP Paribas - $124 million; Credit Suisse - $150 million; Wells Fargo - $86 million; Barclays - $57 million; Deutsche Bank - $11 million; and Union Bank - $4 million.  Additionally, contracts with Dominion Field Services account for $6 million of the fair value. The credit ratings of certain of these banks were downgraded in 2011 because of the sovereign debt crisis in Europe.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($6 million at December 31, 2012) and the sale of our natural gas production ($47 million in receivables at December 31, 2012), which we market to energy marketing companies, refineries and affiliates.  Joint interest receivables arise from billing entities who own partial interest in the wells we operate.  These entities participate in our wells primarily based on their ownership in leases on which we wish to drill.  We can do very little to choose who participates in our wells.  We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers.  The largest purchaser of our natural gas during the twelve months ended December 31, 2012 purchased approximately 23% of our operated production.  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.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and worker health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits

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and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

For example, in March 2011, we received orders for compliance from federal regulatory agencies, including the EPA, relating to certain of our activities in West Virginia. The orders allege that certain of our operations at several well sites are in non-compliance with certain environmental regulations, such as unpermitted discharges of fill material into wetlands or waters of the United States that are potentially in violation of the Clean Water Act. We have responded to all pending orders and are actively cooperating with the relevant agencies. No fine or penalty relating to these matters has been proposed at this time, but we believe that these actions will result in monetary sanctions exceeding $100,000. In addition, we expect to incur additional costs to remediate these well locations in order to bring them into compliance with applicable environmental laws and regulations. We have not, however, been required to suspend our operations at these locations to date and our management team does not expect these matters to have a material adverse effect on our financial statements.

Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and worker health and safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. For example, we have been recently named as the defendant in separate lawsuits in Colorado, West Virginia, and Pennsylvania in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties. The plaintiffs have requested unspecified damages and other injunctive or equitable relief. We are not yet able to estimate what our aggregate exposure for monetary or other damages resulting from these or other similar claims might be. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations.  Additionally we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks.  Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.  Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

·environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

·abnormally pressured formations;

·mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

·fires, explosions and ruptures of pipelines;

·personal injuries and death;

·natural disasters; and

·terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

·injury or loss of life;

·damage to and destruction of property, natural resources and equipment;

·pollution and other environmental damage;

·regulatory investigations and penalties;

·suspension of our operations; and

·repair and remediation costs.

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We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented.  In addition, pollution and environmental risks generally are not fully insurable.  The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.

Prospects that we decide to drill that do not yield natural gas or oil in commercially viable quantities will adversely affect our results of operations and financial condition.  In this report, we describe some of our current prospects and our plans to explore those prospects.  Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.  There is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas or oil in sufficient quantities to recover drilling or completion costs or to be economically viable.  The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities.  We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.  Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

·unexpected drilling conditions;

·title problems;

·pressure or lost circulation in formations;

·equipment failure or accidents;

·adverse weather conditions;

·compliance with environmental and other governmental or contractual requirements; and

·increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons.  We are employing 3-D seismic technology with respect to certain of our projects.  The implementation and practical use of 3-D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs.  In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns or losses.  As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 3-D seismic data over large areas.  Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling.  Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location.  If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3-D data without having an opportunity to attempt to benefit from those expenditures.

Market conditions or operational impediments may hinder our access to natural gas and oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas and oil transportation arrangements may hinder our access to natural gas and oil markets or delay our production.  The availability of a ready market for our natural gas and oil production depends on a number of factors, including the demand for and supply of natural gas and oil and the proximity of reserves to pipelines and terminal facilities.  Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties.  Our failure to obtain such services on acceptable terms could materially harm our business.  We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas and oil pipeline or gathering system capacity.  In addition, if natural gas or oil quality specifications for the third party natural gas or oil pipelines with which we connect change so as to restrict our ability to transport natural gas or oil, our access to natural gas and oil markets could be impeded.  If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

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We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations.  In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities.  We may incur substantial costs in order to maintain compliance with these existing laws and regulations.  In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.  Such costs could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas.  Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations.  Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC, as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.  These EPA rulemakings could adversely affect our operations and restrict or delay or ability to obtain air permits for new or modified sources.  In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, which include certain of our operations.  We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations. While Congress has from time to time

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considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs.  If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.  Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.  Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.  Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production.  We commonly use hydraulic fracturing as part of our operations.  Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA Act over certain hydraulic fracturing activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels.  In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations.  In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process.  At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices.  The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices.  The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014.  Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014.  Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing.  These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), enacted in 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, the CFTC issued a final rule on position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. The position-limits rule was vacated by the U.S. District Court for the District of Colombia in September 2012 and the CFTC recently stated that it will appeal the District Court’s decision. The CFTC also finalized other regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant.” Some regulations, however, remain to be finalized and it is not possible at this time to predict when this will be accomplished. Depending on

28

our classification and the particular nature of our derivative activities, the Dodd-Frank Act and regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities. The Dodd-Frank Act and regulations may also require our counterparties to our derivative instruments to spin off some of our derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less-creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural-gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations, or cash flows.

Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman and Chief Executive Officer, and Glen C. Warren, Jr., our President and Chief Financial Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are developed and producing. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, as of December 31, 2012, outstanding borrowings under our Credit Facility were approximately $217 million, and the impact of a 1.0%

29

increase in interest rates on this amount of indebtedness would result in increased annual interest expense during 2012 of approximately $3 million and a corresponding decrease in our net income before the effects of increased interest rates on the value of our interest rate swap contracts and income taxes. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

·recoverable reserves;

·future natural gas prices and their applicable differentials;

·operating costs; and

·potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our Credit Facility imposes and the indentures governing our series of senior notes impose certain limitations on our ability to enter into mergers or combination transactions. Our Credit Facility and the indentures governing our series of senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

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In February 2013, the governor of the state of Ohio proposed a plan to enact new severance taxes in fiscal 2014 and 2015. Under the plan, the severance taxes for horizontal wells would increase from $0.20 per barrel of oil and $0.03 per MCF of gas to 1% of production revenues for natural gas production revenues and 4% of production revenues for oil, NGLs, and condensate.  For the first year of production, a rate of 1.5% would apply to oil, NGLs, and condensate. The passage of these changes would increase our tax burdens in the Utica Shale play in Ohio.

Item 1B.          Unresolved Staff Comments

Not applicable.

Item 3.Legal Proceedings

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

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

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

Item 4.Mine Safety Disclosures

Not applicable.

PART II

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Not applicable.

Item 6.Selected Financial Data

The following table shows our selected historical consolidated financial data, for the periods and as of the dates indicated, for Antero Resources LLC and its subsidiaries. As of December 31, 2012, the subsidiaries of Antero Resources LLC included Antero Resources Appalachian Corporation and its wholly owned subsidiaries: Antero Resources Piceance LLC, Antero Resources Pipeline LLC, Antero Resources Arkoma LLC, Antero Resources Bluestone LLC , and Antero Resources Finance Corporation.

The selected statement of operations data for the years ended December 31, 2010, 2011 and 2012 and the balance sheet data as of December 31, 2011 and 2012 are derived from our audited consolidated financial statements included in Item 8 of this Annual Report on Form 10-K. The selected statement of operations data for the years ended December 31, 2008 and 2009 and the balance sheet data as of December 31, 2008, 2009, and 2010 are derived from our audited consolidated financial statements not included in Item 8 of this Annual Report on Form 10-K. The statement of operations data for all periods presented has been recast to present the results of operations from our Piceance Basin and Arkoma Basin operations in discontinued operations.  The losses on the sales of these properties are also included in discontinued operations in 2012.  The results from continuing operations reflect our remaining operations in the Appalachian Basin.  No part of our general and administrative expenses or interest expense was allocated to discontinued operations.  The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this report.

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	Year Ended December 31,
(in thousands, except ratios)	2008			2009			2010			2011			2012
Statement of operations data:
Operating revenues:
Natural gas sales	$	—		$	2,252		$	47,392		$	195,116		$	259,743
NGL sales	—			—			—			—			3,719
Oil sales	—			—			39			173			1,520
Realized gains on commodity derivative instruments	—			—			15,063			49,944			178,491
Unrealized gains on commodity derivative instruments	—			3,910			62,536			446,120			1,055
Gain on sale of assets	—			—			—			—			291,190
Total revenues	—			6,162			125,030			691,353			735,718
Operating expenses:
Lease operating expenses	—			28			1,158			4,608			6,243
Gathering, compression and transportation	—			421			9,237			37,315			91,094
Production taxes	—			128			2,885			11,915			20,210
Exploration expenses	—			2,095			2,350			4,034			14,675
Impairment of unproved properties	—			100			6,076			4,664			12,070
Depletion, depreciation and amortization	391			1,706			18,522			55,716			102,026
Accretion of asset retirement obligations	—			—			11			76			101
Expenses related to acquisition of business	—			—			2,544			—			—
General and administrative	16,171			20,843			21,952			33,342			45,284
Loss on sale of compression station	—			—			—			8,700			—
Total operating expenses	16,562			25,321			64,735			160,370			291,703
Operating income (loss)	(16,562		)	(19,159		)	60,295			530,983			444,015
Other expense:
Interest expense	$	(37,594	)	$	(36,053	)	(56,463		)	$	(74,404	)	(97,510		)
Realized and unrealized losses on interest derivative instruments, net	(15,245		)	(4,985		)	(2,677		)	(94		)	—
Total other expense	(52,839		)	(41,038		)	(59,140		)	(74,498		)	(97,510		)
Income (loss) before income taxes	(69,401		)	(60,197		)	1,155			456,485			346,505
Income tax (expense) benefit	26,520			—			(939		)	(185,297		)	(121,229		)
Income (loss) from continuing operations	(42,881		)	(60,197		)	216			271,188			225,276
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations	126,837			(45,972		)	228,412			121,490			(510,345		)
Net income (loss) attributable to Antero equity owners	$	(83,956	)	$	(106,169	)	$	228,628		$	392,678		$	(285,069	)
Balance sheet data (at period end):
Cash and cash equivalents	$	38,969		$	10,669		$	8,988		$	3,343		18,989
Other current assets	165,199			84,175			147,917			330,299			255,617
Total current assets	204,168			94,844			156,905			333,642			274,606
Natural gas properties, at cost (successful efforts method):
Unproved properties	649,605			596,694			737,358			834,255			1,243,237
Producing properties	1,148,306			1,340,827			1,762,206			2,497,306			1,689,132
Gathering systems and facilities	179,836			185,688			85,404			142,241			168,930
Other property and equipment	3,113			3,302			5,975			8,314			9,517
	1,980,860			2,126,511			2,590,943			3,482,116			3,110,816
Less accumulated depletion, depreciation, and amortization	(183,145		)	(322,992		)	(431,181		)	(601,702		)	(173,343		)
Property and equipment, net	1,797,715			1,803,519			2,159,762			2,880,414			2,937,473
Other assets	27,084			38,203			169,620			574,744			406,714
Total assets	$	2,028,967		1,936,566			$	2,486,287		$	3,788,800		$	3,618,793
Current liabilities	$	208,209		$	112,493		$	152,483		$	255,058		376,296
Long-term indebtedness	622,734			515,499			652,632			1,317,330			1,444,058
Other long-term liabilities	20,469			9,467			86,185			257,606			124,702
Total equity	1,177,555			1,299,107			1,594,987			1,958,806			1,673,737
Total liabilities and equity	$	2,028,967		$	1,936,566		$	2,486,287		$	3,788,800		$	3,618,793
Other financial data:
EBITDAX(1)	$	208,513		$	201,270		$	197,678		$	340,821		$	434,315
Net cash provided by operating activities	157,515			149,307			127,791			$	266,307		332,255
Net cash used in investing activities	(1,004,010		)	(281,899		)	(230,672		)	(901,249		)	(463,491		)
Net cash provided by financing activities	874,350			104,292			101,200			629,297			146,882
Capital expenditures(2)	1,041,748			203,454			423,002			929,887			1,755,430

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(1)“EBITDAX” is a non-GAAP financial measure that we define as net income (loss) before interest expense, 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, gain or loss on sale of assets, and interest income. “EBITDAX,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position. EBITDAX does not represent funds available for discretionary use because those funds are required for debt service, capital expenditures, working capital, 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 operating performance because this measure:

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

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

·is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to a covenant under our Credit Facility. EBITDAX is also used as a measure of our operating performance pursuant to a covenant under the indentures governing our series of 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) to EBITDAX (including continuing and discontinued operations) for the periods presented:

	Year Ended December 31,
(in thousands)	2008			2009			2010			2011			2012
Net income (loss)	$	83,956		$	(106,169	)	$	228,628		$	392,678		$	(285,069	)
Unrealized (gains) losses on commodity derivative contracts	(90,301		)	61,186			(170,571		)	(559,596		)	44,753
(Gain) loss on sale of assets	—			—			(147,559		)	8,700			504,755
Interest expense and other	52,839			41,038			59,140			74,498			97,510
Provision (benefit) for income taxes	3,029			(2,605		)	30,009			230,452			(151,324		)
Depreciation, depletion, amortization and accretion	124,997			140,078			134,272			170,956			191,251
Impairment of unproved properties	10,112			54,204			35,859			11,051			13,032
Exploration expense	22,998			10,228			24,794			9,876			15,339
Other	883			3,310			3,106			2,206			4,068
EBITDAX	$	208,513		$	201,270		$	197,678		$	340,821		$	434,315

(2)Capital expenditures as shown in this table differ from the amounts shown in the statement of cash flows in the consolidated financial statements because amounts in this table include changes in accounts payable for capital expenditures from the previous reporting period while the amounts in the statement of cash flows in the financial statements are presented on a cash basis.

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Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the historical audited financial statements and the related notes included 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 which 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,” “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 “Items 1 and 2. Business and Properties—Business—Corporate Sponsorship and Structure” or note 1 to the consolidated financial statements included elsewhere in this report.

Our Company

Antero Resources is an independent oil and natural gas company engaged in the exploration, development and acquisition of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. As of December 31, 2012, we held approximately 371,000 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.

Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays.  Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily through internally generated projects on our acquired acreage.  As of December 31, 2012, our estimated proved reserves were approximately 4.9 Tcfe, consisting of 3.7 Tcf of natural gas, 203 MMBbl of NGLs, and 3 MMBbl of oil.  As of December 31, 2012, 75% of our proved reserves were natural gas, 21% were proved developed and 98% were operated by us.  For the year ended December 31, 2012, we generated cash flow from operations of $332 million, a net loss of $285 million and EBITDAX of $434 million.  The net loss in 2012 includes $505 million of net losses on the sale of gathering systems and discontinued operations, and $151 million of net deferred tax benefits.  See “Item 6.  Selected Financial Data” for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

We have assembled a diversified portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatable drilling opportunities.  Our drilling opportunities are focused in the Marcellus, Utica and Upper Devonian Shales of the Appalachian Basin.  From inception, we have drilled and operated 520 wells through December 31, 2012 with a success rate of approximately 98%.  Our drilling inventory consists of approximately 4,900 potential well locations, all of which are unconventional resource opportunities.  For information on the possible limitations on our ability to drill these potential locations, see “Item 1A.  Risk Factors- Our identified potential well locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.  In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential well locations.”

As of December 31, 2012, we had entered into hedging contracts covering a total of approximately 757 Bcfe of our projected natural gas and oil production from January 1, 2013 through December 31, 2018 at a weighted average index price of $4.88 per MMBtu.  For the year ending December 31, 2013, we have hedged approximately 115 Bcfe of our projected natural gas and oil production at a weighted average index price of $4.93 per MMBtu.  We believe this hedge position provides significant protection to future operations and capital spending plans.

Our current borrowing base under the Credit Facility is $1.22 billion and lender commitments are $700 million.  Lender commitments under the facility can be expanded from $700 million to the full $1.22 billion borrowing base upon bank approval.  The borrowing base under the Credit Facility is redetermined semi-annually and is based on the amount of our proved oil, NGL, and gas reserves and the estimated cash flows from these reserves and our hedge positions.  The next redetermination is scheduled to occur in May 2013.  The Credit Facility provides for a maximum availability of $2.5 billion.  At December 31, 2012, we had $260 million of

34

borrowings and letters of credit outstanding under the Credit Facility and $440 million of available borrowing capacity, based on $700 million of lender commitments at that date.  Pro forma for the issuance of $225 million of 6.00% senior notes subsequent to year-end, we would have had $657 million of  borrowing capacity at December 31, 2012.  The Credit Facility matures in May 2016.

For the year ended December 31, 2012, our capital expenditures were approximately $1.69 billion for drilling, leasehold, and gathering.  Our capital budget for 2013 is $1.65 billion, including $1.15 billion for drilling and completion, $350 million for the construction of gathering pipelines and facilities in the Appalachian Basin (including $150 million for water-handling infrastructure, primarily in the Marcellus Shale) and $150 million for leasehold. Our capital budget excludes acquisitions. Substantially all of the $1.15 billion allocated for drilling and completion is allocated to our operated drilling in rich gas areas. Approximately 87% of the drilling and completion budget is allocated to the Marcellus Shale, and the remaining 13% is allocated to the Utica Shale. During 2013, we plan to operate an average of 12 drilling rigs in the Marcellus Shale and 2 drilling rigs in the Utica Shale. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results and commodity prices.

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

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

Source of Our Revenues

Our production revenues are entirely from the continental United States and during 2012 our revenues from both continuing and discontinued operations were comprised of approximately 85% from the production and sale of natural gas and 15% from the production and sale of NGLs and oil. Natural gas, NGL, and oil prices are inherently volatile and are influenced by many factors outside of our control. Our revenues are derived from the sale of natural gas and oil production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Substantially all of our production is derived from natural gas wells which also produce natural gas liquids and limited quantities of oil. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas production. We currently use fixed price natural gas swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At the end of each period we estimate the fair value of these swaps and recognize an unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. We expect continued volatility in the fair value of these swaps.

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 produced water disposal, pumping, maintenance, repairs, and workover expenses. Cost levels for these expenses can vary based on industry drilling and production activity levels and the resulting demand fluctuations for oilfield services.

·Gathering, compression, 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 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 NGLs and oil to market. Cost 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 in to 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) or at fixed per unit rates established by federal, state or local taxing authorities.

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

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·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 December 31, 2012, we have not recorded any impairment for proved properties.

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

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

·Interest expense.  We finance a portion of our working capital requirements and acquisitions with borrowings under our Credit Facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We also had at December 31, 2012 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 $300 million. We expect to continue to incur significant interest expense as we continue to grow.

·Income tax expense.  Through December 31, 2011, each of our operating entities filed separate federal and state income tax returns; therefore, our provision for income taxes through that date consisted of the sum of our income tax provisions for each of the operating entities. In October 2012, the Company completed a reorganization of its legal structure by contributing all of the outstanding shares owned by Antero Resources LLC in each of the Antero Arkoma, Antero Piceance, and Antero Pipeline corporations to Antero Appalachian.  Antero Arkoma, Antero Piceance, and Antero Pipeline were then converted to limited liability companies.  As a result, for income tax purposes, the operations from the date of the reorganizations and tax attributes of Arkoma, Piceance and Pipeline are now combined with Antero Appalachian for tax reporting purposes.  We are subject to state and federal income taxes but are currently not in a tax paying position for regular Federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”) 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 our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on a basis other than income.  We have generated net operating loss carryforwards 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 the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations.  The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.  The financial statements include unrecognized benefits at December 31, 2012 of $15 million that, if recognized, would result in a reduction of current income taxes payable and an increase in noncurrent deferred tax liabilities.  No impact to the Company’s 2012 effective tax rate would result from the recognition of the tax benefits.  As of December 31, 2012, no interest or penalties have been accrued on unrecognized tax benefits.    The Company had no unrecognized tax benefits at December 31, 2010 or 2011.

