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**UNITED STATES SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

 

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**FORM 10-K/A**

**(Amendment No. 1)**

** **

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**(Mark one)**

 

| **x** | **ANNUAL REPORT PURSUANT TO   SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934** |
|-------|------------------------------------------------------------------------------------------------------|

 

**For the fiscal year ended December 31, 2010**

 

**or**

 

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

 

**For the transition period from      to      **

 

**Commission File No. 333-164876-06**

 

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**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) |

 

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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.  o  Yes  x  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.  x  Yes  o  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).  o  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

 

 

 

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**EXPLANATORY NOTE**

 

Prior to February 2, 2012, we filed annual, quarterly and periodic reports through EDGAR with Antero Resources Finance Corporation as the primary registrant.  Beginning on February 2, 2012, we have filed and intend to file all future annual, quarterly and periodic reports through EDGAR with Antero Resources LLC as the primary registrant.  Accordingly, in order to assist investors in accessing all of our relevant historical disclosures, we are re-filing this report through EDGAR with the primary registrant changed to Antero Resources LLC.  We also included expanded disclosures regarding oil and gas reserves and production data.  These additional disclosures did not change our estimates of total proved developed or undeveloped reserves.  The additional disclosures include adding a breakdown of proved developed reserves and proved undeveloped reserves to the reserves presentation on page 5, adding the average per unit sales prices to the production data schedule on page 9, clarifying under well counts on page 9 that our wells are natural gas wells that also produce NGLs and oil, and on the table on page F-33 adding the quantities of proved undeveloped reserves. No other changes have been made to the disclosure contained in this report, and this report does not disclose any new information related to events that may have occurred after March 30, 2011, the date of our original filing.

 

Antero Resources Finance Corporation (“Antero Finance”) was formed to be the issuer of Antero’s $525 million principal amount of senior notes due 2017 and is an indirect wholly owned subsidiary of Antero Resources LLC.  In this Annual Report on Form 10-K, references to “Antero,” “we,” “the Company,” “us,” “our” and “operating entities” refer to the companies that conduct Antero Resources LLC’s operations (Antero Resources Corporation, Antero Resources Midstream Corporation (through November 5, 2010), Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation, and, beginning December 1, 2010, Antero Resources Bluestone LLC), unless otherwise indicated or the context otherwise requires.  Certain oil and gas terms used in this report are defined under caption “Glossary of Certain Defined Terms” at the end of “Items 1 and 2.  Business and Properties” in this report.

 

TABLE OF CONTENTS

 
| CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING   STATEMENTS | ii               |
|-------------------------------------------------------------|------------------|
|                                                        |             |
| PART I                                                 | 1                |
|                                                        | Items 1 and   2. | Business and   Properties | 1 |
|                                                        | Item   1A.       | Risk   Factors | 22 |
|                                                        | Item 1B.         | Unresolved   Staff Comments | 36 |
|                                                        | Item   3.        | Legal   Proceedings | 36 |
|                                                        | Item 4.          | Submission   of Matters to a Vote of Security Holders | 37 |
|                                                        |             |   |   |
| PART II                                                | 38               |
|                                                        | Item 5.          | Market for   Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases   of Equity Securities | 38 |
|                                                        | Item 6.          | Selected   Financial Data | 38 |
|                                                        | Item 7.          | Management’s   Discussion and Analysis of Financial Condition and Results of Operations | 41 |
|                                                        | Item 7A.         | Quantitative   and Qualitative Disclosures about Market Risk | 58 |
|                                                        | Item 8.          | Financial   Statements and Supplementary Data | 61 |
|                                                        | Item 9.          | Changes in   and Disagreements with Accountants on Accounting and Financial Disclosure | 61 |
|                                                        | Item 9A.         | Controls and   Procedures | 61 |
|                                                        | Item   9B.       | Other   Information | 61 |
|                                                        |             |   |   |
| PART III                                               | 62               |
|                                                        | Item 10.         | Directors,   Executive Officers and Corporate Governance | 62 |
|                                                        | Item 11.         | Executive   Compensation | 65 |
|                                                        | Item 12.         | Security   Ownership of Certain Beneficial Owners and Management and Related Stockholder   Matters | 79 |
|                                                        | Item 13.         | Certain   Relationships and Related Transactions and Director Independence | 80 |
|                                                        |             |   |   |
| PART IV                                                | 82               |
|                                                        | Item 14.         | Principal   Accountant Fees and Services | 82 |
|                                                        | Item 15.         | Exhibits,   Financial Statement Schedules | 82 |
|                                                        |             |   |   |
| SIGNATURES                                                  | 85               |

 

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**CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS**

 

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements, other than statements of historical fact included in this 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 and oil prices;

 

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

 

·                  hedging strategy and results;

 

·                  future drilling plans;

 

·                  competition and government regulations;

 

·                  pending legal or environmental matters;

 

·                  marketing of natural gas and oil;

 

·                  leasehold or business acquisitions;

 

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

 

·                  general economic conditions;

 

·                  credit markets;

 

·                  uncertainty regarding our future operating results; and

 

·                  plans, objectives, expectations and intentions contained in this report that are not historical.

 

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

 

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natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A.  Risk Factors” in this Annual Report on Form 10-K.

 

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

 

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**PART I**

 

**Items 1 and 2.****                 ****Business and Properties**

 

**BUSINESS**

 

**Our Company**

 

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

 

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 existing acreage.  As of December 31, 2010, our estimated proved reserves were 3,231 Bcfe, consisting of 2,544 Bcf of natural gas, 104 MMBbl of natural gas liquids, and 10 MMBbl of oil.  As of December 31, 2010, 79% of our proved reserves were natural gas, 14% were proved developed and 87% were operated by us.  From December 31, 2006 through December 31, 2010, we grew our estimated proved reserves from 87 Bcfe to 3,231 Bcfe.  In addition, we grew our average daily production from 31 MMcfe/d for the year ended December 31, 2007 to 133 MMcfe/d for the year ended December 31, 2010.  For the year ended December 31, 2010, we generated cash flow from operations of $125.8 million, net income of $230.2 million and EBITDAX of $197.7 million.  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 Shale of the Appalachian Basin, the Woodford Shale of the Arkoma Basin (the Arkoma Woodford), the Fayetteville Shale of the Arkoma Basin, the Mesaverde tight sands, and the Mancos and Niobrara Shales of the Piceance Basin.  From inception, we have drilled and operated 380 wells through December 31, 2010 with a success rate of approximately 97%.  Our drilling inventory consists of approximately 15,000 potential well locations, all of which are unconventional resource opportunities.  For information on the possible limitations on our ability to drill our potential locations, see “Item 1A.  Risk Factors.

 

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

 

On November 4, 2010, we entered into an amended and restated senior secured revolving credit agreement (Credit Facility) with our lenders increasing the maximum amount of our Credit Facility from $400 million to $1 billion.  Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved reserves and are subject to semiannual redeterminations.  The initial borrowing base was set at $550 million.  The next semiannual redetermination of the borrowing base is scheduled to occur in April 2011.  At December 31, 2010, we had approximately $432 million of available borrowing capacity under the Credit Facility.

 

On November 5, 2010, we sold our Oklahoma midstream assets and received approximately $259 million of net cash proceeds from the sale and realized a gain of approximately $148 million.  We used the proceeds to pay down advances on the Credit Facility and thereby increase availability on our Credit Facility for working capital, drilling activities and property acquisitions.  We entered into long-term contracts with the purchaser of the Oklahoma midstream assets to continue to gather and process the Company’s Oklahoma gas production.  The terms of the Antero Resources LLC limited liability company operating agreement require us to make distributions sufficient to

 

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cover the members’ tax liabilities for taxable gains that are allocated to the members.  As a result of the gain on the sale of the midstream assets, we distributed $28.9 million to the members subsequent to December 31, 2010.

 

On December 1, 2010, we acquired 100% of the partnership interests in Bluestone Energy Partners, a general partnership which owned leasehold rights in approximately 37,250 acres in the Appalachian Basin in West Virginia and Pennsylvania and 96 producing wells.  The leasehold interests are in the same proximity and adjacent to our existing holdings in the area.  The consideration included approximately $96 million of cash, the assumption of  a $25 million note,  and  3,814,392 newly issued I-5 and B-6 units in Antero Resources LLC having an aggregate fair value of $97 million.