Results of Operations

Year Ended December 31, 2011 Compared to Year Ended December 31, 2012

The following table sets forth selected operating data (as recast for discontinued operations) for the year ended December 31, 2011 compared to the year ended December 31, 2012:

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	Year Ended December 31,						Amount of Increase			Percent
(in thousands, except per unit data)	2011			2012			(Decrease)			Change
Operating revenues:
Natural gas sales	$	195,116		$	259,743		$	64,627		33	%
NGL sales	—			3,719			3,719			*
Oil sales	173			1,520			1,347			779	%
Realized commodity derivative gains	49,944			178,491			128,547			257	%
Unrealized commodity derivative gains	446,120			1,055			(445,065		)	(100	)%
Gain on sale of Appalachian gathering assets	—			291,190			291,190			*
Total operating revenues	691,353			735,718			44,365			6	%
Operating expenses:
Lease operating expenses	4,608			6,243			1,635			35	%
Gathering, compression, and transportation	37,315			91,094			53,779			144	%
Production taxes	11,915			20,210			8,295			70	%
Exploration	4,034			14,675			10,641			264	%
Impairment of unproved properties expense	4,664			12,070			7,406			159	%
Depletion, depreciation and amortization	55,716			102,026			46,310			83	%
Accretion of asset retirement obligations	76			101			25			33	%
General and administrative expense	33,342			45,284			11,942			36	%
Loss on sale of compressor station	8,700			—			(8,700		)	*
Total operating expenses	160,370			291,703			131,333			82	%
Operating income	530,983			444,015			(86,968		)	(16	)%
Other income expense:
Interest expense	$	(74,404	)	$	(97,510	)	$	(23,106	)	31	%
Realized and unrealized interest rate derivative losses	(94		)	—			94			*
Total other expense	(74,498		)	(97,510		)	(23,012		)	31	%
Income before income taxes	456,485			346,505			(109,980		)	(24	)%
Income taxes expense	(185,297		)	(121,229		)	(64,068		)	(35	)%
Income from continuing operations	271,188			225,276			(45,912		)	(17	)%
Income (loss) from discontinued operations	121,490			(510,345		)	(631,835		)	*
Net income (loss) attributable to Antero equity owners	$	392,678		$	(285,069	)	$	(677,747	)	(173	)%
EBITDAX (1)	$	340,821		$	434,312		$	93,491		27	%
Production data:
Natural gas (Bcf)	45			87			42			93	%
NGLs (MBbl)	—			71			71			*
Oil (MBbl)	2			19			17			963	%
Combined (Bcfe)	45			87			42			93	%
Daily combined production (MMcfe/d)	124			239			115			93	%
Average prices before effects of hedges (2):
Natural gas (per Mcf)	$	4.33		2.99			(1.34		)	(31	)%
NGLs (per Bbl)	$	—		52.07			52.07			*
Oil (per Bbl)	$	97.19		80.34			(16.85		)	(17	)%
Combined (per Mcfe)	$	4.33		3.03			(1.30		)	(30	)%
Average realized prices after-effects of hedges (2):
Natural gas (per Mcf)	$	5.44		5.05			(0.39		)	(7	)%
NGLs (per Bbl)	$	—		52.07			52.07			*
Oil (per Bbl)	$	97.19		80.34			(16.85		)	(17	)%
Combined (per Mcfe)	$	5.44		5.08			(0.36		)	(7	)%
Average costs (per Mcfe):
Lease operating costs	$	0.10		0.07			(0.03		)	(30	)%
Gathering compression and transportation	$	0.83		1.04			0.21			25	%
Production taxes	$	0.26		0.23			(0.03		)	(12	)%
Depletion depreciation amortization and accretion	$	1.24		1.17			(0.07		)	(6	)%
General and administrative	$	0.74		0.52			(0.22		)	(30	)%

(1)See “Item 6.  Selected Financial Data” included in this Annual Report on Form 10-K for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

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(2)Average prices shown in the table reflect both of the before-and-after-effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil 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. Combined revenues from production of natural gas, NGLs, and oil increased from $195 million for the year ended December 31, 2011 to $265 million for the year ended December 31, 2012, an increase of $70 million, or 36%. Our production increased by 94% from 45 Bcfe in 2011 to 87 Bcfe in 2012. Increased production volumes increased revenues by $183 million, or 94%, (calculated as the increase in year-to-year volumes times the prior year average price), and combined commodity price decreases accounted for a $113 million, or 58%, decrease in revenues (calculated as the decrease in year-to-year average combined price times current year production volumes).

Commodity hedging activities.  To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge treatment, and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate from the fixed price we will receive on future production. For the years ended December 31, 2011 and 2012, our hedges resulted in realized gains of $50 million and $178 million, respectively. For the years ended December 31, 2011 and 2012, our hedges resulted in unrealized gains of $446 million and $1 million, respectively.  Unrealized gains in 2011 resulted from, (i) lower commodity prices at December 31, 2011 compared to December 31, 2010 for contracts outstanding at the end of both years and, (ii) from commodity prices at December 31, 2011 being lower than commodity swap prices for new contracts entered into in 2011.  Additionally, prices did not vary significantly from year-end 2011 prices.

Gain on sale of Appalachian gathering assets.  On March 26, 2012, we closed the sale of a portion of its Marcellus Shale gathering system assets along with exclusive rights to gather and compress 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.  We can earn up to an additional $40 million of sale proceeds if we meet certain volume thresholds over the first three years of the contract.  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 we have not retained the substantial risks and rewards of ownership associated with the gathering rights and systems transferred to Crestwood, it has recognized a gain on the sale of the gathering system and gathering rights of approximately $291 million.

Lease operating expenses. Lease operating expenses increased from $5 million for the year ended December 31, 2011 to $6 million in 2012, primarily as a result of increased production. On a per-Mcfe basis, lease operating expenses decreased by 30%, from $0.10 per Mcfe in 2011 to $0.07 per Mcfe in 2012 primarily because of costs increasing at a lower rate than production.  Because our Appalachian Basin properties are in a relatively early stage of production, lease operating expenses are minimal and are expected to increase as the properties mature.

Gathering, compression and transportation expense.  Gathering, compression and transportation expense increased from $37 million for the year ended December 31, 2011 to $91 million in 2012.  The increase in these expenses resulted from the increase in production, increased firm transportation commitments, and increases in third-party compression and gathering expenses as we move to outsource some of our compression and gathering activities.  On a per-Mcfe basis, total gathering, compression, and transportation expenses increased from $0.83 per Mcfe for 2011 to $1.04 in 2012.

Production tax expense.  Total production taxes increased from $12 million for the year ended December 31, 2011 to $20 million for the year ended December 31, 2012, primarily as a result of increased production. Production taxes as a percentage of natural gas, NGLs, and oil revenues before the effects of hedging were 6.1% for the year ended December 31, 2011 compared to 7.6% for the year ended December 31, 2012. West Virginia ad valorem taxes, which are based on the value of oil and gas reserves, accounted for the increase in the ratio of production tax expense to revenues as we increased our Appalachian reserves.

Exploration expense.  Exploration expense increased from $4 million for the year ended December 31, 2011 to $15 million for the year ended December 31, 2012 primarily because of an increase in the cost of unsuccessful lease acquisition efforts.

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Impairment of unproved properties.  Impairment of unproved properties was approximately $5 million for the year ended December 31, 2011 compared to $12 million for the year ended December 31, 2012.  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 or future plans to develop the acreage and recognize impairment costs accordingly.

Depletion, depreciation and amortization (“DD&A”).  DD&A increased from $56 million for the year ended December 31, 2011 to $102 million for the year ended December 31, 2012, an increase of $46 million, as a result of increased production in 2012 compared to 2011. DD&A per Mcfe decreased 6%, from $1.24 per Mcfe during 2011 to $1.17 per Mcfe during 2012 as a result of the increased proved reserves in 2012.

We evaluate the impairment of our proved natural gas, NGLs, and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. There were no impairment expenses recorded for the years ended December 31, 2011 or 2012 for proved properties. As of December 31, 2012, no significant exploratory well costs had been deferred for over one year pending proved reserves determination.

General and administrative expense.  General and administrative expense increased from $33 million for the year ended December 31, 2011 to $45 million during 2012, an increase of $12 million. The increase is due to increased costs related to salaries, employee benefits, contract personnel and other general business expenses required to support the growth of our capital expenditure program and production levels. The number of our full-time employees grew from 107 at December 31, 2011 to 150 at December 31, 2012.  On a per-Mcfe basis, general and administrative expense decreased by 30%, from $0.74 per Mcfe during the year ended December 31, 2011 to $0.52 per Mcfe during 2012 primarily due to a 94% growth in production.  No portion of general and administrative expenses was allocated to discontinued operations as the Company does not expect any reduction of such expenses as a result of the sale of the Arkoma and Piceance properties.  When all discontinued operations are included, general and administrative expenses were $0.37 per Mcfe for both 2011 and 2012.

Interest expense and realized and unrealized gains and losses on interest rate derivatives.  Interest expense increased from $74 million for the year ended December 31, 2011 to $98 million for the year ended December 31, 2012, an increase of $24 million as a result of an increase in the amount of senior notes outstanding during 2012 compared to during 2011.

Income tax expense.  For each tax year-end through December 31, 2011, Antero Resources LLC and each of its subsidiaries filed separate federal and state income tax returns.  Antero Resources LLC is a partnership for income tax purposes and therefore is not subject to federal or state income taxes.  The tax on the income of Antero Resources LLC is borne by its individual members through the allocation of taxable income.  In October 2012, the Company completed a reorganization of its legal structure by contributing all of the outstanding shares owned by Antero Resources LLC in each of the Antero Arkoma, Antero Piceance, and Antero Pipeline corporations to Antero Appalachian.  Antero Arkoma, Antero Piceance, and Antero Pipeline were then converted to limited liability companies.  As a result, for income tax purposes, the operations from the date of the reorganizations and tax attributes of Arkoma, Piceance and Pipeline are now combined with Antero Appalachian for tax reporting purposes.

Income tax expense related to continuing operations was $121 million in 2012 compared to $185 million in 2011.  Although we have accrued $15 million at December 31, 2012 for unrecognized tax benefits, no taxes are due at the end of either December 31, 2011 or 2012.  We have not generated current taxable income in either the current or prior years, which is primarily attributable to the differing book and tax treatment of unrealized derivative gains and intangible drilling costs.  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 and through 2032.  At December 31, 2012, we recorded valuation allowances of approximately $48 million for deferred tax assets primarily related to capital loss and state loss carryforwards.  From time to time there has been proposed legislation in the U.S. Congress to eliminate or limit future deductions for intangible drilling costs; such legislation could significantly affect our future taxable position if passed. The impact of any change will be recorded in the period that such legislation might be enacted.

The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.  The financial statements include unrecognized benefits at December 31, 2012 of $15 million that, if recognized, would result in a reduction of current income taxes payable and an increase in noncurrent deferred tax liabilities.  No impact to the Company’s 2012 effective tax rate would result.  As of December 31, 2012, no

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interest or penalties have been accrued on unrecognized tax benefits.    The Company had no unrecognized tax benefits at December 31, 2010 or 2011.

Income (loss) from discontinued operations.  Income (loss) from discontinued operations includes the results of operations from the Arkoma Basin and Piceance Basin operations (including revenues and direct operating expenses and allocated income tax expense, but not general and administrative or interest expenses) and, in 2012, the loss on the sale of these assets.  A detailed analysis of these operations is included in note 3 to the consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.  Income (loss) from discontinued operations decreased from income of $121 million in 2011 to a loss of $510 million in 2012, primarily as a result of the loss on the sale of the properties of $796 million and a $273 million tax benefit from the loss.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2011

The following table sets forth selected operating data (as recast for discontinued operations) for the year ended December 31, 2010 compared to the year ended December 31, 2011:

	Year Ended December 31,
(in thousands, except per unit data)	2010			2011			Amount of Increase (Decrease)			Percent Change
Operating revenues:
Natural gas sales	$	47,392		$	195,116		$	147,724		312	%
Oil sales	39			173			134			344	%
Realized commodity derivative gains	15,063			49,944			34,881			232	%
Unrealized commodity derivative gains	62,536			446,120			383,584			613	%
Total operating revenues	125,030			691,353			566,323			453	%
Operating expenses:
Lease operating expenses	1,158			4,608			3,450			298	%
Gathering, compression and transportation	9,237			37,315			28,078			304	%
Production taxes	2,885			11,915			9,030			313	%
Exploration expenses	2,350			4,034			1,684			72	%
Impairment of unproved properties	6,076			4,664			(1,412		)	(23	)%
Depletion, depreciation and amortization	18,522			55,716			37,194			201	%
Accretion of asset retirement obligations	11			76			65			591	%
Expenses related to acquisition of business	2,544			—			(2,544		)	*
General and administrative	21,952			33,342			11,390			52	%
Loss on sale of compressor station	—			8,700			8,700			*
Total operating expenses	64,735			160,370			95,635			148	%
Operating income	60,295			530,983			470,688			781	%
Other expense:
Interest expense	(56,463		)	(74,404		)	17,941			32	%
Realized and unrealized interest rate derivative losses	(2,677		)	(94		)	(2,583		)	(96	)%
Total other expense	(59,140		)	(74,498		)	15,358			26	%
Income before income taxes	1,155			456,485			455,330			*
Income tax expense	(939		)	(185,297		)	(184,358		)	*
Income (loss) from continuing operations	216			271,188			270,972			*
Income from discontinued operations	228,412			121,490			(106,922		)	(47	)%
Net income attributable to Antero equity owners	$	228,628		$	392,678		$	164,050		72	%
EBITDAX (1)	$	197,678		$	340,821		$	143,143		72	%
Production data:
Natural gas (Bcf)	11			45			34			317	%
Oil (MBbl)	—			2			2			*
Combined (Bcfe)	11			45			34			317	%

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	Year Ended December 31,
(in thousands, except per unit data)	2010		2011		Amount of Increase (Decrease)			Percent Change
Daily combined production (MMcfe/d)	30		124		94			317	%
Average prices before effects of hedges(2):
Natural gas (per Mcf)	$	4.39	$	4.33	$	(0.06	)	(1	)%
Oil (per Bbl)	$	—	$	97.19	$	*		*
Combined (per Mcfe)	$	4.39	$	4.33	$	(0.06	)	(1	)%
Average realized prices after-effects of hedges(2):
Natural gas (per Mcf)	$	5.78	$	5.44	$	(0.34	)	(6	)%
Oil (per Bbl)	$	—	$	97.19	$	*		*
Combined (per Mcfe)	$	5.78	$	5.44	$	(0.34	)	(6	)%
Average costs (per Mcfe) (2):
Lease operating costs	$	0.11	$	0.10	$	(0.01	)	(9	)%
Gathering, compression and transportation	$	0.85	$	0.83	$	(0.02	)	(2	)%
Production taxes	$	0.27	$	0.26	$	(0.01	)	(4	)%
Depletion, depreciation, amortization	$	1.71	$	1.24	$	(0.47	)	(27	)%
General and administrative	$	2.03	$	0.74	$	(1.29	)	(64	)%

(1)See “Item 6.  Selected Financial Data” included in this Annual Report on Form 10-K for a definition of EBITDAX (a non-GAAP measure) and a reconciliation of EBITDAX to net income (loss).

(2)Average prices shown in the table reflect both of the before-and-after effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges. 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 $47 million for the year ended December 31, 2010 to $195 million for the year ended December 31, 2011, an increase of $148 million or 312%. Our production increased by 317% from 11 Bcfe in 2010 to 45 Bcfe in 2011. The net increase in revenues resulted from production volume increases reduced by commodity price decreases. Production increases accounted for a $150 million, or 317%, increase in revenues (calculated as the increase in year-to-year volumes times the prior year average price).  Price decreases accounted for a $2 million, or 5%, decrease in revenues (calculated as the decrease in year-to-year average price times current year production volumes).

Commodity hedging activities.  To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we enter into derivative contracts using fixed for variable swap contracts when management believes that favorable future sales prices for our natural gas production can be secured. Because we do not designate these derivatives as accounting hedges, they do not receive accounting hedge treatment and all mark-to-market gains or losses, as well as realized gains or losses on the derivative instruments, are recognized in our results of operations. The unrealized gains and losses represent the changes in the fair value of these swap agreements as the future strip prices fluctuate from the fixed price we will receive on future production. For the years ended December 31, 2010 and 2011, our hedges resulted in realized gains of $15 million and $50 million, respectively. For the years ended December 31, 2010 and 2011, our hedges resulted in unrealized gains of $63 million and $446 million, respectively.  The increase in unrealized gains from 2010 to 2011 resulted primarily from the decrease in natural gas prices.

Lease operating expenses. Lease operating expenses increased from $1 million for the year ended December 31, 2010 to $5 million in 2011, an increase of $4 million, as a result of a 317% increase in production.

Gathering, compression and transportation expense.  Gathering, compression and transportation expense increased from $9 million for the year ended December 31, 2010 to $37 million in 2011 because of the increase in production and increased firm transportation commitments.  On a per-Mcfe basis, these expenses decreased slightly from $0.85 per Mcfe for 2010 to $0.83 per Mcfe for 2011.

Production tax expense.  Total production taxes increased from $3 million for the year ended December 31, 2010 to $12 million for the year ended December 31, 2011, as a result of increased production. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 6.1% in both years.

Exploration expense.  Exploration expense increased from $3 million for the year ended December 31, 2010 to $4 million for the year ended December 31, 2011, primarily because of an increase in the cost of unsuccessful lease acquisition efforts.

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Impairment of unproved properties.  We abandon 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 short remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage and recognize impairment costs accordingly.  Our impairment of unproved property expense decreased from $6 million for the year ended December 31, 2010 to $5 million for the year ended December 31, 2011.

Depletion, depreciation and amortization (DD&A).  DD&A increased from $19 million for the year ended December 31, 2010 to $56 million for the year ended December 31, 2011, an increase of $37 million as a result of increased production.  DD&A per Mcfe decreased from $1.71 per Mcfe to $1.24 per Mcfe, primarily as a result of increased reserve volumes in 2011 compared to 2010. As a successful efforts company, we evaluate the impairment of our proved natural gas, NGLs, and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. There were no impairment expenses recorded for the years ended December 31, 2010 or 2011 for proved properties. As of December 31, 2011, no significant well costs had been deferred for over one year pending proved reserves determination.

General and administrative expense.  General and administrative expense increased from $22 million for the year ended December 31, 2010 to $33 million for 2011, an increase of $11 million. The increase is primarily due to increased costs related to salaries, employee benefits, contract personnel and professional services expenses for additional personnel required for our capital expenditure program and production levels.  On a per-Mcfe basis, general and administrative expense decreased from $2.03 per Mcfe for the year ended December 31, 2010 to $0.74 per Mcfe for 2011.  No portion of general and administrative expenses was allocated to discontinued operations as the Company does not expect any reduction of such expenses as a result of the sale of the Arkoma and Piceance properties.  When all discontinued operations are included, general and administrative expenses decreased from $0.47 per Mcfe in 2010 to $0.37 per Mcfe in 2011.

Interest expense and realized and unrealized gains and losses on interest rate derivatives.  Interest expense increased from $56 million for the year ended December 31, 2010 to $74 million for 2011, an increase of $18 million, primarily as a result of increased borrowings on the Credit Facility and the issuance of $400 million of 7.25% senior notes in August 2011. We had entered into variable-to-fixed interest rate swap agreements that hedged our exposure to interest rate variations on our Credit Facility and second lien term loan facility. At December 31, 2010, one of these swaps remained outstanding with a notional amount of $225.0 million and a fixed pay rate of 4.11%.  This swap expired in July 2011.  For the year ended December 31, 2010, we realized a loss on interest rate swap agreements of $10 million, whereas in 2011 we had a realized loss on interest rate swap agreements of $4 million. There were no outstanding interest swap agreements at December 31, 2011.

Income tax expense.  Income tax expense related to continuing operations was $185 million in 2011 compared to $1 million in 2010 and is entirely comprised of deferred taxes in both years.  In general, we have not generated current taxable income in either the current or prior years, which is primarily attributable to the differing book and tax treatment of unrealized derivative gains and intangible drilling costs.  Each of our operating subsidiaries filed separate federal and state tax returns in 2010 and 2011; therefore, our provision for income taxes for those years consists of the sum of our provisions for each of the operating entities.  From time to time there has been proposed legislation in the U.S. Congress to eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that such legislation might be enacted.

Income from discontinued operations.  Income from discontinued operations includes the results of operations from the Arkoma Basin and Piceance Basin operations (including revenues and direct operating expenses and allocated income tax expense, but not general and administrative or interest expenses).  A detailed analysis of these operations is included in note 3 to the consolidated financial statements included elsewhere in the Annual Report on Form 10-K.  Income from discontinued operations decreased from income of $228 million in 2010 to income of $121 million in 2011, primarily as a result of a nonrecurring gain of $148 million recognized in 2010 on the sale of our Arkoma midstream assets.

Capital Resources and Liquidity

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, NGL, 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. We have approximately 4,900 potential well locations which will take many years to develop.  Additionally our proved undeveloped reserves will require an estimated $3 billion of development capital over the next five years.  A significant portion of this capital requirement will be funded out of operating cash flows. However, we may be required to generate or raise significant capital to conduct drilling activities on these potential drilling locations and to finance the development of our proved undeveloped reserves.

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During 2012, we raised capital through the issuance of $300 million of 6.00% senior notes due 2020, and in February 2013 we issued another $225 million of the 6.00% senior notes.  We also sold various properties for which we received cash proceeds of approximately $1.2 billion.  As a result of the issuances of the 6.00% notes, the borrowing base under the Credit Facility is currently $1.22 billion and lender commitments total $700 million, leaving us with borrowing capacity of $657 million.  At December 31, 2012, we had borrowed $217 million.  Current lender commitments can be increased to the full $1.22 billion borrowing base upon approval of the lending bank group. The borrowing base is determined every six months based on reserves, oil and gas commodity prices, and the value of our hedge portfolio.  The next redetermination of the borrowing base is scheduled to occur in May 2013.  Our hedge position provides us with additional liquidity as it provides us with the relative certainty of receiving a significant portion of our future expected revenues from operations despite potential declines in the price of natural gas. Our ability to make significant additional acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. Our Credit Facility is funded by a syndicate of 16 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of our Credit Facility.

In order to fully fund our 2013 capital budget, we believe it will be necessary to obtain additional capital.  We are considering several alternatives including increasing lender commitments on our Credit Facility, selling noncore gathering assets, or exploring further capital market transactions.  We may pursue a combination of these alternatives.  If necessary, we will revise our capital spending plans to 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 will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

For more information on our outstanding indebtedness, see “—Debt Agreements and Contractual Obligations.”

Cash Flows

The following table summarizes our cash flows for the years ended December 31, 2010, 2011, and 2012:

	Year Ended December 31,
	2010			2011			2012
	(in thousands)
Net cash provided by operating activities	$	127,791		$	266,307		$	332,255
Net cash used in investing activities	(230,672		)	(901,249		)	(463,491		)
Net cash provided by financing activities	101,200			629,297			146,882
Net increase (decrease) in cash and cash equivalents	$	(1,681	)	(5,645		)	$	15,646

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $128 million, $266 million and $332 million for the years ended December 31, 2010, 2011 and 2012, respectively. The increase in cash flows from operations from 2010 to 2011 and also from 2011 to 2012 was primarily the result of increased oil and gas production volumes and realized gains from commodity hedges, net of increased operating expenses and interest expense and changes in working capital.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas, NGLs, and oil prices. Prices for these commodities are determined primarily by prevailing market conditions. Factors including regional and worldwide economic activity, weather, infrastructure capacity to reach markets, and other variables 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 7A. Quantitative and Qualitative Disclosure About Market Risk.”

Cash Flow Used in Investing Activities

During the years ended December 31, 2010, 2011 and 2012, we used cash flows in investing activities of $231 million, $901 million and $463 million, respectively, as a result of our capital expenditures for drilling, development and acquisitions.  During 2012 we spent approximately $1.7 billion on investments in undeveloped leaseholds, development costs and gathering systems.  Net cash flow used in investing activities was reduced by realized cash proceeds of approximately $1.2 billion from the sale of the Piceance Basin, Arkoma Basin, and certain Appalachian gathering systems. The increase in cash flows used in investing activities in 2011 from 2010 resulted primarily from increased drilling and acquisition activities in the Marcellus Shale.  In September 2011, we also acquired a 7% overriding royalty interest related to 115,000 net acres operated by us in the core of our West Virginia and Pennsylvania Marcellus acreage position for $193 million.

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Our board of directors has approved a capital budget of up to $1.65 billion for 2013. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities in 2012 of $147 million was primarily the result of (i) $300 million of cash provided by the issuance of senior notes, net of (ii) net repayments of the Credit Facility of $148 million and other items of $5 million including deferred financing costs.

Net cash provided by financing activities in 2011 of $629 million was primarily the result of (i) $400 million of cash provided by the issuance of senior notes, (ii) net borrowings of $265 million on our Credit Facility, net of (iii) cash outflows for $7 million of deferred financing costs, and a $29 million distribution to equity members for tax liabilities.

Net cash provided by financing activities in 2010 of $101 million was primarily a result of (i) $156 million of cash provided by the issuance of senior notes, (ii) net payments of $42 million on our Credit Facility, and (iii) $13 million of other payment items including deferred financing costs.

Debt Agreements and Contractual Obligations

Senior Secured Revolving Credit Facility.  Our Credit Facility provides for a maximum borrowing base of $1.22 billion.  The borrowing base is redetermined semi-annually and the borrowing base depends on the amount of our proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions.  The next redetermination is scheduled to occur in May 2013.  . After giving effect to the issuance of the 6.00% senior notes due 2020 in November 2012 and February 2013, the borrowing base was $1.22 billion and lender commitments totaled $700 million.  Lender commitments can be increased to the full $1.22 billion upon approval of the lending group.  At December 31, 2012, we had $217 million of borrowings and $43 million of letters of credit outstanding under the Credit Facility.  As a result of the sale of the Piceance properties, $11 million of letters of credit outstanding at December 31, 2012 were terminated in March 2013.  The Credit Facility matures in May 2016.

Principal amounts borrowed are payable on the maturity date with such borrowings bearing interest that is payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters BBA Libor Rates Page 3750 for one, two, three, six or twelve months plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of our borrowing base utilized. The amounts outstanding under the facility are secured by a first priority lien on substantially all of our natural gas, NGLs, and oil properties and associated assets and are cross-guaranteed by each borrower entity along with each of their current and future wholly owned subsidiaries. For information concerning the effect of changes in interest rates on interest payments under this facility, see “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”  As of December 31, 2011 and 2012, borrowings and letters of credit outstanding under our senior secured revolving credit facility totaled $386 million and $217 million, respectively, and had a weighted average interest rate (excluding the impact of our interest rate swaps) of 2.12% and 1.91%, respectively. The facility contains restrictive covenants that may limit our ability to, among other things:

·incur additional indebtedness;

·sell assets;

·make loans to others;

·make investments;

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·enter into mergers;

·make certain payments to Antero Resources LLC;

·hedge future production;

·incur liens; and

·engage in certain other transactions without the prior consent of the lenders.

The Credit Facility also requires us to maintain the following two financial ratios:

·a current ratio, which is the ratio of our consolidated current assets (as defined) to our consolidated current liabilities, of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and

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

We were in compliance with such covenants and ratios as of December 31, 2011 and 2012.

Senior Notes.  We have $525 million of 9.375% senior notes outstanding, which are due December 1, 2017.  The notes are issued by Antero Finance and unsecured and effectively subordinate to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.  The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on June 1 and December 1 of each year.  Antero Finance may redeem all or part of the notes at any time on or after December 1, 2013 at redemption prices ranging from 104.688% on or after December 1, 2013 to 100.00% on or after December 1, 2015.  In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%.  At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

We also have $400 million of 7.25% senior notes outstanding, which are due August 1, 2019.  The notes are issued by Antero Finance and unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility.  The notes rank pari passu to the existing 9.375% senior notes.  The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on August 1 and February 1 of each year.  Antero Finance may redeem all or part of the notes at any time on or after August 1, 2014 at redemption prices ranging from 105.438% on or after August 1, 2014 to 100.00% on or after August 1, 2017.  In addition, on or before August 1, 2014, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 107.25% of the principal amount of the notes, plus accrued interest.  At any time prior to August 1, 2014, Antero Finance may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium and accrued interest.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

At December 31, 2012, we also had $300 million of 6.00% senior notes outstanding, which are due December 1, 2020.   On February 4, 2013, we issued an additional $225 million of the 6.00% notes for an aggregate amount of $525 million.  The notes are issued by Antero Finance and unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The notes rank pari passu to the existing 9.375% 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, commencing on June 1, 2013. Antero Finance may redeem all or part of the notes at any time on or after December 1, 2015 at redemption prices ranging from 104.50% on or after December 1, 2015 to 100.00% on or after December 1, 2018. In addition, on or before December 1, 2015, 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 Finance has not exercised its optional redemption

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rights upon a change of control, the note holders will have the right to require Antero Finance to repurchase all or a portion of the notes at a price equal to 101% of the principal amount of the notes, plus accrued interest.

We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under our Credit Facility and for development of our oil and natural gas properties.

The senior notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained.  We were in compliance with such covenants and the coverage ratio requirement as of December 31, 2011 and 2012.

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, 2013. At December 31, 2012, there were no outstanding borrowings under this facility.

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

Contractual Obligations. A summary of our contractual obligations as of December 31, 2012 is provided in the following table.

(in millions)	2013		2014		2015		2016		2017		Thereafter		Total
Credit Facility(1)	$	—	$	—	$	—	$	217	$	—	$	—	$	217
Senior notes—principal(2)	25		—		—		—		525		700		1,250
Senior notes—interest(2)	99		96		96		96		96		112		595
Drilling rig and frac service commitments(3)	150		98		44		—		—		—		292
Firm transportation(4)	36		93		116		116		113		854		1,328
Gas processing, gathering, and compression service(5)	111		107		126		131		125		564		1,164
Office and equipment leases	1		3		3		3		3		15		28
Asset retirement obligations(6)	—		—		—		—		—		11		11
Total	$	422	$	397	$	385	$	563	862		$	2,256	$	4,885

(1)Includes outstanding principal amount at December 31, 2012. This table does not include future commitment fees, interest expense or other fees on the Credit Facility because they are floating rate instruments and we cannot determine with accuracy the 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 due 2020, and the $25 million note due 2013 assumed in the Bluestone acquisition.

(3)At December 31, 2012, we had contracts for the services of 14 rigs, which expire at various dates from January 2013 through January 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 market.  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.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The

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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. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See note 2 to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Natural Gas, NGL and Oil Properties

Successful Efforts Method

Our natural gas, NGL, and oil exploration and production activities are accounted for using the successful efforts method. Under this method, costs of drilling successful exploration wells and development costs are capitalized and amortized on a geological reservoir basis using the unit-of-production method as natural gas, NGL, and oil is produced. Geological and geophysical costs, delay rentals and costs to drill exploratory wells that do not discover proved reserves are expensed as exploration costs. The costs of development wells are capitalized whether productive or nonproductive. Natural gas, NGL, and oil lease acquisition costs are also capitalized. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unproved property costs are costs related to unevaluated properties and are transferred to proved natural gas and oil properties if the properties are determined to be productive. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered.  Unevaluated natural gas, NGL, and oil properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage. If it is determined that it is probable that reserves will not be discovered, the cost of unproved leases is charged to impairment of unproved properties. During the years ended December 31, 2010, 2011, and 2012 we charged impairment expense for expired or expiring leases with a cost of $36 million, $11 million, and $13 million, respectively. The assessment of unevaluated natural gas, NGL, and oil properties to determine any possible impairment requires managerial judgment.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in anticipation of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred. Additionally, the application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred.

Natural Gas, NGL and Oil Reserve Quantities and Standardized Measure of Future Cash Flows

Our independent engineers and internal technical staff prepare the estimates of natural gas, NGL, and oil reserves and associated future net cash flows. Current accounting guidance allows only proved natural gas, NGL, and oil reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of natural gas, NGL, and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our independent engineers and internal technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Natural gas, NGL, and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas, NGL, and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGL, and oil prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of natural gas, NGL, and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions

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are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Impairment of Proved Properties

We review our proved natural gas, NGL, and oil properties for impairment on a geological reservoir basis whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected future cash flows of our gas and oil properties and compare these future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the natural gas, NGL, and oil properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded. We did not record any impairment charges for proved properties in 2010, 2011 or 2012.

Off-Balance Sheet Arrangements

We have various contractual obligations that are not reflected on our balance sheet.   See “Debt Agreements and Contractual Obligations” included under this Item 7 for commitments under operating leases, drilling rig service agreements, firm transportation, and gas processing and compression service agreements.

Item 7A.        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.

Commodity Price Risk and Hedges

Commodity Hedging Activities

Our primary market risk exposure is in the price we received for our natural gas, NGL, and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas, NGL, 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, NGL, and oil production when management believes that favorable future prices can be secured. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the Dominion South, Columbia Gas Appalachian Transmission (“CGTAP”), and Columbia Gas Louisiana (“CGLA”) Indexes.

At December 31, 2012, we had in place natural gas and oil swaps covering portions of our projected production from 2013 through 2018.  Our hedge position as of December 31, 2012 is summarized in note 12 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.  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 2018. Based on our annual production and our fixed price swap contracts in place during 2012, our annual income before taxes for the year ended December 31, 2012 would have

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decreased by approximately $2.0 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.4 million for each $1.00 per barrel decrease in crude oil prices.

All derivative instruments, other than those that meet the normal purchase and normal sales exception, are recorded at fair market value in accordance with US GAAP and are included in the consolidated balance sheets as assets or liabilities. Fair values are adjusted for non-performance risk. As required under US GAAP, all 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.” In 2012, approximately 81% of our production volumes were hedged, which resulted in realized hedge gains of $271 million.  In 2011, approximately 77% of our production volumes were hedged, which resulted in realized hedge gains of $117 million.  In 2010, approximately 79% of our production volumes were hedged, which resulted in realized gains on hedges of $74 million.

Mark-to-market adjustments of derivative instruments produce earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled. We expect continued volatility in the fair value of our derivative instruments. Our cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. At December 31, 2012, the estimated fair value of all of our commodity derivative instruments was a net asset of $532 million comprised of current and noncurrent assets.  See note 12 to the consolidated financial statements included elsewhere in this Annual Report on Form 10-K for a summary of realized or unrealized gains or losses on commodity derivative contracts for 2010, 2011, and 2012.

By removing price volatility from a portion of our expected natural gas production through December 2018, 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.

Interest Rate Risks and Hedges

During the year ended December 31, 2012, we had indebtedness outstanding under our Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this indebtedness for the years ended December 31, 2011 and 2012 was approximately 2.1% during both years.   A 1.0% increase in each of the average LIBOR rate and federal funds rate in 2012 would have resulted in an estimated $3 million increase in interest expense for the year ended December 31, 2012.

At December 31, 2012, we had no interest rate swaps outstanding.  From time to time in the past, we have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our variable rate debt.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($532 million at December 31, 2012), joint interest receivables ($6 million at December 31, 2012) and the sale of our natural gas production ($47 million in receivables at December 31, 2012), which we market to energy marketing companies, refineries and affiliates.

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 cash, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have economic hedges in place with ten different counterparties; all but one are lenders in our Credit Facility.  The fair value of our commodity derivative contracts of approximately $532 million at December 31, 2012 includes the following values by bank counterparty: JP Morgan - $94 million; BNP Paribas - $124 million; Credit Suisse - $150 million; Wells Fargo - $86 million; Barclays - $57 million; Deutsche Bank - $11 million; and Union Bank - $4 million.  Additionally, contracts with Dominion Field Services account for $6 million of the fair value. The credit ratings of certain of these banks were downgraded in 2011 because of the sovereign debt crisis in Europe.  The estimated fair value of our commodity derivative assets has been risk adjusted using a discount rate based upon the respective published credit default swap rates at December 31, 2012 for each of the European and American banks.  We believe that all of these institutions currently are acceptable credit risks. We are not required to provide credit support or collateral to any of our counterparties under current contracts, nor are they required to provide credit support to us. As of December 31, 2012, we have no past due receivables from or payables to any of our counterparties.

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

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We are also subject to credit risk due to concentration of our natural gas receivables with 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.

Item 8.Financial Statements and Supplementary Data

The Report of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth on pages F-1 through F-26 of this report and are incorporated herein by reference.

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.          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 annual report.  Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.  Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2012.

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 fourth quarter of 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control Over Financial Reporting

The management of Antero Resources LLC is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

Our internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and Directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.

Under the supervision of, and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012.

Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report on Form 10-K. Therefore, this Annual Report on Form 10-K does not include such an attestation.

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Item 9B.Other Information

Not applicable.

PART III

Item 10.Directors, Executive Officers and Corporate Governance

Officers and Directors

The following table sets forth names, ages and titles of our officers and directors.

Name	Age	Title
Peter R. Kagan(1)	45	Director
W. Howard Keenan, Jr.(1)	62	Director
Christopher R. Manning(1)	45	Director
Paul M. Rady	59	Chairman of the Board of Directors and Chief Executive Officer
Glen C. Warren, Jr.	57	Director, President, Chief Financial Officer and Secretary
Kevin J. Kilstrom	58	Vice President—Production
Brian A. Kuhn	54	Vice President—Land
Mark D. Mauz	55	Vice President—Gathering, Marketing and Transportation
Steve M. Woodward	54	Vice President—Business Development
Alvyn A. Schopp	54	Vice President—Accounting & Administration and Treasurer
Ward McNeilly	62	Vice President—Reserves, Planning and Midstream

(1)Member of the Audit Committee and the Compensation Committee.

Our board of directors currently consists of five members who have been designated in accordance with our limited liability company agreement. Each of Warburg Pincus, Yorktown Energy Partners and Trilantic Capital Partners currently has the right to designate one director to the board of directors of Antero. The remaining two members of Antero’s board of directors are our Chief Executive Officer and our Chief Financial Officer. Warburg Pincus currently has the right to designate one additional member of Antero’s board of directors after consultation with the management directors and the other investors in Antero.  Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Our officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or principal officers.