 

During the year ended December 31, 2010, we incurred approximately $332 million of capital expenditures for exploration and development of natural gas and oil properties.  Capital expenditures for exploration and development were allocated 48% to our Marcellus shale project in the Appalachian basin, 33% to the Arkoma basin and 19% to the Piceance Basin.  Total capital expenditures during the year ended December 31, 2010, including exploration and development, leasehold acquisition, and gathering systems, were $423 million.  Our board of directors has approved a capital expenditure budget of up to $559 million for 2011 which includes $452 million for drilling and completion $65 million for leasehold acquisitions, and $42 million for construction of gathering pipelines and facilities.  Approximately 73% of the budget is allocated to the Marcellus Shale, 14% is allocated to the Woodford Shale and Fayetteville Shale, and 13% is allocated to the Piceance Basin.  Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, commodity prices and drilling results.

 

During 2010, the Company continued its program to hedge part of its future natural gas sales.  At December 31, 2010, the Company has hedged a portion of its production through December 31, 2015 with commodity swaps covering approximately 263 Bcf of production from January 1, 2011 through December 31, 2015 at a weighted average index price of $6.14 per Mcf.  For 2011, we have hedged approximately 58.9 Bcfe of our production at a weighted average index price of $6.04 per Mcfe.

 

We operate in one industry segment, which is the exploration, development and production of natural gas, natural gas liquids (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.

 

**Corporate Sponsorship and Structure**

 

We began operations in 2004, and have funded our development and operating activities primarily through equity capital raised from private equity sponsors and institutional investors, through the issuance of $525 million of senior notes, through borrowings under our bank credit facilities, and through  operating cash flows.  Our primary private equity sponsors are affiliates of Warburg Pincus, Yorktown Energy Partners and Trilantic Capital Partners.

 

Antero Resources LLC was formed as a holding company in connection with our November 2009 corporate reorganization of the operating subsidiaries and the issuance of new classes of units.  Prior to this reorganization, all of our operations were conducted by five separately capitalized, commonly controlled, operating subsidiaries.

 

In connection with the November 2009 corporate reorganization, the stockholders of each of the operating subsidiaries contributed all of the outstanding shares of each operating subsidiary to Antero.  In return, Antero issued an equivalent number of units of different classes to such stockholders.  The units are substantially similar in character to the contributed stock of each operating subsidiary, including the relative priority of any distributions made by Antero as well as the vesting schedule applicable to shares held by any member of management.  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).  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.  In

 

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November 2010, we sold all of the outstanding capital stock of Antero Resources Midstream Corporation (the operating subsidiary which owned our Oklahoma midstream assets) to a third party.  For more information on the terms of the Antero limited liability company agreement, see “Item 13.  Certain Relationships and Related Party Transactions.”

 

Concurrent with the closing of the reorganization, Antero issued profit units to Antero Resources Employee Holdings LLC, a newly formed Delaware limited liability company.  These profit units only participate in distributions upon liquidation events meeting certain requisite financial return thresholds.  In turn, Antero Resources Employee Holdings LLC issued membership interests to certain of our officers and employees.

 

Antero Resources Finance Corporation (Antero Finance) was formed in October 2009 as an indirect wholly owned subsidiary of Antero for the purpose of arranging financing for Antero and the operating subsidiaries, including the 9.375% senior notes issued in November 2009 and January 2010.  The indenture governing the notes limits Antero Finance’s activity to those of a finance subsidiary.  Antero Finance does not own any significant assets other than intercompany obligations.  The payment of the principal, premium and interest on the notes is fully and unconditionally guaranteed on a senior unsecured basis by Antero, all of its wholly owned subsidiaries (other than Antero Finance) and certain of its future restricted subsidiaries.  The guarantees are unsecured senior indebtedness of the guarantors and have the same ranking with respect to the guarantors’ indebtedness as the notes have with respect to Antero Finance’s indebtedness.

 

**Business Strategy**

 

Our objective is to build value through consistent growth in estimated reserves and production on a cost-efficient basis while delineating future drilling locations.  Our strategy is to emphasize internally generated drillbit growth on our potential drilling locations in low-risk, repeatable, unconventional resource plays.  We have made significant investments in technical staff, acreage, seismic data and technology to build our drilling inventory.  Our strategy has the following principal elements:

 

·                  *Concentrate on unconventional resources in core operating areas*.  We currently operate in three primary basins: the Appalachian Basin in West Virginia and Pennsylvania, the Arkoma Basin in Oklahoma and the Piceance Basin in Colorado.  Concentrating our drilling and producing activities on unconventional resources in these core areas allows us to capitalize on the regional expertise that we have developed in interpreting specific geological and operating trends and optimizing drilling and completion techniques.  Operating in multiple core areas allows us to optimize capital allocation between basins based on risked well economics to balance our portfolio and achieve consistent and profitable production and reserve growth.

 

·                  *Drive growth through low-risk development drilling in established resource plays*.  We expect to generate profitable, long-term reserve and production growth predominantly through repeatable, low-risk development drilling on our assets.  We typically allocate the substantial majority of our drilling budget to our development and delineation projects.  We have a multi-year drilling inventory and have approximately 15,000 potential well locations on our existing leasehold acreage.  We have drilled 380 wells from inception through December 31, 2010 and have achieved an approximate 97% success rate.

 

·      *Focus on cost efficiency*.  We believe concentrating on our sizeable oil and gas resources in place will allow us to consistently increase production.  Our experience suggests that as we increase the density of development within our operating areas, we increase our expected recovery while reducing costs on a per well basis.  We endeavor to control costs such that our cost to find, develop and produce natural gas is within the best performing quartile of our peer group based on publicly available information.

 

·                  *Maintain financial flexibility and conservative financial position*.  We typically use equity capital to fund land acquisitions, exploratory drilling and initial infrastructure, while using cash flow from operations and debt financing to fund our drilling program.  As of December 31, 2010, we have approximately $432 million of available borrowing capacity under our Credit Facility, which, together with our operating cash flow, is expected to provide us with the financial flexibility to pursue our currently planned delineation and development drilling activities.

 

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·                  *Manage commodity price exposure through an active hedging program*.  We maintain an active hedging program designed to mitigate volatility in commodity prices and regional basis differentials.  As of December 31, 2010, we have entered into hedging contracts covering a total of approximately 263 Bcf of our natural gas production from January 1, 2011 through December 31, 2015 at a weighted average index price of $6.14 per Mcf.  For 2011, we have hedged approximately 58.9 Bcf of our production at a weighted average index price of $6.04 per Mcf.  Substantially all of our hedges are at regional sales points in our operating regions, which mitigates the risk of basis differential to the Henry Hub index.

 

·                  *Take advantage of processing opportunities for liquids-rich gas*.  We recently entered into a long-term gas processing agreement in the Piceance Basin allowing us to realize the value of the NGLs from our Piceance gas production effective January 1, 2011.  We believe that virtually all of our Piceance gas reserves are liquids-rich gas that can be processed under current market conditions and estimate that over 37% of our year-end 2010 Piceance proved reserves are liquids, primarily comprised of NGLs.  We also have an existing gas processing agreement in the Woodford Shale under which a portion of the our operated and non-operated gas production is processed, and we  estimate that approximately 9% of our year-end 2010 Woodford Shale proved reserves are liquids, primarily comprised of NGLs.  We are also reviewing gas processing and NGL market alternatives in the Marcellus Shale play where we believe that a substantial portion of our resource base is comprised of liquids-rich gas.

 

**Business Strengths**

 

We believe we have the following strengths:

 

·                  *Proven track record of efficient production and reserve growth*.  We have a proven track record of growth in our production and estimated proved reserves.  For example, we grew our production from an average of 31 MMcfe/d for the year ended December 31, 2007 to 133 MMcfe/d for the year ended December 31, 2010.  In addition, we have grown our estimated proved reserves from 87 Bcfe at December 31, 2006 to 3,231 Bcfe at December 31, 2010.