Peter R. Kagan has served as a director since 2004. Mr. Kagan has been with Warburg Pincus since 1997 and leads the firm’s investment activities in energy and natural resources. He is also a member of the firm’s Executive Management Group. Mr. Kagan received an A.B. degree cum laude from Harvard College and J.D. and M.B.A. degrees with honors from the University of Chicago. Prior to joining Warburg Pincus, he worked in investment banking at Salomon Brothers in both New York and Hong Kong. Mr. Kagan currently also serves on the boards of directors of the following public companies: Laredo Petroleum Holdings, Inc., MEG Energy Corp., Targa Resources Corp., and Targa Resources Partners LP., as well as the boards of several private companies.

Mr. Kagan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry.  We believe his background and skill set make Mr. Kagan well-suited to serve as a member of our board of directors.  Mr. Kagan is the director designee of Warburg Pincus pursuant to the terms of the Antero Resources LLC limited liability company agreement.

W. Howard Keenan, Jr. has served as a director since 2004. Mr. Keenan has over thirty years of experience in the financial and energy businesses. Since 1997, he has been a Member of Yorktown Partners LLC, a private equity investment manager focused on the energy industry. Mr. Keenan currently serves on the Board of Directors of Concho Resources Inc. and GeoMet, Inc. From 1975 to 1997, he was in the Corporate Finance Department of Dillon, Read & Co. Inc. and active in the private equity and energy areas, including the founding of the first Yorktown Partners fund in 1991. He is serving or has served as a director of multiple Yorktown Partners portfolio companies. Mr. Keenan holds an A.B. degree cum laude from Harvard College and an M.B.A. degree from Harvard University.

Mr. Keenan has significant experience with energy companies and investments and broad knowledge of the oil and gas industry.  We believe his background and skill set make Mr. Keenan well-suited to serve as a member of our board of directors.  Mr. Keenan is the director designee of Yorktown Energy Partners pursuant to the terms of the Antero Resources LLC limited liability company agreement.

Christopher R. Manning has served as a director since 2005. Mr. Manning is a Partner and member of the Executive Committee of Trilantic Capital Partners.  His primary focus is on investments in the energy sector.  Mr. Manning joined Lehman Brothers Merchant Banking in 2000 and was concurrently the Head of Lehman Brothers’ Investment Management Division, including both the Asset Management and Private Equity businesses, in Asia-Pacific from 2006 to 2008. He was also a member of the Global Investment

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Management Division Executive Committee and the Private Equity Division Operating Committee.   Prior to Lehman Brothers, Mr. Manning was the chief financial officer of The Wing Group, a developer of international power projects. Prior to The Wing Group, he was in the investment banking department of Kidder, Peabody & Co., where he worked on M&A and corporate finance transactions. Mr. Manning currently serves on the boards of Enduring Resources, Mediterranean Resources, the Cross Group, VantaCore Partners, and Velvet Energy.  Mr. Manning holds an M.B.A. from The Wharton School of the University of Pennsylvania and a B.B.A. from the University of Texas at Austin.

Mr. Manning has significant experience with energy companies and investments and broad knowledge of the oil and gas industry.  We believe his background and skill set make Mr. Manning well-suited to serve as a member of our board of directors.  Mr. Manning is the director designee of Trilantic Capital Partners pursuant to the terms of the Antero Resources LLC limited liability company agreement.

Paul M. Rady has served as Chief Executive Officer and Chairman of the Board of Directors since May 2004. Mr. Rady also served as Chief Executive Officer and Chairman of the Board of Directors of our predecessor company, Antero Resources Corporation, from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero Resources Corporation, Mr. Rady served as President, CEO and Chairman of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Prior to Pennaco, Mr. Rady was with Barrett Resources from 1990 until 1998 where he initially was recruited as Chief Geologist in 1990, then served as Exploration Manager, EVP Exploration, President, COO and Director and ultimately CEO. Mr. Rady began his career with Amoco where he served 10 years as a geologist focused on the Rockies and Mid-Continent. Mr. Rady is the managing member of Salisbury Investment Holdings, LLC. Mr. Rady holds a B.A. in Geology from Western State College of Colorado and M.Sc. in Geology from Western Washington University.

Mr. Rady’s significant experience as a chief executive of oil and gas companies, together with his training as a geologist and broad industry knowledge, enable Mr. Rady to provide the board with executive counsel on a full range of business, strategic and professional matters.

Glen C. Warren, Jr. has served as President, Chief Financial Officer and Secretary and as a director since May 2004. Mr. Warren also served as President and Chief Financial Officer and as a director of our predecessor company, Antero Resources Corporation, from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. Prior to Antero Resources Corporation, Mr. Warren served as EVP, CFO and Director of Pennaco Energy from 1998 until its sale to Marathon in early 2001. Mr. Warren spent 10 years as a natural resources investment banker focused on equity and debt financing and M&A advisory with Lehman Brothers, Dillon Read and Kidder Peabody. Mr. Warren began his career as a landman in the Gulf Coast region with Amoco, where he spent six years. Mr. Warren is the managing member of Canton Investment Holdings, LLC. Mr. Warren holds a B.A. from the University of Mississippi, a J.D. from the University of Mississippi School of Law and an M.B.A from the Anderson School of Management at U.C.L.A.

Mr. Warren’s significant experience as a chief financial officer of oil and gas companies, together with his experience as an investment banker and broad industry knowledge, enable Mr. Warren to provide the board with executive counsel on a full range of business, strategic, financial and professional matters.

Kevin J. Kilstrom has served as Vice President of Production since June 2007. Mr. Kilstrom was a Manager of Petroleum Engineering with AGL Energy of Sydney, Australia from 2006 to 2007. Prior to AGL, Mr. Kilstrom was with Marathon Oil as an Engineering Consultant and Asset Manager from 2003 to 2007 and as a Business Unit Manager for Marathon’s Powder River coal bed methane assets from 2001 to 2003. Mr. Kilstrom also served as a member of the board of directors of three Marathon subsidiaries from October 2003 through May 2005. Mr. Kilstrom was an Operations Manager and reserve engineer at Pennaco Energy from 1999 to 2001. Mr. Kilstrom was at Amoco for more than 22 years prior to 1999. Mr. Kilstrom holds a B.S. in Engineering from Iowa State University and an M.B.A. from DePaul University.

Brian A. Kuhn has served as Vice President of Land since April 2005. Mr. Kuhn also served as Vice President of Land of our predecessor company, Antero Resources Corporation, from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. From 2001 to 2002, Mr. Kuhn served as Head of Denver Land Department for Marathon Oil. Mr. Kuhn was the Vice President—Land at Pennaco Energy from 1998 to 2001. Mr. Kuhn was a Division Landman with Barrett Resources from 1993 to 1998. Mr. Kuhn was a Landman with Amoco for 13 years prior to 1993. Mr. Kuhn holds a B.B.A. in Petroleum Land Management from the University of Oklahoma.

Mark D. Mauz has served as Vice President of Gathering, Marketing and Transportation since April 2006. From 1993 to 2006, Mr. Mauz was with Duke Energy Field Services, most recently as its Managing Director of the Rockies Region. Mr. Mauz spent from 1990 to 1993 with Amoco in natural gas marketing and 9 years prior to 1990 as a Landman. Mr. Mauz holds a B.S. in Business from the University of Colorado.

Steven M. Woodward has served as Vice President of Business Development since April 2005. Mr. Woodward also served as Vice President of Business Development of our predecessor company, Antero Resources Corporation, from its founding in 2002 to its ultimate sale to XTO Energy, Inc. in April 2005. From 1993 until 2002, Mr. Woodward was in senior business/project development roles with Dynegy. From 1990 to 1992, Mr. Woodward was with Reliance Pipeline Company as a Manager of Business Development.

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From 1988 to 1990, Mr. Woodward was at Western Gas Resources in a Business Development role. From 1981 to 1988, Mr. Woodward was with ARCO Oil & Gas Company in various engineering roles. Mr. Woodward holds a B.S. in Mechanical Engineering from the University of Colorado.

Alvyn A. Schopp has served as Vice President of Accounting and Administration and Treasurer since January 2005. Mr. Schopp also served as Controller and Treasurer from 2003 to 2005 and as Vice President of Accounting and Administration and Treasurer of our predecessor company, Antero Resources Corporation, from January 2005 until its ultimate sale to XTO Energy, Inc. in April 2005. From 2002 to 2003, Mr. Schopp was an Executive and Financial Consultant with Duke Energy Field Services. From 1993 to 2000, Mr. Schopp was CFO, Director and ultimately CEO of T-Netix. From 1980 to 1993 Mr. Schopp was with KPMG LLP, most recently as a Senior Manager. Mr. Schopp holds a B.B.A. from Drake University.

Ward D. McNeilly serves as Vice President of Reserves, Planning & Midstream, and has been with the Company since October 2010.  Mr. McNeilly has 34 years of experience in oil and gas asset management, operations, and reservoir management.  From 2007 to October 2010, Mr. McNeilly was BHP Billiton’s Gulf of Mexico Operations Manager.  From 1996 through 2007, Mr. McNeilly served in various North Sea and Gulf of Mexico Deepwater operations and asset management positions with Amoco and then BP.  Mr. McNeilly served in a number of different domestic and international positions with Amoco from 1979 to 1996.  Mr. McNeilly holds a B.S. in Geological Engineering from the Mackay School of Mines at the University of Nevada.

Audit Committee

Our audit committee is comprised of Messrs. Kagan, Keenan and Manning.  Our board of directors has determined that each of Messrs. Kagan, Keenan and Manning are “audit committee financial experts” within the meaning of applicable SEC rules as a result of their extensive experience as investment bankers and principals of private equity firms.  Because we do not have a class of securities listed on any national securities exchange or national securities association, we are not required to have an audit committee comprised of independent directors for purposes of the Securities Exchange Act of 1934, as amended.  Accordingly, our board of directors has not made any determination as to whether the members of the audit committee of our board of directors satisfy the independence requirements applicable to audit committee members under the Exchange Act.

Code of Ethics

We have adopted a Financial Code of Ethics that applies to our principal executive, financial and accounting officers.  A copy of the Financial Code of Ethics applicable to our principal executive, financial and accounting officers is available upon written request to our Secretary at 1625 17th Street, Denver, Colorado 80202.

Item 11.Executive Compensation

Compensation Discussion and Analysis

Overview

This Compensation Discussion and Analysis (1) provides an overview of our compensation policies and programs; (2) explains our compensation objectives, policies and practices with respect to our executive officers; and (3) identifies the elements of compensation for each of the individuals identified in the following table, who we refer to in this Compensation Discussion and Analysis as our “Named Executive Officers.”

Name	Principal Position
Paul M. Rady	Chairman of the Board of Directors and Chief Executive Officer
Glen C. Warren, Jr.	Director, President, Chief Financial Officer and Secretary
Kevin J. Kilstrom	Vice President—Production
Alvyn A. Schopp	Vice President—Accounting and Administration
Ward D. McNeilly	Vice President—Reserves, Planning and Midstream

Each of our Named Executive Officers is an employee of Antero Resources Appalachian Corporation, which is a wholly owned subsidiary of Antero. The Compensation Committee of the Antero Board of Directors, or the Antero Board of Directors, as appropriate, approves all compensation decisions for our Named Executive Officers. The Antero Board of Directors and the Antero Resources Appalachian Corporation Board of Directors are comprised of the same members and are collectively referred to in this Item 11 as the “Board.”

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Compensation Philosophy and Objectives of Our Compensation Program

Since our inception, we have sought to profitably grow our privately held, independent oil and gas company and our compensation philosophy has been primarily focused on recruiting individuals who are motivated to help us achieve that goal. Accordingly, we have structured our compensation program to attract highly qualified and experienced individuals capable of contributing to the continued growth of our company, both in terms of size of net production and oil and gas reserves and enterprise value.  To achieve these objectives, we provide what we believe is a competitive total compensation package to our Named Executive Officers through a combination of base salary, annual cash incentive payments, transaction bonuses and long-term equity-based incentive awards, as discussed in more detail below.

Implementing Our Objectives

Role of the Board of Directors, Compensation Committee and our Executive Officers

Executive compensation decisions are typically made on an annual basis by the Compensation Committee with input from Paul M. Rady, our Chief Executive Officer, and Glen C. Warren, Jr., our President and Chief Financial Officer. Specifically, after reviewing relevant market data and surveys within our industry, Messrs. Rady and Warren provide recommendations to the Compensation Committee regarding the compensation levels for our existing Named Executive Officers (including themselves) and our executive compensation program as a whole. Messrs. Rady and Warren attend all Compensation Committee meetings. After considering these recommendations, the Compensation Committee typically meets in executive session and adjusts base salary levels, cash bonus awards and determines the amount of any equity grants for each of our Named Executive Officers. In making executive compensation recommendations, Messrs. Rady and Warren consider each Named Executive Officer’s performance during the year, our performance during the year, as well as comparable company compensation levels and independent oil and gas company compensation surveys. While the Compensation Committee gives considerable weight to Messrs. Rady and Warren’s recommendations on compensation matters, the Compensation Committee has the final decision-making authority on all executive compensation matters. No other officers have assumed a role in the evaluation, design or administration of our executive officer compensation program.

Role of External Advisors

In December 2012, we engaged Frederick W.Cook & Co., (“F.W. Cook”) to provide periodic compensation consulting services, as determined by management. F.W.Cook did not provide and does not currently provide any other services to our company. Our objective when hiring F.W. Cook was to assess our level of competitiveness for executive-level talent. Pursuant to the terms of its engagement, F.W.Cook:

·Collected and reviewed all relevant company information, including our historical compensation data and our organizational structure;

·With input of management, established a peer group of companies to use for executive compensation comparisons;

·Assessed our compensation program’s position relative to market for our top nine executive officers and stated compensation philosophy;

·Prepared a report of its analysis, findings and recommendations for our executive compensation program.

F.W.Cook’s report was presented by Messrs. Rady and Warren to the Board as a whole in December 2012. The report was utilized by Messrs.Rady and Warren when making their recommendations to the Board for fiscal 2012 compensation decisions.

Competitive Benchmarking

When formulating their compensation recommendations for the Compensation Committee, Messrs. Rady and Warren compare the pay practices for our Named Executive Officers against the pay practices of other companies to assist them in determining base salaries and incentive compensation for our Named Executive Officers. This process recognizes our management’s philosophy that, while our compensation practices should be competitive in the marketplace, marketplace information is only one of the many factors considered in assessing the reasonableness of our executive compensation program.

Messrs. Rady and Warren hired F.W. Cook to assess the total compensation levels of our top nine executives relative to market. In addition, Messrs. Rady and Warren used statistical information from the 2012 Oil and Gas E&P Industry Compensation Survey (the “ECI Survey”) prepared by Effective Compensation, Incorporated (“ECI”) to supplement F.W. Cook’s Peer Group data. Messrs. Rady and Warren considered the results of the F.W. Cook Survey data and ECI Survey data when making their recommendations to the Board for fiscal 2012 decisions.

F.W. Cook Survey Data. In 2012, F.W. Cook used the following parameters when constructing the peer group for its assessment: (1) unconventional resource-focused exploration and production companies that are publically traded (without regard to size), (2) companies with a good performance track record, (3) companies with a strong management team with high quality technical expertise and (4) companies with more than $4.0 billion in enterprise value. Using these parameters and collaborating with Messrs. Rady and Warren, F.W. Cook developed an industry reference group comprised of 13 companies (the “F.W. Cook Peer Group”). The F.W. Cook Peer Group included the following companies:

·Cabot Oil & Gas Corporation;

·Cimarex Energy Co.;

·Concho Resources Inc.;

·EQT Corp.;

·Noble Energy Inc.;

·Pioneer Natural Resources Co.;

·Plains Exploration & Production Co.;

·Range Resources Corp.;

·SandRidge Energy Inc.;

·SM Energy Co.;

·Southwestern Energy Co.;

·Ultra Petroleum Corp.; and

·Whiting Petroleum Corp.

·ECI Survey Data. Data from ECI was used because it is specific to the energy industry and derives its data from direct contributions from a large number of participating companies with which we compete for talent. The ECI Survey was used to compare our executive compensation program against the executive compensation programs at the following companies (collectively, the “Peer Group”):

·Cabot Oil and Gas Corporation;

·Cimarex Energy Co.;

·EQT Corporation;

·EXCO Resources, Inc.;

·Newfield Exploration Company;

·Range Resources Corporation;

·SandRidge Energy;

·Southwestern Energy Company;

·Whiting Petroleum Corporation; and

·WPX Energy, Inc.

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Due to the broad responsibilities of our Named Executive Officers and our status as a privately held company, comparing survey data to the job descriptions of our Named Executive Officers is sometimes difficult. However, as discussed above, our compensation objective is designed to be competitive with the peer companies listed above. Therefore, when formulating their recommendations to the Compensation Committee, Messrs. Rady and Warren generally target compensation levels that are in the median range by reference to persons with similar duties at companies in our peer group.  However, actual compensation decisions for individual officers are the result of a subjective analysis of a number of factors, including the individual officer’s role within our organization, performance, experience, skills or tenure with us, changes to the individual’s position and trends in compensation practices within the Peer Group or industry. Each of our Named Executive Officer’s current and prior compensation is considered in setting future compensation. Specifically, the amount of each Named Executive Officer’s current compensation is considered as a base against which the Compensation Committee makes determinations as to whether adjustments are necessary to retain the executive in light of competition and in order to provide continuing performance incentives. Thus, the Compensation Committee’s determinations regarding compensation are the result of the exercise of judgment based on all reasonably available information and, to that extent, are discretionary.

Assessment of Individual and Company Performance

We believe that a balance of individual and company performance criteria should be used in establishing total compensation. Therefore, in determining the level of compensation for each Named Executive Officer, the Compensation Committee subjectively considers our overall financial and operational performance and the relative contribution and performance of each of our Named Executive Officers as described in more detail below.

Elements of Compensation

Our Named Executive Officers’ compensation includes the following key components:

·Base salaries;

·Annual cash bonus incentive payments;

·Transaction bonuses; and

·Long-term equity-based incentive awards.

Base Salaries

Base salaries are designed to provide a minimum, fixed level of cash compensation for services rendered during the year. Base salaries are generally reviewed annually, but are not systemically increased if the Compensation Committee believes that (1) our executives are currently compensated at proper levels in light of our Company’s performance or external market factors, or (2) an increase or addition to other elements of compensation would be more appropriate in light of our stated objectives.

In addition to providing a base salary that is competitive with other independent oil and gas exploration and production companies, the Compensation Committee also considers pay levels within our company to appropriately align each of our Named Executive Officer’s base salary level relative to the base salary levels of our other officers so that it accurately reflects such officer’s relative skills, responsibilities, experience and contributions to our company. To that end, annual base salary adjustments are based on a subjective analysis of many individual factors, including:

·the responsibilities of the officer;

·the period over which the officer has performed these responsibilities;

·the scope, level of expertise and experience required for the officer’s position;

·the strategic impact of the officer’s position; and

·the potential future contribution and demonstrated individual performance of the officer.

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In addition to the individual factors listed above, our overall business performance and implementation of company objectives are taken into consideration in connection with determining annual base salaries. While these metrics generally provide context for making salary decisions, base salary decisions do not depend on attainment of specific goals or performance levels and no specific weighting is given to one factor over another.