 

·                  *Multi-year, low-risk, development drilling inventory*.  Our drilling inventory consists of approximately 15,000 potential well locations, all of which are unconventional resource opportunities.  From inception in 2004 through December 31, 2010, we have drilled and operated 380 wells, achieving an approximate 97% success rate.  Our concentrated leasehold position has been delineated largely through drilling done by us as well as other industry players, which we believe will help us to achieve predictable and repeatable future well results and minimize investment risk.

 

·                  *Control over operating decisions and capital program*.  As of December 31, 2010, we operated 87% of our production.  Our high percentage of operated production allows us to effectively control operating costs, timing of development activities, application of technological enhancements, marketing of production and efficient allocation of our capital budget.  In addition, the timing of most of our capital expenditures is discretionary, which allows us a significant degree of flexibility to adjust the size and timing of our budgeted spending in response to changes in market conditions.

 

·      *Proven executive management team with track record of value creation*.  We believe our management team’s experience and expertise coupled with our multiple resource plays provides a distinct competitive advantage.  Our nine corporate officers have an average of 25 years of industry experience in the Midcontinent and Rocky Mountain operating regions and have successfully built, grown and sold three unconventional resource focused companies in the past 20 years.  Our Chairman and Chief Executive Officer and our President and Chief Financial Officer and many other members of our management team worked together as managers or executives while at Amoco, Barrett Resources, Pennaco Energy, Inc. or Antero Resources Corporation, a former affiliate of our company that operated in the Barnett Shale and was sold to XTO Energy in 2005.

 

·                  *Leading technical team with significant unconventional shale and tight sand experience*.  All of our proved reserves and resources are classified as unconventional resources, including fractured shale gas plays and basin-centered tight sand formations.  Since 2003, our technical team has drilled and operated over 250

 

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horizontal and over 150 vertical wells in the Barnett, Woodford and Marcellus shales and over 150 directional wells in the Piceance tight sands.  Our technical team has significant experience in drilling horizontal and directional wells in addition to fracture stimulation of unconventional formations.  We utilize the latest geologic, drilling and completion technologies to increase the predictability and repeatability of finding and recovering resources in these unconventional resource plays.  We were an early user of microseismic imaging to monitor frac performance in real time, completed one of the first simul fracs stimulating three horizontal wells simultaneously in the Barnett Shale and have drilled some of the longest lateral shale gas wells (over 9,400 feet) completed to date.

 

·                  *Strong sponsor support*.  We are backed by a number of well known financial sponsors, including Warburg Pincus, Yorktown Energy Partners and Trilantic Capital Partners.  To date, our equity investors have made total equity investments of approximately $1.5 billion.

 

**Our Operations**

* *

***Estimated Proved Reserves***

 

The information with respect to our estimated proved reserves presented below has been prepared by our independent reserve engineering firms or by our internal reserve engineers, as applicable, in accordance with the rules and regulations of the SEC applicable to the periods presented.  In this report, we have only included estimates of our proved reserves and have not included any estimates of probable or possible reserves.

 

In December 2008, the SEC adopted new rules related to modernizing reserve calculations and disclosure requirements for oil and natural gas companies, which became effective for annual reporting periods ending on or after December 31, 2009.  We adopted these new rules effective December 31, 2009 as required by the SEC.

 

*Reserves Presentation*

 

The following table summarizes our estimated proved reserves and related PV-10 at December 31, 2008, 2009 and 2010.  Over 99% of our proved reserves have been prepared by our independent reserve engineers at December 31, 2009 and 2010 and over 98% of our proved reserves were prepared by independent reserve engineers at December 31, 2008.  Our estimated proved reserves are located in the Appalachian Basin, the Arkoma Basin, and the Piceance Basin and are based on reports prepared by DeGolyer and MacNaughton (“D&M”), D&M, and Ryder Scott & Company, L.P., respectively, as of December 31, 2010.  Wright & Co. prepared our Appalachian Basin reserves as of December 31, 2009.  We refer to these firms collectively as our independent engineers.    Copies of the summary reports of our independent engineers with respect to each of our operating basins as of December 31, 2010 are filed as Exhibits 99.1 through 99.3 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,** |   |
|----------------------------------------|--------|-------------------------------|--------|
|                                   |   | **2008**                      |   | **2009** |   | **2010** |   |
| Estimated proved reserves:             |   |                          |   |   |   |   |   |
| Proved developed reserves:             |   |                          |   |   |   |   |   |
| Natural gas (Bcf)                      |   | 237                           |   | 272 |   | 400 |   |
| Oil (MMBbl)                            |   | —                        |   | 1 |   | 1 |   |
| NGLs (MMBbl)(1)                        |   | —                        |   | — |   | 9 |   |
| Proved undeveloped reserves:           |   |                          |   |   |   |   |   |
| Natural gas (Bcf)                      |   | 435                           |   | 858 |   | 2,143 |   |
| Oil (MMBbl)                            |   | 1                             |   | 1 |   | 9 |   |
| NGLs (MMBbl)(1)                        |   | —                        |   | — |   | 95 |   |
| Total estimated proved reserves (Bcfe) |   | 680                           |   | 1,141 |   | 3,231 |   |
| Proved developed producing (Bcfe)      |   | 238                           |   | 247 |   | 416 |   |
| Proved developed non-producing (Bcfe)  |   | 1                             |   | 29 |   | 41 |   |
| Proved undeveloped (Bcfe)              |   | 441                           |   | 865 |   | 2,774 |   |
| Percent developed                      |   | 35                            | %      | 24.2 | % | 14 | % |
| PV-10 (in millions)(2)            |   | $                             | 649    |   | $ | 245 |   | $ | 1,466 |   |
| Standardized measure (in millions)(2)  |   | $                             | 689    |   | $ | 235 |   | $ | 1,097 |   |

 

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(1)         We have elected to begin reporting NGLs separately from natural gas, beginning with our estimated proved reserves for the year ended December 31, 2010.  Due to the execution of a gas processing agreement for our Piceance gas production in December 2010, we believe that separate disclosure of NGLs will provide more transparency to our production and reserve reporting.  At December 31, 2010, 79% of our proved reserves by volume were natural gas, 19% were NGLs and 2% were crude oil, compared to 99% natural gas and 1% oil as of December 31, 2009 when we did not disclose NGLs separately.  NGLs for the Arkoma Basin at December 31, 2009 were included in reported natural gas volumes.

 

(2)         PV-10 was prepared using year-end prices computed using SEC rules in effect at the end of the periods presented, discounted at 10% per annum, without giving effect to taxes.  PV-10 may be considered 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.

 

The following table sets forth the estimated future net cash flows, contracts, from proved reserves (without giving effect to our commodity hedges), the present value of those net cash flows (PV-10), and the prices used in projecting future net cash flows at December 31, 2008, 2009 and 2010:

 
| ** **                                                      | ** ** | **At December 31,** | ** ** |
|-----------------------------------------------------------------|------------|-------------------------------|------------|
| **(In millions, except per Mcf data)** | ** ** | **2008(1)**                   | ** ** | **2009(2)** | ** ** | **2010(3)** | ** ** |
| Future net cash flows                                           |       | $                             | 1,696      |   | $ | 1,362 |   | $ | 5,990 |   |
| Present value of future net cash flows:                         |       |                          |       |   |   |   |   |
| Before income tax (PV-10)                                       |       | $                             | 649        |   | $ | 245 |   | $ | 1,466 |   |
| After income tax (Standardized measure)                         |       | $                             | 689        |   | $ | 235 |   | $ | 1,097 |   |

 

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(1)         Spot prices used at December 31, 2008 were $4.61 per Mcf for the Arkoma Basin and $4.61 per Mcf for the Piceance Basin.

 

(2)         12-month average prices used at December 31, 2009 were $3.25 per Mcf for the Arkoma Basin, $3.07 per Mcf for the Piceance Basin and $4.15 per Mcf for the Appalachian Basin.

 

(3)         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.