Fiscal 2012 Decisions.  In December 2011, after considering the individual and company performance factors described above along with our Peer Group companies, Messrs. Rady and Warren recommended, and the Compensation Committee approved, nominal increases in the base salaries of our Named Executive Officers. These increases became effective as of January 1, 2012 and are reflected in the Summary Compensation Table.

Fiscal 2013 Decisions. In December 2012, after comparing base salary levels to the F.W. Cook Peer Group and the ECI Peer Group (as described in more detail above under “Compensation Discussion and Analysis—Implementing Our Objectives—Competitive Benchmarking”) and considering the individual and business factors described above, Messrs. Rady and Warren recommended, and the Compensation Committee approved, increases in the base salaries of our Named Executive Officers. The increases became effective as of January 1, 2013. The adjusted base salary amounts were slightly below the median of both the F.W. Cook Peer Group and the ECI Peer Group.

Executive Officer	Base Salary Prior to January 2012		Base Salary as of January 2012		Percentage Increase		Base Salary as of January 2013		Percentage Increase
Paul M. Rady	$	475,000	$	515,000	8	%	$	650,000	26	%
Glen C. Warren, Jr.	$	395,000	$	425,000	8	%	$	525,000	24	%
Kevin J. Kilstrom	$	290,000	$	310,000	7	%	$	350,000	13	%
Alvyn A. Shopp	$	290,000	$	310,000	7	%	$	350,000	13	%
Ward D. McNeilly	$	255,000	$	280,000	10	%	$	315,000	13	%

Annual Cash Incentive Payments

Annual cash incentive payments, which we also refer to as cash bonuses, are a key component of each Named Executive Officer’s annual compensation package. The Compensation Committee believes that discretionary cash bonuses are an appropriate way to further our goals of attracting, retaining, and rewarding highly qualified and experienced officers and avoiding an environment that might cause undue pressure to meet specific financial or individual performance goals. In December of each year, the Compensation Committee determines whether to pay cash bonuses from a bonus pool to some or all of our employees, including our Named Executive Officers, and, if so, the amount of such cash bonuses (which may range from 0% to 100% of an executive officer’s base salary). The Compensation Committee’s decisions are based on recommendations from Messrs. Rady and Warren. Messrs. Rady and Warren formulate their recommendations based in part on input from functional managers within our organization, including certain of our vice presidents. The factors considered when determining the amount of discretionary cash bonus awards, if any, are similar to those considered when setting and adjusting base salaries. No particular weight is assigned to any of these factors.

Fiscal 2012 Decisions.  A discretionary cash bonus was awarded to each of our Named Executive Officers in December 2012. These awards were made based upon the factors described above under “—Base Salaries.” The size of each of these bonuses was determined without regard to any objective metrics and was based on the judgment of the Compensation Committee.  The bonuses paid to each Named Executive Officer are reflected below in the “Bonus” column of the Summary Compensation Table.

Transaction Bonuses

Pursuant to the terms of Antero’s limited liability company agreement, a “Transaction Bonus Pool” is created upon a direct or indirect disposition of all or substantially all the assets or equity interests of any of our operating subsidiaries (a “Qualifying Transaction”).  Each Transaction Bonus Pool is an amount equal to 3% of the “profit,” as defined under our limited liability company agreement, generated with respect to the disposition of a particular operating subsidiary. The Transaction Bonus Pool is available to pay bonuses to individuals who are employees of any of our operating subsidiaries as of the date of the disposition (including, potentially, our Named Executive Officers), but the amount of any individual’s transaction bonus and whether any particular individual receives a transaction bonus in connection with a disposition is determined by the Compensation Committee at the time of any such disposition. Transaction bonus awards are intended to incentivize our employees to increase the value of our operating subsidiaries for the benefit of our unitholders by allowing them to share in the profits of any disposition of any such operating subsidiary. The amount of any transaction bonus awards made to an employee is offset against future amounts that such employee would be entitled to receive in connection with future distributions by Antero as a result of the ownership by such employee of certain units in Antero and in Antero Resources Employee Holdings LLC (which are described below under “—Long-Term Equity-Based Incentive Awards”).

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No Qualifying Transactions occurred during fiscal 2012 and, therefore, no transaction bonuses have been reflected in the 2012 “Bonus” column of the Summary Compensation Table.

Long-Term Equity-Based Incentive Awards

Our long-term equity-based incentive program is designed to provide each of our employees with an incentive to focus on the long-term success of our company and to act as a long-term retention tool by aligning the interests of our employees with those of our stakeholders.

In connection with our November 2009 corporate reorganization, Antero Resources Employee Holdings LLC (“Holdings”) was established to hold a portion of our units that were set aside at the time of the reorganization to be used for employee incentive compensation. We grant units in Holdings to our employees, including our Named Executive Officers, as a means of providing them with long-term equity incentive compensation in an affiliated entity that may directly profit from any success we achieve. This structure enables us to identify a fixed number of Antero units on which any distributions will flow through Holdings to our employees. We believe that providing equity compensation from Holdings allows us to retain the ability to incentivize our executives to focus on our long-term success.

Because a portion of the units granted to certain of our Named Executive Officers remain unvested, the Compensation Committee believes that these awards continue to provide significant retentive value.  As a result, the Compensation Committee determined that there was no need to grant additional restricted unit awards to our Named Executive Officers in 2010, 2011 or 2012.

Other Benefits

Health and Welfare Benefits

Our Named Executive Officers are eligible to participate in all of our employee health and welfare benefit arrangements on the same basis as other employees (subject to applicable law). These arrangements include medical, dental and disability insurance, as well as health savings accounts. These benefits are provided in order to ensure that we are able to competitively attract and retain officers and other employees. This is a fixed component of compensation, and these benefits are provided on a non-discriminatory basis to all employees.

Retirement Benefits

We maintain an employee retirement savings plan through which employees may save for retirement or future events on a tax-advantaged basis. While the plan permits us to make discretionary matching and non-elective contributions, we have not made any employer contributions in recent years.  Participation in the 401(k) plan is at the discretion of each individual employee, and our Named Executive Officers participate in the plan on the same basis as all other employees.

Perquisites and Other Personal Benefits

We believe that the total mix of compensation and benefits provided to our Named Executive Officers is currently competitive and, therefore, perquisites do not play a significant role in our Named Executive Officers’ total compensation.

Employment, Severance or Change in Control Agreements

We do not maintain any employment, severance or change in control agreements with any of our Named Executive Officers.

As discussed below under “Potential Payments Upon a Termination or a Change in Control,” Mr. McNeilly could be entitled to receive certain payments or accelerated vesting of his unit awards that remain unvested upon his termination of employment with us under certain circumstances or the occurrence of certain corporate events.

Other Matters

Equity Ownership Guidelines and Hedging Prohibition

Because our equity securities are not publicly traded, we do not currently have ownership requirements or an equity retention policy for our Named Executive Officers. We also do not have a policy that restricts our Named Executive Officers from limiting their economic exposure to our equity.

Tax and Accounting Treatment of Executive Compensation Decisions

Because none of our operating subsidiaries are publicly held corporations, neither the Board nor the Compensation Committee has adopted a policy with respect to the limitation under Section 162(m) of the Internal Revenue Code of 1986, as amended (the

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“Code”), which generally imposes a $1.0 million limit on the amount that a public corporation may deduct for federal income tax purposes in any year with regard to compensation paid to certain executive officers.

Risk Assessment

Messrs. Rady and Warren reviewed our compensation policies and practices to determine where they create risks that are reasonably likely to have a material adverse effect on our company. In connection with this risk assessment, Messrs. Rady and Warren reviewed the design of our compensation and benefits program and related policies and the potential risks that could be created by the programs and determined that certain features of our programs and corporate governance generally help mitigate risk. Among the factors Messrs. Rady and Warren considered were the mix of cash and equity compensation, the balance between short- and long term objectives of our incentive compensation, the degree to which programs provided for discretion to determine payout amounts and our general governance structure. Messrs. Rady and Warren reviewed and discussed the results of this assessment with the Compensation Committee as part of their annual program recommendations.

The Compensation Committee believes that our approach of evaluating overall business performance and implementation of company objectives assist in mitigating excessive risk-taking that could harm our value or reward poor judgment by our executives. Several features of our programs reflect sound risk management practices. The Compensation Committee believes our overall compensation program provides a reasonable balance between short and long-term objectives, which helps mitigate the risk of excessive risk-taking in the short term. Further, with respect to our incentive compensation programs, the metrics that determine ultimate value are associated with total company value and avoid an environment that might cause pressure to meet specific financial or individual performance goals. In addition, the performance criteria reviewed by the Compensation Committee in determining cash bonuses are based on overall individual performance relative to continually evolving company objectives, and the Compensation Committee uses its subjective judgment in setting bonus levels for our officers. This is based on the Compensation Committee’s belief that applying company-wide objectives encourages decision making that is in the best long-term interests of our company and our stakeholders as a whole. The multi-year vesting of our equity awards for executive compensation discourage excessive risk-taking and properly accounts for the time horizon of risk. Accordingly, the Compensation Committee concluded that our compensation policies and practices for all employees, including our Named Executive Officers, do not create policies that are reasonably likely to have a material adverse effect on our company.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the foregoing Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussion, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

Compensation Committee Members:

Peter R. Kagan

W. Howard Keenan, Jr.

Christopher R. Manning

Summary Compensation Table

The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal years ended December 31, 2012, 2011 and 2010.

Summary Compensation Table for the Years Ended December 31, 2012, 2011 and 2010

Name and		Salary		Bonus(1)		Total
Principal Position	Year	($)		($)		($)
Paul M. Rady	2012	$	516,156	$	1,000,000	$	1,516,156
(Chairman of the Board of Directors and Chief Executive Officer)	2011	$	475,000	$	800,000	$	1,275,000
	2010	$	450,000	$	1,319,267	$	1,769,267
Glen C. Warren, Jr.	2012	$	426,156	$	825,000	$	1,251,156
(Director, President and Chief Financial Officer and Secretary)	2011	$	395,000	$	625,000	$	1,020,000
	2010	$	375,000	$	912,845	$	1,287,845
Kevin J. Kilstrom	2012	$	311,156	$	400,000	$	711,156
(Vice President - Production)	2011	$	290,000	$	300,000	$	590,000
	2010	$	280,000	$	460,000	$	740,000
Alvyn A. Schopp	2012	$	311,156	$	400,000	$	711,156
(Vice President - Accounting and Administration)	2011	$	290,000	$	300,000	$	590,000
	2010	$	275,000	$	525,000	$	800,000
Ward D. McNeilly(2)	2012	$	281,156	$	350,000	$	631,156
(Vice President—Reserves, Planning and Midstream)

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(1)Bonus compensation for fiscal 2011 and fiscal 2012 represents the aggregate amount of the annual discretionary cash bonuses paid to each Named Executive Officer.  Bonus compensation for 2010 includes the following transaction bonus awards paid to our Named Executive Officers in connection with our disposition of Antero Resources Midstream Corporation: Mr. Rady, $919,267; Mr. Warren, $612,845; Mr. Kilstrom, $300,000; and Mr. Schopp, $350,000.

(2)Mr. McNeilly was appointed as Vice President—Reserves, Planning and Midstream in October 2010.  However, he was not a named executive officer in fiscal 2010 or fiscal 2011.

Grants of Plan-Based Awards for Fiscal Year 2012

There were no plan-based awards granted to our Named Executive Officers during the fiscal year ended December 31, 2012.

Narrative Disclosure to Summary Compensation Table

The following is a discussion of material factors necessary to an understanding of the information disclosed in the Summary Compensation Table.

Salary and Cash Incentive Awards in Proportion to Total Compensation

We paid 100% of each Named Executive Officer’s total compensation for fiscal 2012 in the form of base salary and annual cash incentive awards.

Outstanding Equity Awards at 2012 Fiscal Year-End

The following table provides information concerning equity awards that have not vested for our Named Executive Officers as of December 31, 2012.

Outstanding Equity Awards as of December 31, 2012

Name	Number of Shares or of Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (4)
	(#)	($)		(#)	($)
Ward D. McNeilly
Restricted Award Units (1)(2)	—	$	—	25,000	$	—
Restricted Award Units (1)(2)	—	$	—	25,000	$	—
Restricted Award Units (1)(3)	—	$	—	25,000	$	—
Restricted Award Units (1)(3)	—	$	—	50,000	$	—

(1) Represents the number of Class A-2, B-2, B-4 and B-7 unit in Holdings granted pursuant to the Holdings LLC Agreement. For more information concerning these awards, see the discussion above under “—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Equity-Based Incentive Awards.” As described below under “—Payments Upon Termination or Change in Control,” the restricted unit awards may terminate or be subject to accelerated vesting upon the officer’s termination of employment or the occurrence of certain corporate events. Please see footnotes 2 and 3 below for a description of the vesting schedules for the awards that remain outstanding as of December 31, 2012.

(2) Represents non-vested restricted unit awards that were granted on December 7, 2010 with a vesting commencement date of October 15, 2010. The awards vest 25% per year beginning on the first anniversary of the vesting commencement date.

(3) Represents non-vested restricted unit awards that were granted on September 13, 2011 with a vesting commencement date of December 7, 2010. The awards vest 25% per year beginning on the first anniversary of the vesting commencement date.

(4) The fair market value per unit of each of the units in Holdings subject to restricted unit awards was $0.00 at the time of issuance of the awards. Therefore, there is no market value associated with the unvested portion of the awards.

Option Exercises and Stock Vested in Fiscal Year 2012

There were no Option Exercises or Stock Vesting by any of our Named Executive Officers as of December 31, 2012.

Pension Benefits

We do not provide pension benefits to our employees.

Nonqualified Deferred Compensation

We do not provide nonqualified deferred compensation benefits to our employees.

Payments Upon Termination or Change in Control

Holdings Units

As described above, we do not maintain individual employment agreements, severance agreements or change in control agreements with our Named Executive Officers; however, the unvested units in Holdings awarded to Mr. McNeilly could be affected by the termination of his employment or the occurrence of certain corporate events. The impact of such a termination or corporate event upon the units is governed by the terms of both the individual award agreements issued to him in connection with the grant of his unit awards, as well as the Holdings LLC Agreement.

The Holdings LLC Agreement provides that upon termination of a Named Executive Officer’s employment with us by reason of death or “disability” (as defined below) or the occurrence of an “exit event” (as defined below) while the Named Executive Officer is employed by us, any unvested portion of the Holdings units granted to the Named Executive Officer will become vested; our termination of the Named Executive Officer’s employment with or without “cause,” as well as the officer’s voluntary termination of employment, generally results in the forfeiture of all unvested Holdings units. In addition, a termination for “cause” results in a forfeiture of all vested units. Any unvested portion of the Holdings units granted to a Named Executive Officer may also become immediately vested upon a “qualified IPO” (as defined below) or under such other circumstances and at such times as the Board of Directors of Holdings determines to be appropriate in its discretion.  The Holdings LLC Agreement also provides that upon the

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voluntary resignation of a Named Executive Officer or the occurrence of an exit event, any portion of the Holdings units granted to the officer that have vested as of the time of the applicable event are subject to repurchase, at Holdings’ option, at a purchase price equal to the “fair market value” of such units, as determined by the unanimous resolution of the Board of Directors of Holdings. Such amount may be paid by Holdings in cash or by promissory note. Any such promissory note issued may be structured such that (i) the principal and interest is due and payable only at the end of the term of the notes, (ii) the term of the note will mature only upon the disposition of a subsidiary or a liquidation event, and (iii) the principal amount of the note may be reduced at the end of its term to the amount of distributions the Company would have made with respect to the Holdings units purchased upon a disposition or liquidation event. In addition to the acceleration of vesting described above, in the event of a qualified IPO, the Board of Directors of Holdings may, but is not required to, effect one of the following actions in its discretion: (1) require some or all of our Named Executive Officers to surrender some or all of their vested units in Holdings in exchange for an amount of cash or stock per unit equal to the fair market value of such units; (2) make appropriate adjustments to such units; or (3) require the forfeiture of any unvested Holdings units.

At the time of the repurchase of any unit awards in Holdings that occurs at the termination of the employee’s employment relationship with us or any of our subsidiaries, any amounts received as a transaction bonus award that have not already been offset against previous unit distributions will be offset against the purchase price to be paid by Holdings for the repurchase of such units.

Under the Holdings LLC Agreement, a Named Executive Officer will be considered to have incurred a “disability” if the officer becomes incapacitated by accident, sickness or other circumstance that renders the officer mentally or physically incapable of performing the officer’s duties with us on a full time basis for a period of at least 120 days during any 12 month period. A termination for “cause” will occur following an employee’s (1) gross negligence or willful misconduct, (2) conviction of a felony or a crime involving theft, fraud or moral turpitude, (3) refusal to perform material duties or responsibilities, (4) willful and material breach of a corporate policy or code of conduct or (5) willful engagement in conduct that damages the integrity, reputation or financial success of Antero or any of its affiliates. Further, an “exit event” generally includes the sale of our company, in one transaction or a series of related transactions, whether structured as (a) a sale or other transfer of all or substantially all of our units (including by way of merger, consolidation, share exchange, or similar transaction), (b) a sale or other transfer of all or substantially all of our assets promptly followed by a dissolution and liquidation of our company or (c) a combination of the transactions described in clauses (a) and (b).  The Holdings LLC Agreement defines a “qualified IPO” as the offering and sale of equity interests or securities in Antero or one of its subsidiaries in a firm commitment underwritten public offering registered under the Securities Act of 1933, as amended, that results in (i) aggregate cash proceeds of not less than $50,000,000 (without deducting underwriting discounts, expenses, and commissions) and (ii) the listing of such interests or securities on the New York Stock Exchange, the NYSE Euronext or the Nasdaq Stock Market.

Potential Payments Upon Termination or Change in Control Table for Fiscal 2012

Because the right to repurchase vested Holdings units is optional rather than mandatory, we would not have had any financial obligation to provide any benefits to any of our Named Executive Officers upon the occurrence of an exit event or a qualified IPO as of December 31, 2012.

Compensation of Directors

The employee and non-employee members of the Board do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending meetings of the Board.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Beneficial Ownership

The following table sets forth the number of voting units in Antero Resources LLC beneficially owned by (1) all persons who, to the knowledge of our management team, beneficially own more than 5% of the outstanding voting units of Antero Resources LLC, (2) each of our current directors, (3) each of our Named Executive Officers and (4) all of our current directors and officers as a group. Except as otherwise noted, information is presented as of March 14, 2013 and the mailing address of each person or entity named in the table is 1625 17th Street, Denver, Colorado, 80202.

Name and Address of Beneficial Owner	Total Number of Voting Units	Percent of Total Voting Units Outstanding(1)
Warburg Pincus(2)
450 Lexington Avenue
New York, NY 10017	56,557,133	38.4	%
Yorktown Energy Partners(3)
410 Park Avenue, 19th Floor
New York, NY 10022	15,942,448	10.8	%
Trilantic Capital Partners(4)
399 Park Avenue
New York, NY 10022	12,471,533	8.5	%
Peter R. Kagan(5)	56,557,133	38.4	%
W. Howard Keenan, Jr.(6)	15,942,448	10.8	%
Christopher R. Manning(7)	12,471,533	8.5	%
Paul M. Rady(8)	21,125,461	14.3	%
Glen C. Warren, Jr.(9)	14,083,641	9.6	%
Alvyn A. Schopp	855,574	*	%
Kevin J. Kilstrom	530,653	*	%
Directors and officers as a group (11 persons)	38,687,713	26.3	%

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*Less than one percent.

(1)Based on 147,288,521 total outstanding voting units at March 14, 2013.

(2)The Warburg Pincus members are Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership, (“WP VIII”, and together with its two affiliated partnerships Warburg Pincus Netherlands Private Equity VIII C.V. I, a company formed under the laws of the Netherlands (“WP VIII CV I”), and WP-WPVIII Investors, L.P., a Delaware limited partnership, (“WP-WPVIII Investors”), collectively, the “WP VIII Funds”), Warburg Pincus Private Equity X, L.P., a Delaware limited partnership (“WP X”), and Warburg Pincus X Partners, L.P., a Delaware limited partnership (“WP X Partners,” and together with WP X, “WP X Funds”), and Warburg Pincus Private Equity X O&G, L.P., a Delaware limited partnership (“WP X O&G”), through their beneficial interests in WP Antero LLC, a Delaware limited liability company, an indirect subsidiary of WP X, WP X O&G, WP-WPVIII Investors and a direct subsidiary of WP X Partners, WP VIII and WP VIII CV I.  Warburg Pincus X, L.P., a Delaware limited partnership (“WP X GP”), is the general partner of WP X Funds and WP X O&G.  Warburg Pincus X LLC, a Delaware limited liability company (“WP X LLC”), is the general partner of WP X GP.  WP-WPVIII Investors LLC, a Delaware limited liability company (“WP-WPVIII LLC”), is the general partner of WP-WPVIII Investors. Warburg Pincus Partners LLC, a New York limited liability company (“WP Partners”), is the sole member of WP X LLC and WP-WPVIII Investors LLC and the general partner of WP VIII and WP VIII CV I.  Warburg Pincus & Co., a New York general partnership (“WP”), is the managing member of WP Partners.  Warburg Pincus LLC, a New York limited liability company (“WP LLC”), is the manager of the WP VIII Funds, WP X Funds, and WP X O&G.  Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members and Co-Presidents of WP LLC and may be deemed to control the Warburg Pincus entities.   Messrs. Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities.

(3)The holdings of Yorktown Energy Partners are collectively held by Yorktown Energy Partners V, L.P., Yorktown Energy Partners, VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P.

(4)The Trilantic Capital Partners (“TCP”) members are TCP Antero I-1 Holdco, LLC; TCP Antero I-2 Holdco, LLC; and TCP Antero I-4 Holdco, LLC.

(5)Peter R. Kagan, one of our directors, is a Partner of WP and a Member and Managing Director of WP LLC.  All units indicated as owned by Mr. Kagan are included because of his affiliation with the Warburg Pincus entities.  Mr. Kagan disclaims beneficial ownership of all units held by the Warburg Pincus entities.  For additional information, see footnote 2 above.

(6)W. Howard Keenan, Jr., one of our directors, is a member and a manager of the general partner of and a limited partner of each of Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P. and holds all securities received as director compensation for the benefit of those entities. Mr. Keenan disclaims beneficial ownership of all such securities as well as those held by Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P. and Yorktown Energy Partners VIII, L.P. except to the extent of his pecuniary interest therein. Mr. Keenan was elected to our Board of Directors as a Yorktown Energy Partners designee.  For additional information, see footnote 3 above.

(7)Christopher R. Manning, one of our directors, is partner of TCP. Mr. Manning was elected to our Board of Directors as a TCP designee.  All units indicated as owned by Mr. Manning are included because of his affiliation with TCP.  Mr. Manning disclaims beneficial ownership of all units held by the TCP entities.  For additional information, see footnote 4 above.

(8)Mr. Rady, our Chief Executive Officer and Chairman of the Board, is the managing member of Salisbury Investment Holdings, LLC and Mockingbird Investments, LLC and the holdings of Mr. Rady reflected above include both the direct personal holdings of Mr. Rady,  the holdings of Salisbury Investment Holdings, LLC, and the holdings of Mockingbird Investments, LLC.  Mr. Rady has sole voting and investment power over the units held by Salisbury Investment Holdings, LLC and Mockingbird Investments LLC.

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(9)Mr. Warren, our President, Chief Financial Officer and Secretary and one of our directors, is the managing member of Canton Investment Holdings, LLC and the holdings of Mr. Warren reflected above include both the direct personal holdings of Mr. Warren and the holdings of Canton Investment Holdings, LLC.  Mr. Warren has sole voting and investment power over the units held by Canton Investment Holdings, LLC.

Item 13.Certain Relationships and Related Transactions and Director Independence

Certain Relationships and Related Party Transactions

To date, our equity investors, including our Chief Executive Officer and our President, Chief Financial Officer and Secretary, have invested approximately $1.4 billion in us. For a description of our ownership structure and the ownership of the equity interests in Antero Resources by its principal equity holders and by our directors and executive officers, see “Items 1 and 2. Business and Properties—Corporate Sponsorship” and “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”  We do not currently have any formal policy with respect to the review and approval of related party transactions.

Antero Resources LLC Limited Liability Company Agreement

Antero Resources LLC was formed in connection with our November 2009 corporate reorganization. The limited liability company agreement of Antero provides for a number of different classes of units, which are owned by Antero’s equity investors and employees. Under Antero’s limited liability company agreement, if Antero proposes to issue certain additional equity securities prior to any initial public offering of its equity securities, certain of the existing holders of Antero’s units who are “accredited investors” under the Securities Act will have the right to purchase a pro rata amount of such securities. Certain of the units are subject to rights of first refusal held by Antero and the other members. In addition, if, after complying with the applicable rights of first refusal, any member seeks to sell any units, the terms of such sale must include, from the third party buyer, an offer to purchase, on the same terms, a proportional number of units of the same class of units to be sold by such selling member from each member that holds units of the class that the selling member is proposing to sell. Furthermore, if holders of at least 69% of certain classes of units and the director designated by Warburg Pincus approve a sale of Antero, then all members will be required both to approve the sale and to agree to sell all of their units on the terms and conditions of such approved sale.

None of Antero’s outstanding units are entitled to current cash distributions or are convertible into indebtedness, and Antero has no obligation to repurchase these units at the election of the unitholders. Although Antero is required to make quarterly distributions to cover any income taxes allocated to each unitholder, the unitholders have no other rights to cash distributions (except in the case of certain liquidation events).  As a result of the gain we realized on the sale of our midstream assets in 2010, we made a distribution to unitholders on February 14, 2011 of $28.9 million to cover income taxes allocated to the unitholders resulting from the gain.  We do not anticipate making any additional tax distributions in the foreseeable future. Pursuant to the terms of Antero’s limited liability company agreement, upon certain liquidation events, units held by our private equity sponsors and institutional investors are entitled to receive, prior to any amounts received by other unitholders, an amount equal to the initial purchase price of such units plus a special distribution with respect to such units and will continue to participate on a pro rata basis with other unitholders in any excess funds available in liquidation.

The board of directors of Antero currently consists of five members who have been designated in accordance with Antero’s limited liability company agreement. Each of Warburg Pincus, Yorktown Energy Partners and Trilantic Capital Partners currently has the right to designate one director to the board of directors of Antero. The remaining two members of Antero’s board of directors are our Chief Executive Officer and our Chief Financial Officer. Warburg Pincus currently has the right to designate one additional member of Antero’s board of directors after consultation with the management directors and the other investors in Antero.

Antero Resources Employee Holdings

Concurrent with the closing of the November 2009 corporate reorganization, Antero Resources LLC issued profits interests to Antero Resources Employee Holdings LLC, a newly formed Delaware limited liability company, owned solely by certain of our officers and employees. These profits interests only participate in distributions upon liquidation events meeting certain requisite financial return thresholds. In turn, Antero Resources Employee Holdings LLC issued similar profits interests to certain of our officers and employees.

Director Independence

Our board of directors consists of five members, three of whom are outside directors.  The three outside directors are representatives of our three primary equity investors and have been designated as directors in accordance with Antero Resources LLC’s limited liability company agreement.  Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards.  Accordingly, our board of directors has not made any determination as to whether the three outside

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directors satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

PART IV

Item 14.Principal Accountant Fees and Services

Policy for Approval of Audit, Audit-Related and Tax Services

The Audit Committee annually reviews and pre-approves certain categories of audit, audit-related and tax services to be performed by our independent auditor, subject to a specified range of fees. The Audit Committee may also pre-approve specific services. Certain non-audit services as specified by the SEC may not be performed by our independent auditor.  The services described below and the related fees were pre-approved by the Audit Committee in 2011 and 2012 in accordance with the pre-approval policies and procedures established by the Audit Committee.

Fees

KPMG served as our independent registered public accounting firm during 2011 and 2012. The following table sets forth the aggregate fees and costs paid to KPMG during the last two fiscal years for professional services rendered to Antero:

	Years Ended December 31,
	2011		2012
Audit	$	589,000	$	531,000
Audit-related fees	$	55,000	$	139,000
Tax fees	$	236,000	$	159,000
All other fees	$	178,000	$	—

Tax fees were incurred in connection with the preparation of our federal and state income tax returns.  Audit-related fees are fees for the issuance of comfort letters on offering memorandums prepared in connection with the issuance of senior notes.  All other fees in 2011 are for services performed in connection with due diligence related to an acquisition completed in 2010.

Item 15.Exhibits and Financial Statement Schedules

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules

The consolidated financial statements are listed on the Index to Financial Statements to this report beginning on page F-1.

(a)(3) Exhibits.

Exhibit Number	Description of Exhibits
2.1	Purchase and Sale Agreement, dated June 1, 2012, between Antero Resources Corporation and Vanguard Permian, LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on July 5, 2012)
2.2	Purchase and Sale Agreement by and among Antero Resources Piceance LLC, Antero Resources Pipeline LLC and Ursa Resources Group II LLC, dated as of November 1, 2012 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 6, 2012).
3.1	Certificate of Incorporation of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.2	Bylaws of Antero Resources Finance Corporation (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.3	Certificate of Formation of Antero Resources LLC (incorporated by reference to Exhibit 3.3 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
3.4	Amended and Restated Limited Liability Company Agreement of Antero Resources LLC dated as of December 1, 2010 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 3, 2010).
4.1	Indenture dated as of November 17, 2009 among Antero Resources Finance Corporation, the several guarantors named therein, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).

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4.2	Indenture dated as of August 1, 2011 by and among Antero Resources Finance Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on August 1, 2011).
4.3	Indenture dated as of November 19, 2012 by and among Antero Resources Finance Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 20, 2012).
4.4	Registration Rights Agreement dated as of November 19, 2012 by and among Antero Resources LLC and the other parties named therein and Wells Fargo Securities as representative for 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 November 20, 2012).
4.5	Form of 6.0% Senior Note due 2020 (included in Exhibit 4.1) (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 20, 2012).
4.6	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	Fourth Amended And Restated Credit Agreement dated as of November 4, 2010 among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, Bank of Scotland Plc, Union Bank, N.A., Credit Agricole Corporate and Investment Bank, BNP Paribas and Deutsche Bank Trust Company Americas, as Co-Documentation Agents and J.P. Morgan Securities LLC and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 11, 2010).
10.2	First Amendment to the Fourth Amended And Restated Credit Agreement, dated as of May 12, 2011, among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Form 10-Q (Commission File No. 333-164876) filed on May 16, 2011).
10.3	Second Amendment to Fourth Amended And Restated Credit Agreement dated as of July 8, 2011 among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on July 11, 2011).
10.4	Third Amendment to Fourth Amended And Restated Credit Agreement dated as of October 26, 2011 among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on October 28, 2011).
10.5	Fourth Amendment to Fourth Amended And Restated Credit Agreement dated as of May 4, 2012 among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party thereto and JP Morgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (Commission File No. 333-164876) filed on May 7, 2012).
10.6	Fifth Amendment to Fourth Amended and Restated Credit Agreement dated as of October 25, 2012 among Antero

64

	Resources Arkoma LLC, Antero Resources Piceance LLC, Antero Resources Pipeline LLC and Antero Resources Appalachian Corporation, as Borrowers, certain subsidiaries of Borrowers, as Guarantors, the Lenders party hereto, and JP Morgan Chase Bank, N.A. as Administrative Agent (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on October 26, 2012).
10.7	Purchase Agreement dated as of November 14, 2012 by and among Antero Resources Finance Corporation, the guarantors party thereto and Wells Fargo Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on November 20, 2012).
10.8	Limited Liability Company Agreement of Antero Resources Employee Holdings LLC, dated as of November 3, 2009 (incorporated by reference to Exhibit 10.9 to Registration Statement on Form S-4 (Commission File No. 333-164876) filed on February 12, 2010).
10.9	Purchase Agreement dated as of July 27, 2011 by and among Antero Resources Finance Corporation, the guarantors party thereto and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on August 1, 2011).
10.10	Letter Agreement dated June 29, 2012 by and among Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation and JPMorgan Chase Bank N.A., as administrative agent for the lenders, to reduce the borrowing base and lender commitments under the Fourth Amended and Restated Credit Agreement dated as of November 4, 2010 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on July 5, 2012).
10.11	Letter Agreement dated November 19, 2012 by and among Antero Resources Arkoma LLC, Antero Resources Piceance LLC, Antero Resources Pipeline LLC, and Antero Resources Appalachian Corporation and JPMorgan Chase Bank N.A., as administrative agent for the lenders, to reduce the borrowing base and lender commitments under the Fourth Amended and Restated Credit Agreement dated as of November 4, 2010 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 10, 2012).
10.12	Letter Agreement dated December 7, 2012 by and among Antero Resources Arkoma LLC, Antero Resources Piceance LLC, Antero Resources Pipeline LLC, and Antero Resources Appalachian Corporation and JPMorgan Chase Bank N.A., as administrative agent for the lenders, to reduce the borrowing base and lender commitments under the Fourth Amended and Restated Credit Agreement dated as of November 4, 2010 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (Commission File No. 333-164876) filed on December 10, 2012).
10.13	Purchase Agreement, dated as of January 30, 2013, by and among Antero Resources Finance Corporation, the guarantors party thereto and J.P. Morgan Securities LLC as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (Commission File No. 333-164876) filed on February 4, 2013).
10.14	Letter Agreement dated February 4, 2013 by and among Antero Resources Arkoma LLC, Antero Resources Piceance LLC, Antero Resources Pipeline LLC, and Antero Resources Appalachian Corporation and JPMorgan Chase Bank, N.A., as administrative agent for the lenders, to reduce the borrowing base and lender commitments under the Fourth Amended and Restated Credit Agreement dated as of November 4, 2010 (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K (Commission File No. 333-164876) filed on February 4, 2013).
12.1*	Computation of Ratio of Earnings to Fixed Charges.

65

21.1*	Subsidiaries of Antero Resources LLC.
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).
99.1*	Summary Report of DeGolyer and MacNaughton relating to Marcellus and Upper Devonian resources in the Appalachian Basin.
99.2*	Summary Report of DeGolyer and MacNaughton relating to Utica Shale resources in the Appalachian Basin.
101*	The following financial information from this Form 10-K of Antero Resources LLC for the year ended December 31, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to the Consolidated Financial Statements, tagged as blocks of text.

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

66

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
By:	/s/ Glen C. Warren, Jr.
	Glen C. Warren, Jr.
	President, Chief Financial Officer and Secretary
Date:	March 15, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.

/s/ Paul M. Rady	Chairman of the Board, Director and Chief Executive Officer (principal executive officer)	March 15, 2013
Paul M. Rady
/s/ Glen C. Warren, Jr.	Director, President, Chief Financial Officer and Secretary (principal financial officer)	March 15, 2013
Glen C. Warren, Jr.
/s/ Alvyn A. Schopp	Vice President—Accounting & Administration and Treasurer (principal accounting officer)	March 15, 2013
Alvyn A. Schopp
/s/ Peter R. Kagan	Director	March 15, 2013
Peter R. Kagan
/s/ W. Howard Keenan, Jr.	Director	March 15, 2013
W. Howard Keenan, Jr.
/s/ Christopher R. Manning	Director	March 15, 2013
Christopher R. Manning

67

ANTERO RESOURCES LLC AND SUBSIDIARIES

Table of Contents

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2011 and 2012	F-2
Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2010, 2011, and 2012	F-3
Consolidated Statements of Members’ Equity for the years ended December 31, 2010, 2011, and 2012	F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2011, and 2012	F-5
Notes to Consolidated Financial Statements	F-6

Report of Independent Registered Public Accounting Firm

The Board of Directors and Members

Antero Resources LLC and Subsidiaries:

We have audited the accompanying consolidated balance sheets of Antero Resources LLC and subsidiaries as of December 31, 2011 and 2012, and the related consolidated statements of operations and comprehensive income (loss), members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Antero Resources LLC and subsidiaries as of December 31, 2011 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Denver, Colorado

March 15, 2013

F-1

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 2011 and 2012

(In thousands)

	2011			2012
Assets
Current assets:
Cash and cash equivalents	$	3,343		18,989
Accounts receivable — trade, net of allowance for doubtful accounts of $182 and $174 in 2011 and 2012, respectively	25,117			21,296
Notes receivable — short-term portion	7,000			4,555
Accrued revenue	35,986			46,669
Derivative instruments	248,550			160,579
Other	13,646			22,518
Total current assets	333,642			274,606
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties	834,255			1,243,237
Producing properties	2,497,306			1,689,132
Gathering systems and facilities	142,241			168,930
Other property and equipment	8,314			9,517
	3,482,116			3,110,816
Less accumulated depletion, depreciation, and amortization	(601,702		)	(173,343	)
Property and equipment, net	2,880,414			2,937,473
Derivative instruments	541,423			371,436
Notes receivable — long-term portion	5,111			2,667
Other assets, net	28,210			32,611
Total assets	$	3,788,800		3,618,793
Liabilities and Equity
Current liabilities:
Accounts payable	$	107,027		181,478
Accrued liabilities	37,955			61,161
Revenue distributions payable	34,768			46,037
Current portion of long-term debt	—			25,000
Deferred income tax liability	75,308			62,620
Total current liabilities	255,058			376,296
Long-term liabilities:
Long-term debt	1,317,330			1,444,058
Deferred income tax liability	245,327			91,692
Other long-term liabilities	12,279			33,010
Total liabilities	1,829,994			1,945,056
Equity:
Members’ equity	1,460,947			1,460,947
Accumulated earnings	497,859			212,790
Total equity	1,958,806			1,673,737
Total liabilities and equity	$	3,788,800		3,618,793

See accompanying notes to consolidated financial statements.

F-2

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income (Loss)

Years ended December 31, 2010, 2011 and 2012

(In thousands)

	2010			2011		2012
Revenue:
Natural gas sales	$	47,392		195,116		259,743
Natural gas liquids sales	—			—		3,719
Oil sales	39			173		1,520
Realized and unrealized gains on commodity derivative instruments (including unrealized gains of $62,536, $446,120 and $1,055 in 2010, 2011, and 2012, respectively)	77,599			496,064		179,546
Gain on sale of gathering system	—			—		291,190
Total revenue	125,030			691,353		735,718
Operating expenses:
Lease operating expenses	1,158			4,608		6,243
Gathering, compression, and transportation	9,237			37,315		91,094
Production taxes	2,885			11,915		20,210
Exploration expenses	2,350			4,034		14,675
Impairment of unproved properties	6,076			4,664		12,070
Depletion, depreciation, and amortization	18,522			55,716		102,026
Accretion of asset retirement obligations	11			76		101
Expenses related to business acquisition	2,544			—		—
General and administrative	21,952			33,342		45,284
Loss on sale of assets	—			8,700		—
Total operating expenses	64,735			160,370		291,703
Operating income	60,295			530,983		444,015
Other expense:
Interest expense	(56,463		)	(74,404	)	(97,510	)
Realized and unrealized losses on interest derivative instruments, net (including unrealized gains of $6,875 and $4,212 in 2010 and 2011, respectively)	(2,677		)	(94	)	—
Total other expense	(59,140		)	(74,498	)	(97,510	)
Income from continuing operations before income taxes and discontinued operations	1,155			456,485		346,505
Provision for income taxes	(939		)	(185,297	)	(121,229	)
Income from continuing operations	216			271,188		225,276
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations, net of income tax (expense) benefit of $(29,070), $(45,155), and $272,553 in 2010, 2011, and 2012, respectively	228,412			121,490		(510,345	)
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners	$	228,628		392,678		(285,069	)

See accompanying notes to consolidated financial statements.