 

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).  Such calculations for 2008 are based on costs and prices in effect at December 31 without escalation.  In accordance with the new SEC rules, prices for 2009 and 2010 were based on a 12 month average, without escalation and costs are based on 2010 costs 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 2010*

 

The following table summarizes the changes in our estimated proved reserves during 2010 (in Bcfe):

 

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| **Proved reserves,   December 31, 2009**    |   | 1,141 |   |
|--------------------------------------------------|--------|-------|--------|
| Extensions, discoveries, NGL and other additions |   | 1,712 |   |
| Purchases                                        |   | 172   |   |
| Price and performance revisions                  |   | 253   |   |
| Production                                       |   | (47   | )      |
| **Proved reserves,   December 31, 2010**    |   | 3,231 |   |

 

During 2010, we added 1,712 Bcfe of proved reserves through the drill bit and NGL booking, and 172 Bcfe through acquisitions.  Positive performance and price revisions increased proved reserves by 253 Bcfe.  As a result, our estimated proved reserves as of December 31, 2010 totaled 3.2 Tcfe, up 183% from 1.1 Tcfe at December 31, 2009.  Our proved developed reserves increased 66% from the year ended December 31, 2009 to 457 Bcfe for the year ended December 31, 2010.

 

*Proved Undeveloped Reserves*

 

Our proved undeveloped reserves at December 31, 2010, as prepared by our independent engineers, were 2,774 Bcfe, 77% of which consisted of natural gas.  Proved undeveloped reserves at December 31, 2010 increased by 1,909 Bcfe from December 31, 2009, primarily attributable to positive drilling results in the Marcellus Shale and Piceance Basin, expected improvement in price realizations in the Piceance Basin due to our recently executed gas processing agreement, the volumetric uplift realized from reporting NGLs separately in the Piceance Basin and Woodford Shale, and increased well density in the East Rockpile area of the Woodford Shale.  Changes in proved undeveloped reserves that occurred during the year were due to:

 

·                  conversion of 59 Bcfe of proved undeveloped reserves into proved developed reserves;

 

·                  addition of new proved undeveloped reserves of 1,480 Bcfe;

 

·                  positive revision of 217 Bcfe in proved undeveloped reserves due to higher commodity prices and performance revisions; and

 

·                  acquisition of 153 Bcfe of proved undeveloped reserves.

 

During the year ended December 31, 2010, we converted our beginning proved undeveloped reserves to proved developed reserves at a rate of 7%.  Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2010 are approximately $4 billion over the next five years, which we expect we will finance through cash flow from operations, borrowings under our Credit Facility, 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, 2010 included in this report relating to our properties in the Arkoma Basin , the Piceance Basin and the Appalachian Basin were prepared by our independent engineers in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC.  Our independent reserve engineers were selected for their geographic expertise and their historical experience in engineering unconventional resources.  The technical persons at each independent reserve engineering firm responsible for preparing the 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.

 

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We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent engineers in their reserve estimation process.  Periodically, our technical team meets with each independent engineering contractor to review properties and discuss methods and assumptions used by such firms in their respective preparations of our year-end reserve estimates.  While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, preliminary copies of each independent engineer’s reserve reports are reviewed by our internal technical staff with representatives of such firms.  The independent engineers’ reserve estimates and related reports are reviewed and approved by our Vice President of Production, Kevin J. Kilstrom. 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.  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 independent engineers’ reserve estimates and related reports with 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, each independent engineer 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 is a commodity and, therefore, the price that we receive for the natural gas we produce is largely a function of market supply and demand.  Demand for natural gas in the United States has increased dramatically since 2000; however, the recent economic crisis reduced this demand during the second half of 2008 and through 2010, while supplies increased.  Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms.  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.

 

The following table sets forth information regarding our production for each field containing 15% or more of our total estimated proved reserves and our total production, and regarding our revenues and realized prices and production costs for the years ended December 31, 2008, 2009 and 2010. 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.”

 

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| ** **                                                      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                      | ** ** | **2008**                                   | ** ** | **2009** | ** ** | **2010** | ** ** |
| Production data:                                                |       |                                       |       |   |   |   |   |
| Natural gas (Bcf):                                              |       |                                       |       |   |   |   |   |
| Arkoma                                                          |       | 18.6                                       |       | 23.4 |   | 23.7 |   |
| Piceance                                                        |       | 11.7                                       |       | 11.2 |   | 11.3 |   |
| Appalachia                                                      |       | —                                     |       | 0.5 |   | 10.8 |   |
| Total                                                           |       | 30.3                                       |       | 35.1 |   | 45.8 |   |
| Oil (MBbl):                                                     |       |                                       |       |   |   |   |   |
| Arkoma                                                          |       | 20.5                                       |       | 26.7 |   | 24.8 |   |
| Piceance                                                        |       | 94.4                                       |       | 87.3 |   | 102.7 |   |
| Appalachia                                                      |       | —                                     |       | — |   | — |   |
| Total                                                           |       | 114.9                                      |       | 114.0 |   | 127.5 |   |
| NGLs (MBbl)(1)                                                  |       | 150.0                                      |       | 433.3 |   | 333.3 |   |
| Total combined production (Bcfe)                                |       | 31.9                                       |       | 38.4 |   | 48.6 |   |
| Daily combined production (MMcfe/d)                             |       | 87.4                                       |       | 105.2 |   | 133.1 |   |
| Gas and oil production revenues (in millions)                   |       | $                                          | 229.7      |   | $ | 129.6 |   | $ | 206.5 |   |
| Average Prices:                                                 |       |                                       |       |   |   |   |   |
| Natural gas (per Mcf)                                           |       | $                                          | 7.14       |   | $ | 3.46 |   | $ | 4.24 |   |
| Oil (per Bbl)                                                   |       | $                                          | 86.65      |   | $ | 50.05 |   | $ | 66.44 |   |
| NGLs (per Bbl)                                                  |       | $                                          | 58.48      |   | $ | 32.76 |   | $ | 47.33 |   |
| Average prices before effects of hedges (per   Mcfe)(2)         |       | $                                          | 7.41       |   | $ | 3.62 |   | $ | 4.43 |   |
| Average realized prices after-effects of hedges   (per Mcfe)(2) |       | $                                          | 8.25       |   | $ | 6.88 |   | $ | 6.02 |   |
| Average costs per Mcfe:                                         |       |                                       |       |   |   |   |   |
| Lease operating costs                                           |       | $                                          | 0.43       |   | $ | 0.49 |   | $ | 0.55 |   |
| Gathering, compression and transportation                       |       | $                                          | 0.94       |   | $ | 0.79 |   | $ | 0.98 |   |
| Production taxes                                                |       | $                                          | 0.33       |   | $ | 0.14 |   | $ | 0.19 |   |
| Depreciation, depletion, amortization and   accretion           |       | $                                          | 4.03       |   | $ | 3.91 |   | $ | 2.84 |   |
| General and administrative                                      |       | $                                          | 0.52       |   | $ | 0.58 |   | $ | 0.47 |   |

 

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

 

(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 them as hedges.

* *

***Productive Wells***

 

As of December 31, 2010, we had a total of 1,031 gross (385 net) producing wells averaging a 40.2% working interest. Our wells are gas wells, many of which also produce oil, condensate and NGLs, we do not have interests in any wells that produce only oil or NGLs.