F-3

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Equity

Years ended December 31, 2010, 2011, and 2012

(In thousands)

	Members’			Accumulated		Total Antero		Noncontrolling		Total
	equity			deficit		equity		interest		equity
Balances, December 31, 2009	$	1,392,833		(123,447	)	1,269,386		29,721		1,299,107
Issuance of member units in business acquisition	97,000			—		97,000		—		97,000
Equity issuance costs	(27		)	—		(27	)	—		(27	)
Sale of midstream subsidiary	—			—		—		(31,285	)	(31,285	)
Net income and comprehensive income	—			228,628		228,628		1,564		230,192
Balances, December 31, 2010	1,489,806			105,181		1,594,987		—		1,594,987
Distribution to members	(28,859		)	—		(28,859	)	—		(28,859	)
Net income and comprehensive income	—			392,678		392,678		—		392,678
Balances, December 31, 2011	1,460,947			497,859		1,958,806		—		1,958,806
Net income (loss) and comprehensive income (loss)	—			(285,069	)	(285,069	)	—		(285,069	)
Balances, December 31, 2012	$	1,460,947		212,790		1,673,737		—		1,673,737

See accompanying notes to consolidated financial statements.

F-4

ANTERO RESOURCES LLC AND SUBSIDIARIES

Consolidated Statements of Cash Flows

Years ended December 31, 2010, 2011, and 2012

(In thousands)

	2010			2011		2012
Cash flows from operating activities:
Net income (loss)	$	228,628		392,678		(285,069	)
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and depletion	18,533			55,792		102,127
Impairment of unproved properties	6,076			4,664		12,070
Unrealized gains on derivative instruments, net	(69,411		)	(450,332	)	(1,055	)
Deferred income tax expense	939			185,297		106,229
(Gain) loss on sale of assets	—			8,700		(291,190	)
Loss (gain) on sale of discontinued operations	(147,559		)	—		795,945
Depletion, depreciation, amortization, impairment of unproved properties, and dry hole expense — discontinued operations	164,993			126,041		90,096
Unrealized (gains) losses on derivative instruments, net — discontinued operations	(108,035		)	(113,476	)	45,808
Deferred income tax expense (benefit) — discontinued operations	29,070			45,155		(272,553	)
Other	5,255			3,479		4,960
Changes in assets and liabilities:
Accounts receivable	(2,306		)	3,854		5,511
Accrued revenue	(7,408		)	(11,118	)	(10,683	)
Other current assets	261			(4,528	)	(8,882	)
Accounts payable	9,779			(1,875	)	(2,117	)
Accrued liabilities	(2,771		)	17,124		14,790
Revenue distributions payable	1,747			4,852		11,268
Other	—			—		15,000
Net cash provided by operating activities	127,791			266,307		332,255
Cash flows from investing activities:
Additions to proved properties	—			(105,405	)	(10,254	)
Additions to unproved properties	(41,277		)	(195,131	)	(687,403	)
Drilling costs	(299,926		)	(527,710	)	(839,151	)
Additions to gathering systems and facilities	(47,124		)	(72,837	)	(142,294	)
Additions to other property and equipment	(2,647		)	(2,339	)	(3,447	)
(Increase) decrease in notes receivable	(2,000		)	(10,111	)	4,889
Increase in other assets	(556		)	(3,095	)	(3,707	)
Proceeds from asset sales	258,918			15,379		1,217,876
Net assets of business acquired, net of cash of $170	(96,060		)	—		—
Net cash used in investing activities	(230,672		)	(901,249	)	(463,491	)
Cash flows from financing activities:
Issuance of senior notes	156,000			400,000		300,000
Borrowings (repayments) on bank credit facility, net	(42,080		)	265,000		(148,000	)
Payments of deferred financing costs	(10,459		)	(6,691	)	(5,926	)
Distribution to members	—			(28,859	)	—
Other	(2,261		)	(153	)	808
Net cash provided by financing activities	101,200			629,297		146,882
Net increase (decrease) in cash and cash equivalents	(1,681		)	(5,645	)	15,646
Cash and cash equivalents, beginning of period	10,669			8,988		3,343
Cash and cash equivalents, end of period	$	8,988		3,343		18,989
Supplemental disclosure of cash flow information:
Cash paid during the period for interest	$	52,326		59,107		90,122
Supplemental disclosure of noncash investing activities:
Changes in accounts payable for additions to properties, gathering systems and facilities	$	32,028		26,465		72,881

See accompanying notes to consolidated financial statements.

F-5

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(1)Organization

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 Oklahoma Arkoma Basin properties and our Colorado 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 December 31, 2012 include the accounts of Antero Resources LLC, and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Appalachian Corporation and its wholly owned subsidiaries, Antero Resources Arkoma LLC (Antero Arkoma), Antero Resources Piceance LLC (Antero Piceance), Antero Resources Pipeline LLC (Antero Pipeline), Antero Resources Bluestone LLC, and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities).  Subsequent to December 31, 2012 the Antero Arkoma, Antero Piceance, and Antero Pipeline LLCs were merged into Antero Resources Appalachian Corporation.

(2)Summary of Significant Accounting Policies

(a)Basis of Presentation

The accompanying consolidated financial statements include the accounts of Antero Resources LLC and its subsidiaries. All significant intercompany accounts and transactions have been eliminated.

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 other than the event described in Note 7 (d) requiring disclosure were identified.

(b)Use of Estimates

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

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

(Continued)

F-6

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(c)Risks and Uncertainties

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

(d)Cash and Cash Equivalents

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

(e)Oil and Gas Properties

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, costs of productive wells, development dry holes, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The Company reviews exploration costs related to wells-in-progress at the end of each quarter and makes a determination based on known results of drilling at that time whether the costs should continue to be capitalized pending further well testing and results or charged to expense. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Other unproved properties are assessed for impairment on an aggregate basis. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on or otherwise attributed to the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognizing any gain or loss until the cost has been recovered. Impairment of unproved properties (including discontinued operations) for leases which have expired or are expected to expire was $35.9 million, $11.1 million, and $13.0 million for the years ended December 31, 2010, 2011, and 2012, respectively.

The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that the carrying value of the properties may not be recoverable. When determining whether impairment has occurred, the Company estimates the expected future cash flows of its oil and gas properties and compares such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company reduces the carrying amount of the

(Continued)

F-7

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

properties to their estimated fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, cash flow from commodity hedges, future production estimates, anticipated capital expenditures, and a commensurate discount rate. There were no impairments of proved natural gas properties during the years ended December 31, 2010, 2011, and 2012.

At December 31, 2012, the Company did not have significant capitalized costs related to exploratory wells-in-progress which were pending determination of proved reserves. The Company had no significant costs which have been deferred for longer than one year pending proved reserves at December 31, 2012.

The provision for depreciation, depletion, and amortization of oil and gas properties (including discontinued operations) is calculated on a geological reservoir basis using the units-of-production method. Depreciation, depletion, and amortization expense for oil and gas properties was $124.3 million, $164.0 million, and $181.7 million for the years ended December 31, 2010, 2011, and 2012, respectively.

(f)Inventories

Inventories consist of pipe and well equipment, and are stated at the lower of cost or market. Cost is determined using the first-in, first-out (FIFO) method.

(g)Gathering Systems and Facilities

Gathering systems and compressors are depreciated using the straight-line method over their estimated useful life of 20 years. Expenditures for installation, major additions, and improvements are capitalized, and minor replacements, maintenance, and repairs are charged to expenses as incurred. For the years ended December 31, 2010, 2011, and 2012, depreciation expense  (including discontinued operations) for gathering systems and processing facilities was $8.8 million, $5.5 million, and $7.4 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.

(h)Impairment of Long-Lived Assets Other than Oil and Gas Properties

The Company evaluates its long-lived assets other than natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amount of the assets may not be recoverable. Generally, the basis for making such assessments is undiscounted future cash flow projections for the unit being assessed. If the carrying value amounts of the assets are deemed to be not recoverable, the carrying amount is reduced to the estimated fair value, which is based on discounted future cash flows or other techniques, as appropriate. No impairments for such assets have been recorded through December 31, 2012.

(i)Other Property and Equipment

Other property and equipment is depreciated using the straight-line method over estimated useful lives ranging from three to five years. For the years ended December 31, 2010, 2011, and 2012, depreciation expense for other property and equipment was $0.8 million, $1.0 million, and $1.7 million, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.

(Continued)

F-8

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(j)Deferred Financing Costs

Deferred financing costs represent loan origination fees, initial purchasers’ discounts, and other borrowing costs and are included in noncurrent other assets on the consolidated balance sheets. These costs are being amortized over the term of the related debt using the effective interest method. The Company charges interest expense for deferred financing costs remaining for debt facilities that have been retired prior to their maturity date. At December 31, 2012, the Company had $28.1 million of unamortized deferred financing costs included in other long-term assets. The amounts amortized and the write-off of previously deferred debt issuance costs were $4.1 million, $3.8 million, and $5.2 million for the years ended December 31, 2010, 2011, and 2012, respectively.

(k)Derivative Financial Instruments

In order to manage its exposure to oil and gas price volatility, the Company enters into derivative transactions from time to time, including commodity swap agreements, collar agreements, and other similar agreements relating to natural gas expected to be produced. From time to time, the Company also enters into derivative contracts to mitigate the effects of interest rate fluctuations. To the extent legal right of offset with a counterparty exists, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position.

The Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings as they occur. Changes in the fair value of commodity derivatives are classified as revenues, and changes in the fair value of interest rate derivatives are classified as other income (expense). Cash flows from the termination of commodity derivatives in conjunction with sales of oil and gas assets are included in the investing section of the statement of cash flows.

(l)Asset Retirement Obligations

The Company is obligated to dispose of certain long-lived assets upon their abandonment. The Company’s asset retirement obligations (ARO) relate primarily to its obligation to plug and abandon oil and gas wells at the end of their life. The ARO is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted, risk-free interest rate. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. The fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.

The Company delivers natural gas through its gathering assets and may become obligated by regulatory requirements to remove certain facilities or perform other remediation upon retirement of these assets. However, the Company is not able to reasonably determine the fair value of the ARO since future dismantlement and removal dates are indeterminate. The Company does not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which the Company operates. In the absence of such information, the Company is not able

(Continued)

F-9

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

to make a reasonable estimate of when future dismantlement and removal dates will occur and will continue to monitor regulatory requirements to remove its gathering assets.

(m)Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed as incurred. Liabilities are accrued when environmental assessments and/or clean up is probable, and the costs can be reasonably estimated. These liabilities are adjusted as additional information becomes available or circumstances change. As of December 31, 2011 and 2012, the Company has not accrued a material amount for any environmental liabilities nor has it been fined or cited for any environmental violations that could have a material adverse effect on future capital expenditures or operating results of the Company.

(n)Natural Gas, NGL and Oil Revenues

Sales of natural gas, NGLs, and crude oil are recognized when the products are delivered to the purchaser and title transfers to the purchaser. Payment is generally received one month months after the sale has occurred. Variances between estimated sales and actual amounts received are recorded in the month payment is received and are not material. The Company recognizes natural gas revenues based on its entitlement share of natural gas that is produced based on its working interests in the properties. The Company records a receivable (payable) to the extent it receives less (more) than its proportionate share natural gas revenues. At December 31, 2011 and 2012, the Company had no significant imbalance positions.

(o)Concentrations of Credit Risk

The Company’s revenues are derived principally from uncollateralized sales to purchasers in the oil and gas industry. The concentration of credit risk in a single industry affects the Company’s overall exposure to credit risk because purchasers may be similarly affected by changes in economic and other conditions. The Company has not experienced significant credit losses on its receivables.

The Company’s sales to major customers (purchases in excess of 10% of total sales) for the years ended December 31, 2010, 2011, and 2012 are as follows (including sales in discontinued operations):

	2010		2011		2012
Company A	23	%	28	%	23	%
Company B	13		17		13
Company C	11		12		10
All others	53		43		54
	100	%	100	%	100	%

Although a substantial portion of production is purchased by these major customers, we do not believe the loss of any one or several customers would have a material adverse effect on our business, as other customers or markets would be accessible to us.

(Continued)

F-10

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

The Company is also exposed to credit risk on its commodity derivative portfolio. Any default by the counterparties to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations. The fair value of our commodity derivative contracts of approximately $532 million at December 31, 2012 includes the following values by bank counterparty: JP Morgan — $94 million; BNP Paribas — $124 million; Credit Suisse — $150 million; Wells Fargo — $86 million; Barclays — $57 million; Deutsche Bank — $11 million; and Union Bank — $4 million. Additionally, contracts with Dominion Field Services account for $6 million of the fair value. 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 at December 31, 2012 for each of the European and American banks. We believe that all of these institutions currently are acceptable credit risks.

The Company, at times, may have cash in banks in excess of federally insured amounts.

(p)Income Taxes

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

The Company’s operating 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.

(q)Fair Value Measures

FASB ASC Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., those measured at fair value in a business combination, the initial recognition of asset retirement obligations, and impairments of proved oil and gas properties, and other long-lived assets). The fair value is the price that the Company estimates would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant

(Continued)

F-11

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Instruments which are valued using Level 2 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.

(r)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 customers located in the United States.

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

On December 21, 2012 the Company completed the sale of its Piceance Basin assets. Proceeds from the sale of $316 million represent 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 had a loss of $364 million on the sale of the Piceance Basin assets. The purchaser also assumed all of the Company’s Rocky Mountain firm transportation obligations.  Because of the sale of the Piceance Basin assets, the Company also liquidated its hedge positions related to the Piceance Basin and realized additional proceeds from these transactions 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 had a loss of $432 million on the sale of the Arkoma Basin assets. The Company’s Arkoma Basin midstream operations, which were sold on November 5, 2010, are also included in discontinued operations through the date of the sale. The Company realized a gain in 2010 of $148 million on the sale of those midstream operations.

(Continued)

F-12

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

Results of operations and the loss on the sale of 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):

	Year ended December 31
	2010			2011		2012
Sales of oil, natural gas, and natural gas liquids	$	159,031		196,705		125,396
Realized gains on commodity derivative instruments	58,650			66,654		92,166
Unrealized gains (losses) on commodity derivative instruments	108,035			113,476		(45,808	)
Gas gathering and processing revenue	20,554			—		—
Gain on sale of midstream assets	147,559			—		—
Total revenues	493,829			376,835		171,754
Lease operating expenses	24,353			26,037		19,901
Gathering, compression, and transportation	36,572			50,453		45,089
Production taxes	5,892			6,307		2,967
Exploration expenses	22,444			5,842		664
Impairment of unproved properties	29,783			6,387		962
Depletion, depreciation, and amortization	115,433			114,805		88,720
Accretion of asset retirement obligations	306			359		404
Loss on sale of assets	—			—		795,945
Total expenses	234,783			210,190		954,652
Income (loss) from discontinued operations before income taxes	259,046			166,645		(782,898	)
Income tax (expense) benefit	(29,070		)	(45,155	)	272,553
Net income (loss)	229,976			121,490		(510,345	)
Noncontrolling interest in net income of consolidated subsidiary	(1,564		)	—		—
Net income (loss) from discontinued operations attributable to Antero equity owners	$	228,412		121,490		(510,345	)

(Continued)

F-13

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(4)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 annual volumes into the gathering systems, with certain carryback and carryforward adjustments for overages or deficiencies. The Company can earn up to an additional $40 million of sale proceeds over the next three years if it meets certain volume thresholds. Crestwood is obligated to incur all future capital costs to build out gathering systems and compression facilities within the AOD to connect the Company’s wells as it executes its drilling program and has assumed the various risks and rewards of the system build-out and operations. Because the Company has not retained the substantial risks and rewards of ownership associated with the gathering rights and systems transferred to Crestwood, it has recognized a gain on the sale of the gathering system and gathering rights of approximately $291 million.

(5)Bluestone Acquisition

On December 1, 2010, the Company, through a newly formed subsidiary of Antero Appalachian, Antero Resources Bluestone LLC, acquired 100% of the interests in Bluestone Energy Partners (BEP), a general partnership which owned approximately 96 producing wells and 37,250 acres of unproved leaseholds in the Appalachian Basin.

The following table summarizes the consideration paid for the BEP partnership interests and the amounts of the assets acquired and liabilities assumed (in millions).

Consideration:
Cash	$	96.2
I-5 and B-6 units (3,814,392 each) in Antero Resources LLC	97.0
Total fair value of consideration transferred	$	193.2
Acquisition related costs (included in operating expenses in the Company’s statement of operations for the year ended December 31, 2011)	$	2.5
Fair values of identifiable assets acquired and liabilities assumed:
Current assets	$	17.2
Oil and gas properties:
Producing properties	50.7
Undeveloped leases	206.3
Other	4.3
Other long-term assets	9.3
Current liabilities	(7.0		)
Long term liabilities	(26.2		)
Deferred tax liabilities	(61.4		)
Net assets acquired	$	193.2

(Continued)

F-14

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

The fair value of property and equipment and other long-term assets was determined using Level 3 inputs. Deferred tax liabilities were calculated by applying the estimated effective tax rate to the difference between the fair value of the assets acquired and their tax basis. The Company’s I-5 and B-6 units, representing additional membership interests issued as part of the consideration, were recorded based on their estimated fair value of $97.0 million on the acquisition date, using Level 3 inputs. There was no contingent consideration given as part of the purchase price.

(6)Notes Receivable

At December 31, 2011 and 2012 the Company had notes receivable from a drilling contractor of $12.1 million and $7.2 million, respectively. The notes result from the Company’s advances to the drilling contractor to construct drilling rigs to be used by the contractor to fulfill long-term drilling contracts with the Company. The notes are noninterest bearing and are repayable over the term of the service agreements with the drilling contractor.

(Continued)

F-15

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(7)Long-term Debt

The Company’s had long-term debt as follows at December 31, 2011 and 2012 (in thousands):

	2011		2012
Bank credit facility (a)	$	365,000	217,000
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
9.00% senior note due 2013 (e)	25,000		25,000
Net unamortized premium	2,330		2,058
	1,317,330		1,469,058
Less amounts due within one year	—		25,000
	$	1,317,330	1,444,058

(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 our proved properties and commodity hedge positions and are subject to regular semiannual redeterminations. The next redetermination of the borrowing base is scheduled to occur in May 2013. After giving effect to the issuance of the 6.00% senior notes due 2020 in November 2012 and February 2013, the borrowing base was $1.22 billion and lender commitments totaled $700 million. Lender commitments can be increased to the full $1.22 billion borrowing base upon approval of the lending bank group. 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 debt covenants under the Credit Facility as of December 31, 2011 and 2012.

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

F-16

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(b)9.375% Senior Notes Due 2017

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, 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. Antero Resources LLC has no independent assets or operations. 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. Antero Resources LLC, the stand-alone parent entity, has insignificant independent assets and no operations. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from its subsidiaries, except those imposed by applicable law.

(c)7.25% Senior Notes 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

(Continued)

F-17

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

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, commencing on June 1, 2013. Antero Finance may redeem all or part 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 $25.0 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on June 1, 2013. At December 31, 2012, there were no outstanding borrowings under this facility.

(8)Asset Retirement Obligations

The following is a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2011 and 2012 (in thousands).

	2011		2012
Asset retirement obligations — beginning of year	$	5,374	6,715
Obligations incurred for wells drilled or on properties acquired	906		9,440
Obligations related to assets sold	—		(6,107	)
Accretion expense	435		504
Asset retirement obligations — end of year	$	6,715	10,552

(Continued)

F-18

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(9)Ownership Structure

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

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

None of the three classes of outstanding units are entitled to current cash distributions, except as provided in the limited liability operating agreement, nor are they convertible into indebtedness. The Company has no obligation to repurchase these units at the election of the unit holders.

Antero Resources Employee Holdings LLC, a limited liability company owned by certain officers and directors, owns Class A-2, A-4, B-2, B-3, B-4, and B-5 profit units and has issued similar units to its members. These units participate only in distributions upon liquidation events meeting requisite financial return thresholds.

In December 2010, Antero Resources LLC issued new Class I-5 and B-6 units valued in aggregate at $97 million in connection with the acquisition of Bluestone Energy Partners (see note 4).

In the event of a distribution from Antero Resources LLC, amounts available for distribution are distributed according to a formula set forth in the 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 subsidiary, 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, the Class I units had an aggregate liquidation priority, including the special allocation of 8% per annum, of $2.191 billion. Under the terms of the Antero Resources LLC limited liability company agreement, the Company is obligated to distribute cash to the members of the limited liability company each year in an amount sufficient for the members to fund income tax liabilities for partnership income allocated to them. As a result of the gain recognized by Antero Resources LLC on the sale of Antero Resources Midstream Corporation in 2010, the Company distributed approximately $28.9 million to the members to fund income tax liabilities in February 2011.

(10)Membership Interests Awards

The Company has issued membership interests in Antero Resources Employee Holdings LLC, a limited liability company owned by certain officers and employees. The membership interests participate only in

(Continued)

F-19

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

distributions from Antero Resources LLC in liquidation events, meeting requisite financial thresholds after the Class I and other classes of unitholders have recovered their investment and special allocation amounts. The membership interests have no voting rights. Compensation expense for these awards will be recognized when all performance, market, and service conditions are probable of being satisfied (in general, upon a liquidating event). Accordingly, no value was assigned to the interests when issued. A summary of the status of the net membership interests outstanding in Antero Holdings and changes during the year ended December 31, 2012 is summarized as follows:

Balance, January 1, 2012	7,957,283
Granted	806,000
Forfeited/canceled	(203,500	)
Outstanding at December 31, 2012	8,559,783

(11)Financial Instruments

The carrying values of trade receivables and trade payables at December 31, 2011 and 2012 approximated market value because of their short-term nature. The carrying value of the bank credit facility at December 31, 2011 and 2012 approximated fair value because the variable interest rates are reflective of current market conditions.

The fair value of the Company’s senior notes was approximately $1.3 billion, based on Level 2 market data inputs at December 31, 2012.

See note 12 for information regarding the fair value of derivative financial instruments.

(12)Derivative Instruments

(a)Commodity Derivatives

The Company periodically enters into natural gas derivative contracts with counterparties to hedge the price risk associated with a portion of its production. These derivatives are not held for trading purposes. To the extent that changes occur in the market prices of natural gas, the Company is exposed to market risk on these open contracts. This market risk exposure is generally offset by the change in market prices of natural gas recognized upon the ultimate sale of the natural gas produced.

For the years ended December 31, 2010, 2011, and 2012, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price the Company receives the difference from the counterparty. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

(Continued)

F-20

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

As of December 31, 2012, the Company has entered into fixed price natural gas and oil swaps in order to hedge a portion of its natural gas and oil production from January 1, 2013 through December 31, 2018 as summarized in the following table.

	MMbtu/day	Bbls/day	price
Year ending December 31, 2013:
CGTAP	122,631	—	$	5.02
Dominion South	191,702	—	4.77
NYMEX-WTI	—	300	90.30
2013 Total	314,333	300
Year ending December 31, 2014:
CGLA	10,000		$	3.87
CGTAP	200,000		5.16
Dominion South	160,000		5.15
2014 Total	370,000
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
2016 Total	502,500
Year ending December 31, 2017:
CGLA	420,000		$	4.27
Year ending December 31, 2018:
CGLA	75,000		$	4.90

(b)Interest Rate Derivatives

From time to time, the Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations. Under the swaps, the Company made payments to the swap counterparty when the variable LIBOR three-month rate fell below the fixed rate or received payments from the swap counterparty when the variable LIBOR three-month rate went above the fixed rate. The Company had no outstanding interest rate swap agreements at December 31, 2012.

(Continued)

F-21

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(c)Summary

The following is a summary of the fair values of derivative instruments not designated as hedges for accounting purposes and where such values are recorded in the consolidated balance sheets as of December 31, 2011 and 2012. None of the Company’s derivative instruments are designated as hedges for accounting purposes.

	2011			2012
	Balance			Balance
	sheet			sheet
	location	Fair value		location	Fair value
		(In thousands)			(In thousands)
Asset derivatives not designated as hedges for accounting purposes:
Commodity contracts	Current assets	$	248,550	Current assets	$	160,579
Commodity contracts	Long-term assets	541,423		Long-term assets	371,436
Total asset derivatives		$	789,973		$	532,015

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 years ended December 31, 2010, 2011, and 2012 (in thousands):

	Statement of
	operations
	location	2010			2011		2012
Realized gains on commodity contracts	Revenue	$	15,063		49,944		178,491
Unrealized gains on commodity contracts	Revenue	62,536			446,120		1,055
Realized gains on commodity contracts	Discontinued	58,650			66,654		92,166
	operations
Unrealized gains (losses) on commodity contracts	Discontinued operations	108,035			113,476		(45,808	)
Total gains on commodity contracts		244,284			676,194		225,904
Realized losses on interest rate contracts	Other expense	(9,552		)	(4,306	)	—
Unrealized gains on interest rate contracts	Other income	6,875			4,212		—
Total losses on interest rate contracts		(2,677		)	(94	)	—
Net gains on derivative contracts		$	241,607		676,100		225,904

(Continued)

F-22

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

The fair value of commodity and interest rate derivative instruments was determined using Level 2 inputs.

(13)Income Taxes

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 federal and state income taxes.

For the years ended December 31, 2010, 2011, and 2012 income tax expense from continuing operations consisted of the following (in thousands):

	2010		2011	2012
Current income tax expense	$	—	—	15,000
Deferred income tax expense	939		185,297	106,229
Total income tax expense from continuing operations	$	939	185,297	121,229

The income tax expense from continuing operations differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 35% to consolidated income for the years ended December 31, 2010, 2011, and 2012, as a result of the following (in thousands):

	2010			2011		2012
Federal income tax expense	$	404		159,770		121,276
State income tax expense, net of federal benefit	57			23,593		4,761
Change in valuation allowance	1,197			(934	)	(4,872	)
Other	(719		)	2,868		64
Total income tax expense from continuing operations	$	939		185,297		121,229

For the years ended December 31, 2010, 2011, and 2012 income tax expense (benefit) was allocated to continuing and discontinued operations as follows (in thousands):

	2010		2011	2012
Continuing operations	$	939	185,297	121,229
Discontinued operations and sale of discontinued operations	29,070		45,155	(272,553	)
Total income tax expense / (benefit)	$	30,009	230,452	(151,324	)

(Continued)

F-23

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities at December 31, 2011 and 2012 is as follows (in thousands):

	2011			2012
Deferred tax assets:
Net operating loss carryforwards	$	364,017		417,385
Capital loss carryforwards	5,292			5,367
Minimum tax credit carryforward				15,000
Other	10,490			5,006
Total deferred tax assets	379,799			442,758
Valuation allowance	(13,833		)	(47,678	)
Net deferred tax assets	365,966			395,080
Deferred tax liabilities:
Unrealized gains on derivative instruments	311,434			206,937
Depreciation differences on gathering system	5,100			—
Oil and gas properties	370,067			342,455
Total deferred tax liabilities	686,601			549,392
Net deferred tax liabilities	$	(320,635	)	(154,312	)

(Continued)

F-24

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of all of these deductible differences and has recorded a valuation allowance of approximately $14 million and $48 million at December 31, 2011 and 2012, respectively, which is primarily related to capital loss carryforwards and certain state NOL carryforwards. The amount of the deferred tax asset considered realizable could be reduced in the near term if estimates of future taxable income during the carryforward period are revised.

The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations.  The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.  The financial statements include unrecognized benefits at December 31, 2012 of $15 million that, if recognized, would result in a reduction of noncurrent income taxes payable (included in other long-term liabilities) and an increase in noncurrent deferred tax liabilities.  No impact to the Company’s 2012 effective tax rate would result.  As of December 31, 2012, no interest or penalties have been accrued on unrecognized tax benefits.  A reconciliation of beginning and ending amount of unrecognized tax benefits is as follows:

	2012
Balance at beginning of year	$	—
Additions based upon tax positions related to the current year	15,000
Balance at end of year	$	15,000

The Company’s corporate subsidiaries have U.S Federal and state net operating loss carryforwards (NOLs) as of December 31, 2012 of $1.0 billion and $1.3 billion, respectively, which expire at various dates from 2024 to 2032.  Included in other current assets are $14 million of estimated Federal tax payments made during 2012 that will be refunded to the Company when it files its 2012 tax return.

The tax years 2009 through 2012 remain open to examination by the U.S. Internal Revenue Service. The Company and subsidiaries file tax returns with various state taxing authorities; these returns remain open to examination for tax years 2008 through 2012.

(14)Commitments

The following is a schedule of future minimum payments for firm transportation agreements, drilling and compression facility obligations, and leases that have remaining lease terms in excess of one year as of December 31, 2012 (in millions).

(Continued)

F-25

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

			Gas processing,
			gathering	Drilling rigs
	Firm		and	and frac	Office and
	transportation		compression	Services	equipment
	(a)		(b)	(c)	(d)	Total
Year ending December 31:
2013	$	36	111	150	1	298
2014	93		107	98	3	301
2015	116		126	44	3	289
2016	116		131	—	3	250
2017	113		125	—	3	241
Thereafter	854		564	—	15	1,433
Total	$	1,328	1,164	292	28	2,812

(a)Firm Transportation

The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas volumes or ethane 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.

(b)Gas Processing and Compression Service Commitments

The Company has entered into various long-term gas processing agreements for certain of its production that will allow us to realize the value of our NGLs. The minimum payment obligations under the agreements are presented in the table.

The Company has various compressor service agreements with third parties that provide for payments based on volumes compressed and have minimum payment obligations which are presented in the table.

(c)Drilling Rig Service Commitments

The Company has obligations under agreements with service providers to procure drilling rigs and compression and frac services. At December 31, 2012, the Company had contracts for the services of 13 rigs. The contracts expire at various dates from January 2013 through January 2016.

(d)Office and Equipment Leases

The Company leases various office space and equipment under operating lease arrangements. Rental expense under operating leases is included in general and administrative expenses and was $0.8 million, $1.0 million, and $1.1 million for the years ended December 31, 2010, 2011, and 2012, respectively.

(Continued)

F-26

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(15)Contingencies

In March 2011, the Company received orders for compliance from the U.S. Environmental Protection Agency relating to certain of our activities in West Virginia. The orders allege that certain of 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.

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

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

(16)Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following is supplemental information regarding our consolidated oil and gas producing activities. The amounts shown include our net working and royalty interests in all of our oil and gas properties.

(a)Capitalized Costs Relating to Oil and Gas Producing Activities

	Year ended December 31
	2011			2012
	(In thousands)
Producing properties	$	2,497,306		1,689,132
Unproved properties	834,255			1,243,237
	3,331,561			2,932,369
Accumulated depreciation and depletion	(586,444		)	(158,210	)
Net capitalized costs	$	2,745,117		2,774,159

(Continued)

F-27

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(b)Costs Incurred in Certain Oil and Gas Activities

	Year ended December 31
	2010		2011	2012
	(In thousands)
Proved property acquisition costs	$	50,657	105,405	10,254
Unproved property acquisition costs	247,733		195,131	687,403
Development costs and other	299,926		527,710	839,151
Asset retirement obligation	332		906	9,440
Total costs incurred	$	598,648	829,152	1,546,248

Costs incurred in 2010 include costs allocated to proved and unproved properties of $50.7 million and $206.3 million, respectively, as a result of a business acquisition. See note 3.

(c)Results of Operations (including discontinued operations) for Oil and Gas Producing Activities

	Year ended December 31
	2010			2011		2012
	(In thousands)
Revenues	$	206,462		391,994		390,378
Operating expenses:
Production expenses	80,097			136,635		185,505
Exploration expenses	24,794			9,876		15,339
Depreciation and depletion	124,341			164,011		181,664
Impairment	35,859			11,051		13,032
Results of operations before income tax expense (benefit)	(58,629		)	70,421		(5,162	)
Income tax (expense) benefit	6,449			(26,056	)	2,008
Results of operations	$	(52,180	)	44,365		(3,154	)

(d)Oil and Gas Reserves

The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the oil and gas segment’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the year ended December 31, 2011 and 2012 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (D&M) or Ryder Scott utilizing data compiled by us. Over 99% of our estimated proved reserves as of December 31, 2010 were prepared by D&M, Ryder Scott, or Wright & Co. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.

(Continued)

F-28

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

Proved reserves are the estimated quantities of crude oil, condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average pricing for the previous 12 months.

Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital; future oil and gas prices; and cash flows from operations, future drilling costs, demand for natural gas, and other economic factors.

	Natural			Oil and
	gas		NGLS	condensate		Equivalents
	(Bcf)		(MMBbl)	(MMBbl)		(Bcfe)
Proved developed and undeveloped reserves:
December 31, 2009	1,130		—	1		1,141
Revisions	38		35	1		253
Extensions, discoveries and other additions	1,248		69	8		1,712
Production	(45	)	—	—	(a)	(47	)
Purchase of reserves	172		—	—		172
December 31, 2010	2,543		104	10		3,231

(Continued)

F-29

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

	Natural				Oil and
	gas		NGLS		condensate		Equivalents
	(Bcf)		(MMBbl)		(MMBbl)		(Bcfe)
Revisions	(223	)	(28	)	7		(352	)
Extensions, discoveries and other additions	1,644		87		—	(a)	2,162
Production	(84	)	(1	)	—	(a)	(89	)
Purchase of reserves	52		2		—		66
Sale of reserves in place	(1	)	—		—		(1	)
December 31, 2011	3,931		164		17		5,017
Revisions	198		4		—	(a)	222
Extensions, discoveries and other additions	1,242		115		3		1,951
Production	(87	)	—	(a)	—	(a)	(87	)
Sale of reserves in place	(1,590	)	(80	)	(17	)	(2,174	)
December 31, 2012	3,694		203		3		4,929

	Natural		Oil and
	gas	NGLS	condensate	Equivalents
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
Proved developed reserves:
December 31, 2010	400	9	1	457
December 31, 2011	718	19	2	844
December 31, 2012	828	36	1	1,047
Proved undeveloped reserves:
December 31, 2010	2,143	95	10	2,774
December 31, 2011	3,213	145	15	4,173
December 31, 2012	2,866	167	2	3,882

(a)Less than 1.0

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2010, 2011, and 2012 in the above table include the following:

·2010 — Of the 1,712 Bcfe of extensions and discoveries in 2010, 249 Bcfe related to the Arkoma Basin in Oklahoma, 1,130 Bcfe related to the Piceance Basin in Colorado, 301 Bcfe related to the Appalachian Basin in Pennsylvania and West Virginia, and 32 Bcfe related to other areas. The increase in extensions and discoveries is the result of increased activity in the

(Continued)

F-30

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

Appalachian Basin and the future realization of the value of our NGLs in the Piceance Basin because of a processing agreement that became effective on January 1, 2011.

·2011 — Of the 2,162 Bcfe of extensions and discoveries in 2011, 93 Bcfe related to the Arkoma Basin in Oklahoma, 61 Bcfe related to the Piceance Basin in Colorado, 1,995 Bcfe related to the Appalachian Basin in Pennsylvania and West Virginia, and 12 Bcfe related to other areas. Extensions and discoveries are primarily the result of increased development activity in the Appalachian Basin and the future realization of the value of our Appalachian NGLs as a result of the execution of a long-term processing agreement expected to occur in the third quarter of 2012 when the processing plant is completed.

·2012 — Extensions, discoveries, and other additions during 2012 of 1,951 Bcfe were added through the drillbit in the Marcellus and Utica Shales, including the addition of 709 Bcfe attributable to NGLs and oil. Downward price revisions resulted in a reduction of proved reserves of 102 Bcfe.  Performance revisions increased proved reserves by 324 Bcfe.  Sales of proved reserves of 2,174 Bcfe are the result of the sale of our Arkoma and Piceance Basin properties.

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows were computed by applying historical 12-month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available net operating loss carryforwards, and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

(Continued)

F-31

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

	Year ended December 31
	2010			2011		2012
	(In millions)
Future cash inflows	$	13,114		20,046		12,151
Future production costs	(3,088		)	(3,491	)	(1,660	)
Future development costs	(4,036		)	(5,085	)	(3,270	)
Future net cash flows before income tax	5,990			11,470		7,221
Future income tax expense	(1,438		)	(3,287	)	(1,603	)
Future net cash flows	4,552			8,183		5,618
10% annual discount for estimated timing of cash flows	(3,455		)	(5,713	)	(4,017	)
Standardized measure of discounted future net cash flows	$	1,097		2,470		1,601

The 12-month weighted average prices used to estimate the Company’s total equivalent reserves were as follows:

	Arkoma		Piceance	Appalachia
			(Per Mcfe)
December 31, 2010	$	4.18	3.93	4.51
December 31, 2011	3.90		3.84	4.16
December 31, 2012	NA		NA	2.78

(Continued)

F-32

ANTERO RESOURCES LLC AND SUBSIDIARIES

Notes to Consolidated Financial Statements

December 31, 2010, 2011, and 2012

(e)Changes in Standardized Measure of Discounted Future Net Cash Flow

	Year ended December 31
	2010			2011		2012
	(In millions)
Sales of oil and gas, net of productions costs	$	(126	)	(255	)	(147	)
Net changes in prices and production costs	382			215		(1,631	)
Development costs incurred during the period	81			247		296
Net changes in future development costs	(61		)	(106	)	(92	)
Extensions, discoveries and other additions	695			1,684		813
Acquisitions	92			51		—
Divestitures	—			—		(1,277	)
Revisions of previous quantity estimates	113			(182	)	88
Accretion of discount	29			147		322
Net change in income taxes	(359		)	(605	)	653
Other changes	16			177		106
Net increase (decrease)	862			1,373		(869	)
Beginning of year	235			1,097		2,470
End of year	$	1,097		2,470		1,601

F-33