 

***Acreage***

 

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2010.  A majority of our developed acreage is subject to mortgage liens securing our Credit Facility.  Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

 
| **Developed Acres** | ** ** | **Undeveloped Acres** | ** ** | **Total Acres** | ** ** |
|--------------------------|------------|----------------------------|------------|----------------------|------------|
| **Gross**                | ** ** | **Net**                    | ** ** | **Gross**            | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| 144,582                  |       | 73,378                     |       | 324,808              |       | 249,275 |   | 469,390 |   | 322,653 |   |

* *

*Undeveloped Acreage Expirations*

 

The following table sets forth the number of total gross and net undeveloped acres as of December 31, 2010 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** | ** ** |
|------------|------------|-----------|------------|---------|------------|
| 2011       |       | 47,764    |       | 26,095  |       |
| 2012       |       | 15,914    |       | 11,126  |       |
| 2013       |       | 39,644    |       | 29,552  |       |

 

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* *

***Drilling Activity***

 

The following table summarizes our drilling activity for the years ended December 31, 2008, 2009 and 2010. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells.

 
| ** **              | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------|------------|--------------------------------------------|------------|
| ** **              | ** ** | **2008**                                   | ** ** | **2009** | ** ** | **2010** | ** ** |
| ** **              | ** ** | **Gross**                                  | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| Development wells:      |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive              |       | 38.0                                       |       | 25.4 |   | 35.0 |   | 4.8 |   | 128.0 |   | 23.8 |   |
| Dry                     |       | 1.0                                        |       | 0.8 |   | — |   | — |   | — |   | — |   |
| Total development wells |       | 39.0                                       |       | 26.2 |   | 35.0 |   | 4.8 |   | 128.0 |   | 23.8 |   |
| Exploratory wells:      |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Productive              |       | 297.0                                      |       | 80.1 |   | 125.0 |   | 19.9 |   | 56.0 |   | 22.3 |   |
| Dry                     |       | 2.0                                        |       | 0.6 |   | 1.0 |   | 0.1 |   | 11.0 |   | 5.0 |   |
| Total exploratory wells |       | 299.0                                      |       | 80.7 |   | 126.0 |   | 20.0 |   | 67.0 |   | 27.3 |   |

 

**Our Core Operating Areas**

*** ***

***Appalachian Basin Marcellus Shale***

 

Our properties in the Appalachian Basin are principally located in southwestern Pennsylvania and northern West Virginia.  As of December 31, 2010, we had approximately 165,000 net leasehold acres in the Appalachian Basin, 75% of which was held by production.  All of this acreage includes Marcellus Shale rights.  For the year ended December 31, 2010, we had 30 MMcfe/d of average daily production from the Appalachian Basin.

 

Since spudding our first well in the Appalachian Basin in March 2009, through December 31, 2010 we have completed a total of 20 gross (19 net) horizontal wells and 1 gross (1 net) vertical well in the area.  Sixteen gross (15 net) horizontal wells were completed in 2010.  We have an additional 14 gross (13 net) wells drilling or waiting on completion as of December 31, 2010.  Currently we have five drilling rigs operating in the Appalachian Basin.  As of December 31, 2010, we had 1,916 gross horizontal well locations in the basin.  Effective December 1, 2010, we purchased 96 producing wells from Bluestone Energy Partners, 47 of which are completed in the Marcellus formation and the balance in other shallow formations.  Of the 47 Marcellus wells, three are horizontal Marcellus producers which accounted for 68% of the net production of the 96 purchased wells.

 

Approximately 73% of our 2011 drilling budget has been allocated to the Appalachian Basin.

 

***Arkoma Basin Woodford Shale***

 

Our properties in the Arkoma Woodford are located in eastern Oklahoma.  As of December 31, 2010, we had approximately 74,000 net leasehold acres in the area, 77% of which was held by production.  For the year ended December 31, 2010, we had 64 MMcfe/d of average daily production in the area, including NGLs retained by our midstream business.

 

Our activity in the Arkoma Woodford has consisted of a combination of exploratory, delineation and development drilling designed both to secure acreage and to delineate areas of economic production for further development.  As of December 31, 2010, we had a total of 571 gross (134 net) producing wells in the area.  We are currently operating one drilling rig in the Arkoma Woodford and, as of December 31, 2010, had over 2,800 gross horizontal well locations in the area.

 

During 2007, we and the industry began to develop this area using tighter spacing to determine the optimum density for development.  These results indicate that 80-acre well density is economically feasible on much of our acreage.  Our development efforts to date have also successfully demonstrated that we are able to drill and complete wells across minor faults that previously limited the length of our lateral drilling.

 

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Approximately 14% of our 2011 drilling budget has been allocated to the Arkoma Basin Woodford Shale.

 

***Piceance Basin***

 

Our properties in the Piceance Basin are located on the western slope of Colorado.  As of December 31, 2010, we had approximately 68,000 net leasehold acres in the area.

 

Since drilling our first well in the Piceance Basin in 2005 and through December 31, 2010, we have operated and completed 173 gross (167 net) producing vertical and directional wells in the area.  Additionally, we purchased 19 gross (19 net) vertical producing wells in 2008 for a total completed well count of 192 gross and 186 net wells.  As of December 31, 2010, we had 11 gross (11 net) wells waiting on completion or testing.  For the year ended December 31 2010, we had approximately 7,700 gross Mesaverde well locations in the area.  The deeper Mancos Shale and Niobrara Shale intervals also had producing potential over the majority of our lease holdings and have recently been horizontally tested at several sites in the Piceance Basin by other operators.  This potential resource in the Mancos has approximately 1,300 potential horizontal well locations. We had average net production of 33 MMcfe/d for the year ended December 31, 2010.  We are currently operating one drilling rig and one completion rig in the Piceance Basin.

 

We recently entered into a long-term gas processing agreement in the Piceance Basin allowing us to realize the value of our NGLs from our Piceance Mesaverde gas reserves effective January 1, 2011.  We believe that virtually all of our Piceance gas reserves are liquids-rich gas that can be processed under current market conditions and estimate that over 35% of our year-end 2010 Piceance proved reserves are liquids, primarily comprised of NGLs.  The processing agreement expires December 1, 2025 and provides for the processing of quantities up to 60 MMcf/d until October 1, 2011 and increasing to a maximum of 120 MMcf/d in 2013.  For processed gas, we will realize the sales price of NGLs less gathering fees and other expenses.

 

We believe we are well positioned to take advantage of the significant opportunities we have identified in the development of the Mesaverde tight sands and the Mancos Shale and Niobrara Shale in the Piceance Basin.

 

Approximately 13% of our 2011 drilling budget has been allocated to the Piceance Basin.

 

***Other Operating Areas***

 

*Fayetteville Shale*

 

As of December 31, 2010, we held approximately 5,600 net acres in the eastern part of the Fayetteville Shale. We had average production of 7 MMcfe/d for the year ended December 31, 2010.  We have 151 gross (9 net) wells currently on production.  We do not operate wells in the Fayetteville Shale but participate in wells operated by others.  We have over 800 gross horizontal well locations in the area.

 

***Our Gathering Systems***

 

*Arkoma Midstream System*

 

On November 5, 2010, we completed the sale of our Oklahoma midstream assets and received approximately $259 million of net proceeds from the sale.  We realized a gain of approximately $148 million on the sale.  We used the proceeds to pay down advances on our Credit Facility and thereby increase availability on our Credit Facility for working capital, drilling activities and property acquisitions.  We entered into long-term contracts with the purchaser of the midstream assets to continue to gather and process our Oklahoma gas production.

 

*Piceance Gathering System*

 

We own approximately 22 miles of gathering pipeline in the Gravel Trend in the Piceance Basin.  We do not currently own or operate any compression facilities in the area.  Our gas is gathered and delivered to third parties for compression, processing and takeaway.

 

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* *

*Appalachian Gathering System*

 

We own and operate approximately 41 miles of gathering pipelines and three compressor stations in West Virginia and Pennsylvania to support our drilling activities in the Marcellus Shale play.  Two additional compressor stations, which are owned and operated by a third party, are connected to our gathering system and provide compression and dehydration services on a fixed fee basis.

 

**Takeaway Capacity**

* *

*Arkoma Basin*

 

We currently have firm takeaway capacity of 20 MMcf/d on the Ozark Gas Transmission Pipeline through August 2012 and 30 MMcf/d of firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline through July 2014.  Of the 30 MMcf/d  firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline, 20 MMcf/d has been released to a financial intermediary who is obligated to purchase our gas at a Transco Zone 4 market based price, less applicable transportation fees, for the term of the capacity release.  Beginning August 1, 2011, we have an additional 10 MMcf/d of firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline through July 2014.  As of August 1, 2014, the total commitment is reduced to 20,000 MMcf/d until August 1, 2015 when the commitment is further reduced to 10,000 MMcf/d until August 1, 2016 when the commitment expires. 

 

*Piceance Basin*

 

We currently have 40 MMcf/d of firm takeaway capacity on the WIC Pipeline through September 2020.  The El Paso WIC Pipeline expansion from Meeker, Colorado to Opal, Wyoming is fully operational and provides 230 MMcf/d of incremental capacity to more liquid markets.  Additionally, we have contracted for 25 MMcf/d of firm takeaway capacity for 10 years on the El Paso Ruby Pipeline that is currently under construction.  The Ruby Pipeline will begin in Opal, Wyoming and is expected to provide approximately 1.3 Bcf/d of incremental pipeline capacity from the Rocky Mountain region to the Northwest and West Coast of the United States beginning in July 2011.

 

*Appalachian Basin*

 

We have 40 MMcf/d of firm transportation on the Columbia Pipeline from August 2009 for 7.5 years.  Additionally, we have 110 MMcf/d of firm transportation capacity on the Columbia Pipeline through March 2021; 40 MMcf/d of this commitment will not be effective until April 2011.  As a result of our acquisition of Bluestone Energy Partners on December 1, 2010, we acquired an additional 10 MMcf/d of firm transportation capacity on the Columbia Gas Transmission Pipeline through December 2013 and 13.1 MMcf/d of firm capacity on the Columbia Gas Transmission Pipeline through September 2025.  Additionally, as a result of the acquisition of Bluestone Energy Partners, we acquired 3.5 MMcf/d of firm transportation capacity on the Dominion Transmission Gateway expansion project for a term of 10 years from the initial in-service date which is currently projected to be September 2012.

 

**Marketing and Major Customers**

 

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 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 ranging anywhere from one day to seven 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.  However, based on the current demand for natural gas 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.  Our NGLs are sold to one customer in the Piceance Basin and one customer in the Arkoma Basin; the loss of either of these customers could adversely affect our financial condition and results of operations.  See “Note 2(p)—Concentrations of Credit Risk” in our consolidated financial statements for the years ended December 31, 2008, 2009 and 2010 included elsewhere in this report.

 

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** **

**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.

 

In addition, the acquisition agreement relating to the purchase of our properties in the Appalachian Basin in 2008 contains various drilling commitments that may require us to drill 179 wells between January 1, 2009 and June 30, 2018 at intervals specified in the agreement.  As of December 31, 2010, we had met our required cumulative drilling commitment of 24 wells, and had an additional 30 wells in various stages of drilling or completion which will satisfy our 2011 drilling commitment. If we do not fulfill our drilling commitments, title to portions of the properties we purchased may revert to the seller, which could have a material adverse effect on our future business and results of operations.

 

**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.  Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other natural gas operations in certain areas of the Rocky Mountain region.  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

 

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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 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, 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.  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 a number of 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, 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

 

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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 eliminated 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 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, EP Act 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 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 EP Act 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 beginning in 2009, 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.

 

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

 

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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.  Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.

 

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 Matters**

 

Our operations are subject to numerous stringent federal, state and local statutes and regulations governing 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 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

 

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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 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.

 

***National Environmental Policy Act***

 

Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or 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 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.

 

***Waste Handling***

 

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), which imposes requirements related to the generation, transportation, treatment, storage, handling, disposal and clean-up of solid and hazardous wastes and the disposal of non-hazardous wastes.  Under the auspices of the Environmental Protection Agency, or the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.  Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent, non-hazardous waste provisions, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.  Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.”

 

We believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we held all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations.  Although we believe that the current costs of managing our wastes as they are presently classified, are reflected in our budget, any legislative or regulatory reclassification of natural gas and oil exploration and production wastes could increase our costs to manage and dispose of such wastes.

 

***Water Discharges***

 

The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other 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 same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development.  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 maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with the terms thereof.  We are currently undertaking a review of recently acquired natural

 

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gas properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans, the costs of which are not expected to be substantial.

 

***Air Emissions***

 

The Federal Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements.  In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.  These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specific equipment or technologies to control emissions.

 

While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, we do not believe that such requirements will have a material adverse effect on our operations.  Obtaining permits has the potential to delay the development of natural gas and oil projects.  We believe that we are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations.

 

***Regulation of “Greenhouse Gas” Emissions***

 

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes, the U.S. Environmental Protection Agency, or  EPA,   adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles effective January 2, 2011 and thereby triggered permit review for GHG emissions from certain stationary sources.  The EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs.  This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis.  The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules.  These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.  With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore oil and natural gas production activities, which includes certain of our operations.  In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  The adoption and implementation of any legislation or 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 or 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 hydrocarbons from tight formations.  The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.  The process is typically regulated by state oil and gas commissions.  Nonetheless, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic

 

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fracturing practices.  In addition, legislation was proposed in the recently completed session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process and similar legislation could be introduced in the current session of Congress.  Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances.  However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act’s Underground Injection Program.  While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision.  At the same time, if new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

 

***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 requires 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 OSHA requirements.

 

***Endangered Species Act***

 

The 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.  Similar protections are offered to migratory birds under the Migratory Bird Treaty Act.  We conduct operations on federal natural gas and oil leases in areas where certain species that are listed as threatened or endangered and where other species, such as the sage grouse, potentially could be listed as threatened or endangered under the ESA 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.  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 2010, nor do we anticipate that such expenditures will be material in 2011.

 

**Employees**

 

As of December 31, 2010, we had 77 full-time employees, including ten in geology, 22 in production and engineering, 20 in accounting and administration, 20 in land, three in midstream and two senior executives.  We also employed approximately 50 contract personnel who assist our full-time employees with respect to specific tasks and 109 outside lease brokers.  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.

 

“*AMI*.”  Area of mutual interest.

 

“*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 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.

 

“*Drill-to-earn*.”  The process of earning an interest in leasehold acreage by drilling a well pursuant to a farm-in, exploration, or other agreement.

 

“*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.

 

“*Enhanced recovery*.”  The recovery of natural gas and oil through the injection of liquids or gases into the reservoir, supplementing its natural energy.  Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

 

“*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.

 

“*Farm-in or farm-out*.”  An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

 

“*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.

 

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“*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.

 

“*Infill wells*.”  Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

 

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

 

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

 

“*MMBtu*.”  One million British thermal units.

 

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

 

“*MMcfe*.”  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.

 

“*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

 

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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.

 

**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 Form 10-K, actually occurs, our business, financial condition or results of operations could suffer.  The risks described below are not the only ones facing us.  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

 

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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 the current 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 current worldwide financial and credit crisis has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide.  The shortage of liquidity and credit combined with recent substantial losses in worldwide equity markets has lead to a worldwide economic recession.  The slowdown in economic activity caused by such recession has reduced worldwide demand for energy and resulted in lower natural gas prices.  Natural gas spot prices have recently been particularly volatile and declined from record high levels in early July 2008 of over $13.00 per Mcf to less than $4.00 per Mcf in 2010.

 

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.  Lower natural gas prices may also reduce the amount of natural gas that we can produce economically.

 

Substantial decreases in natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects.  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 $390 million in 2010.  Our board of directors has approved a capital expenditure budget of up to $559 million for 2011 which includes $452 million for drilling and completion, $65 million for leasehold acquisitions, and $42 million for construction of gathering pipelines and facilities.  We expect to fund these capital expenditures with cash generated by operations and through borrowings under our Credit Facility.  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

 

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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 senior secured revolving 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 these 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;

 

·                  equipment failures or accidents;

 

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

 

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·                  declines in natural gas prices;

 

·                  limited availability of financing at acceptable rates;

 

·                  title problems; 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 9.375% senior notes due 2017, 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 indenture governing the 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 indenture governing our 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.

 

In November 2010, the borrowing base under our Credit Facility was redetermined at $550 million.  Our next scheduled borrowing base redetermination is expected to occur in April 2011.  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:

 

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·                  sell assets;

 

·                  make loans to others;

 

·                  make investments;

 

·                  enter into mergers;

 

·                  make certain payments;

 

·                  incur liens; and

 

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

 

The indenture governing our senior notes contains 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 indenture governing the 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 indenture governing the 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.  In November 2010, the borrowing base under our Credit Facility was redetermined at $550 million.  Our next scheduled borrowing base redetermination is expected to occur in April 2011.

 

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—Capital Resources and Liquidity—Cash Flow Provided by Financing Activities—Senior Secured Revolving Credit Facility” and “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Cash Flow Provided by Financing Activities—Senior Notes” of this Annual Report on Form 10-K.

 

***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.***

 

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 263 Bcf of our natural gas production from January 1, 2011 through December 2015.  We are currently realizing a significant benefit from these hedge positions.  For example, for the years ended December 31, 2009 and 2010, we received approximately $117 million and $74 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

 

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volumes at declining prices through December 2014.  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.  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 these 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.

 

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 15,000 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.

 

In addition, the acquisition agreement relating to the purchase of our properties in the Appalachian Basin in 2008 contains various drilling commitments that may require us to drill 179 wells at intervals specified in the agreement over a seven-year period.  As of December 31, 2010, we had met our required cumulative drilling

 

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commitment of 24 wells, and had an additional 30 wells in various stages of drilling or completion.  If we do not fulfill our drilling commitments, title to portions of the properties we purchased may revert to the seller, 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.***

 

Approximately 86% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2010.  Our 2.8 Tcfe of estimated proved undeveloped reserves will require an estimated $4.0 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, 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 natural gas 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 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 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.

 

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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, 2010, the estimated fair value of our commodity derivative contracts was approximately $230 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.

 

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, 2010) and the sale of our natural gas production ($25 million in receivables at December 31, 2010), 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, 2010 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.

 

***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 flows 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;

 

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·                  pollution and other environmental damage;

 

·                  regulatory investigations and penalties;

 

·                  suspension of our operations; and

 

·                  repair and remediation costs.

 

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.

 

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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.

 

***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.

 

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

 

We may incur significant delays, costs and liabilities as a result of environmental, 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, state and local laws and regulations relating to protection of the environment, 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 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.  In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health

 

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and safety impacts of our operations.  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.

 

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.

 

***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 “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the 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 greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes, the EPA adopted regulations under existing provisions of the federal Clean Air Act that require a reduction in emissions of GHGs from motor vehicles effective January 2, 2011 and thereby triggered permit review for GHG emissions from certain stationary sources.  The EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs.  This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject

 

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to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis.  The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing or requiring state environmental agencies to implement the rules. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.  With regards to the monitoring and reporting of GHGs, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore oil and natural gas production activities, which includes certain of our operations.  In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs.  The adoption and implementation of any legislation or 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 or 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.

 

***Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.***

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. Nonetheless, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. In addition, legislation was proposed in the recently completed session of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process and similar legislation could be introduced in the current session of Congress. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act’s Underground Injection Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, if new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

 

***The recent adoption of derivatives legislation by the United States Congress 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 United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.  The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment.  The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation.  The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time.  The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.  The

 

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new legislation and any new 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 existing derivative contracts, and increase our exposure to less creditworthy counterparties.  If we reduce our use of derivatives as a result of the legislation 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 legislation 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 commodity prices decline as a consequence of the legislation and regulations. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

 

***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.

 

***We have limited control over activities on properties we do not operate, which could reduce our production and revenues.***

 

A significant portion of our business activities is conducted through joint operating agreements under which we own partial interests in natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

 

***Seasonal weather conditions and lease stipulations 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 lease stipulations designed to protect various wildlife. In certain areas of Colorado, for example, drilling and other natural gas activities can only be conducted during the spring and summer months. 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.

 

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***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, 2010, outstanding borrowings under our Credit Facility were approximately $100 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased annual interest expense of approximately $1 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. 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 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,

 

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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 senior secured revolving credit facility imposes and the indenture governing the senior notes will impose certain limitations on our ability to enter into mergers or combination transactions. Our senior secured revolving credit facility and the indenture governing the 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.***

 

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits currently available to oil and gas exploration and production companies. 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; 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.

 

In addition, former Pennsylvania Governor Ed Rendell’s budget proposal for fiscal year 2011, released in February 2009, proposed a new natural gas wellhead tax on both volumes and sales of natural gas extracted in Pennsylvania, where a portion of our acreage in the Appalachian Basin is located. This tax was not approved prior to the Rendell administration leaving office.  The new administration in Pennsylvania has not proposed such a tax.  The passage of any legislation as a result of the Pennsylvania state budget proposal could increase the tax burden on our operations in the Appalachian Basin.

 

**Item 1B.****                            ****Unresolved Staff Comments**

 

Not applicable.

 

**Item 3.****        ****Legal Proceedings**

 

We are a named defendant in certain lawsuits arising in the ordinary course of business. While the outcome of lawsuits against us cannot be predicted with certainty, our management team does not expect these matters to have a material adverse impact on our financial statements.

 

In February 2011, we entered into a Compliance Order on Consent with the Colorado Department of Public Health and Environment, or CDPHE, to resolve a 2008 notice of violation, or NOV.  The NOV arose from a CDPHE inspection in 2007 alleging deficiencies in the stormwater management program implemented for our construction of a pipeline in 2007, notwithstanding that we believed we had promptly corrected the deficiencies identified in the inspection.  Following the expiration of the public notice and comment period for the Compliance Order on Consent expected on or about the beginning of the second quarter of 2011, we have committed to pay a total of $147,661 in the form of $26,802 in civil penalties and $120,859 towards funding Garfield County’s pilot woodstove exchange program, a supplemental environmental project that is expected to lower air pollution and promote energy efficiency in the local area where our pipeline is located.

 

In February 2009, we received a grand jury subpoena from the U.S. Environmental Protection Agency regarding an alleged unauthorized discharge at a well site near Atoka, Oklahoma in May 2007. Based on information presently available to us, it appears that well fracturing fluids stored by a third party contractor in a tank leaked into a surrounding berm and were later discharged along with rainwater into a nearby waterway. The site was

 

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being managed by the contractor at the time of the incident. We have provided the information that was requested by the subpoena. No claim has been made against us with respect to this matter to date, and, based on information presently available to us, we do not believe that our company is a target of the investigation.

 

**Item 4.****        ****Submission of Matters to a Vote of Security Holders**

 

Not applicable.

 

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**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, 2010, the subsidiaries of Antero Resources LLC include Antero Resources Corporation, Antero Resources Piceance Corporation, Antero Resources Pipeline Corporation, Antero Resources Appalachian Corporation, Antero Resources Bluestone LLC (collectively referred to as the “Antero Entities” or the “operating entities”), and Antero Resources Finance Corporation. Our statement of operations data includes the operations of Antero Midstream Corporation through November 5, 2010 when this subsidiary was sold.  Prior to the formation of Antero Resources LLC in 2009, the Antero Entities were under common control, as the ownership interests in each entity were previously held by the same individual stockholders in the same percentages. In 2009, the ownership interests in each of the Antero Entities were contributed to a newly formed limited liability company, Antero Resources LLC, resulting in each entity being a wholly owned subsidiary of Antero Resources LLC. The assets and liabilities of the Antero Entities were carried forward at their historical basis. The selected statement of operations data for the years ended December 31, 2008, 2009 and 2010 and the balance sheet data as of December 31, 2009 and 2010 are derived from our audited consolidated financial statements included elsewhere in this report. The selected statement of operations data for the years ended December 31, 2006 and 2007 and the balance sheet data as of December 31, 2006, 2007, and 2008 are derived from our audited consolidated financial statements not included in this report. 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.

 
| ** **                                                          | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands, except ratios)**                    | ** ** | **2006**                                   | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
| **Statement of operations data:**                                   |       |                                       |       |   |   |   |   |   |   |   |   |
| Operating revenues:                                                 |       |                                       |       |   |   |   |   |   |   |   |   |
| Natural gas sales                                                   |       | $                                          | 14,271     |   | $ | 63,975 |   | $ | 220,219 |   | $ | 123,915 |   | $ | 197,991 |   |
| Oil sales                                                           |       | 523                                        |       | 3,749 |   | 9,496 |   | 5,706 |   | 8,471 |   |
| Realized and unrealized gains on commodity   derivative instruments |       | 14,331                                     |       | 18,992 |   | 116,354 |   | 55,364 |   | 244,284 |   |
| Gathering and processing revenue                                    |       | 717                                        |       | 4,778 |   | 20,421 |   | 23,005 |   | 20,554 |   |
| Gain on sale of Oklahoma midstream assets                           |       | —                                     |       | — |   | — |   | — |   | 147,559 |   |
| Total revenues                                                      |       | 29,842                                     |       | 91,494 |   | 366,490 |   | 207,990 |   | 618,859 |   |
| Operating expenses:                                                 |       |                                       |       |   |   |   |   |   |   |   |   |
| Lease operating expenses                                            |       | 1,189                                      |       | 4,435 |   | 13,350 |   | 17,606 |   | 25,511 |   |
| Gathering, compression and transportation                           |       | 2,482                                      |       | 10,016 |   | 29,033 |   | 28,190 |   | 45,809 |   |
| Production taxes                                                    |       | 1,012                                      |       | 2,233 |   | 10,281 |   | 4,940 |   | 8,777 |   |
| Exploration expenses                                                |       | 8,832                                      |       | 17,970 |   | 22,998 |   | 10,228 |   | 24,794 |   |
| Impairment of unproved properties                                   |       | 8,117                                      |       | 4,995 |   | 10,112 |   | 54,204 |   | 35,859 |   |
| Depletion, depreciation and amortization                            |       | 7,940                                      |       | 50,091 |   | 124,821 |   | 139,813 |   | 133,955 |   |
| Accretion of asset retirement obligations                           |       | 9                                          |       | 68 |   | 176 |   | 265 |   | 317 |   |
| Expenses related to acquisition of business                         |       | —                                     |       | — |   | — |   | — |   | 2,544 |   |
| General and administrative                                          |       | 7,478                                      |       | 11,682 |   | 16,171 |   | 20,843 |   | 21,952 |   |
| Total operating expenses                                            |       | 37,059                                     |       | 101,490 |   | 226,942 |   | 276,089 |   | 299,518 |   |
| Operating income (loss)                                             |       | (7,217                                     | )          | (9,996 | ) | 139,548 |   | (68,099 | ) | 319,341 |   |
|                                                                     |            |                                            |            |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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| ** **                                                                | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands, except ratios)**                          | ** ** | **2006**                                   | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
| Other expense:                                                            |       |                                       |       |   |   |   |   |   |   |   |   |
| Interest expense                                                          |       | $                                          | (1,366     | ) | $ | (25,124 | ) | $ | (37,594 | ) | $ | (36,053 | ) | $ | (56,463 | ) |
| Realized and unrealized losses on interest   derivative instruments, net  |       | —                                     |       | (3,033 | ) | (15,245 | ) | (4,985 | ) | (2,677 | ) |
| Total other expense                                                       |       | (1,366                                     | )          | (28,157 | ) | (52,839 | ) | (41,038 | ) | (59,140 | ) |
| Income (loss) before income taxes                                         |       | (8,583                                     | )          | (38,153 | ) | 86,709 |   | (109,137 | ) | 260,201 |   |
| Income tax (expense) benefit                                              |       | (400                                       | )          | 400 |   | (3,029 | ) | 2,605 |   | (30,009 | ) |
| Net income (loss)                                                         |       | (8,983                                     | )          | (37,753 | ) | 83,680 |   | (106,532 | ) | 230,192 |   |
| Noncontrolling interest in net loss (income) of   consolidated subsidiary |       | —                                     |       | — |   | 276 |   | 363 |   | (1,564 | ) |
| Net income (loss) attributable to Antero equity   owners                  |       | $                                          | (8,983     | ) | $ | (37,753 | ) | $ | 83,956 |   | $ | (106,169 | ) | $ | 228,628 |   |
| **Balance sheet data (at period   end):**                                 |       |                                       |       |   |   |   |   |   |   |   |   |
| Cash and cash equivalents                                                 |       | $                                          | 1,945      |   | $ | 11,114 |   | $ | 38,969 |   | $ | 10,669 |   | $ | 8,988 |   |
| Other current assets                                                      |       | 35,036                                     |       | 64,145 |   | 165,199 |   | 84,175 |   | 147,917 |   |
| Total current assets                                                      |       | 36,981                                     |       | 75,259 |   | 204,168 |   | 94,844 |   | 156,905 |   |
| Natural gas properties, at cost (successful   efforts method):            |       |                                       |       |   |   |   |   |   |   |   |   |
| Unproved properties                                                       |       | 61,307                                     |       | 201,210 |   | 649,605 |   | 596,694 |   | 737,358 |   |
| Producing properties                                                      |       | 208,127                                    |       | 617,697 |   | 1,148,306 |   | 1,340,827 |   | 1,762,206 |   |
| Gathering systems and facilities                                          |       | 40,247                                     |       | 133,917 |   | 179,836 |   | 185,688 |   | 85,404 |   |
| Other property and equipment                                              |       | 1,068                                      |       | 1,440 |   | 3,113 |   | 3,302 |   | 5,975 |   |
|                                                                      |       | 310,749                                    |       | 954,264 |   | 1,980,860 |   | 2,126,511 |   | 2,590,943 |   |
| Less accumulated depletion, depreciation, and   amortization              |       | (8,208                                     | )          | (58,299 | ) | (183,145 | ) | (322,992 | ) | (431,181 | ) |
| Property and equipment, net                                               |       | 302,541                                    |       | 895,965 |   | 1,797,715 |   | 1,803,519 |   | 2,159,762 |   |
| Other assets                                                              |       | 920                                        |       | 8,058 |   | 27,084 |   | 38,203 |   | 169,620 |   |
| Total assets                                                              |       | $                                          | 340,442    |   | $ | 979,282 |   | $ | 2,028,967 |   | $ | 1,936,566 |   | $ | 2,486,287 |   |
| Current liabilities                                                       |       | $                                          | 78,258     |   | $ | 165,091 |   | $ | 208,209 |   | $ | 112,493 |   | 152,483 |   |
| Long-term indebtedness                                                    |       | 83,897                                     |       | 415,659 |   | 622,734 |   | 515,499 |   | 652,632 |   |
| Other long-term liabilities                                               |       | 859                                        |       | 4,230 |   | 20,469 |   | 9,467 |   | 86,185 |   |
| Total equity                                                              |       | 177,428                                    |       | 394,302 |   | 1,177,555 |   | 1,299,107 |   | 1,594,987 |   |
| Total liabilities and equity                                              |       | $                                          | 340,442    |   | $ | 979,282 |   | $ | 2,028,967 |   | $ | 1,936,566 |   | $ | 2,486,287 |   |
| **Other financial data:**                                                 |       |                                       |       |   |   |   |   |   |   |   |   |
| EBITDAX(1)                                                                |       | $                                          | (629       | ) | $ | 59,980 |   | $ | 208,513 |   | $ | 201,270 |   | $ | 197,678 |   |
| Net cash provided by (used in) operating   activities                     |       | (18,101                                    | )          | 24,745 |   | 157,515 |   | $ | 149,307 |   | 125,791 |   |
| Net cash used in investing activities                                     |       | (158,265                                   | )          | (600,902 | ) | (1,004,010 | ) | (281,899 | ) | (228,672 | ) |
| Net cash provided by financing activities                                 |       | 178,311                                    |       | 585,326 |   | 874,350 |   | 104,292 |   | 101,200 |   |
| Capital expenditures(2)                                                   |       | 367,019                                    |       | 646,469 |   | 1,041,748 |   | 203,454 |   | 423,002 |   |

 

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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, expenses related to business acquisition, gain on sale of midstream 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

 

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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 indenture governing the 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 to EBITDAX for the periods presented:

 
| ** **                                                    | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands)**                                       | ** ** | **2006**                                   | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
| Net income (loss)                                             |       | $                                          | (8,983     | ) | $ | (37,753 | ) | $ | 83,956 |   | $ | (106,169 | ) | $ | 228,628 |   |
| Unrealized (gains) losses on commodity derivative   contracts |       | (18,656                                    | )          | (4,619 | ) | (90,301 | ) | 61,186 |   | (170,571 | ) |
| Gain on sale of Oklahoma midstream assets                     |       | —                                     |       | — |   | — |   | — |   | (147,559 | ) |
| Interest expense and other                                    |       | 1,366                                      |       | 28,157 |   | 52,839 |   | 41,038 |   | 59,140 |   |
| Provision (benefit) for income taxes                          |       | 400                                        |       | (400 | ) | 3,029 |   | (2,605 | ) | 30,009 |   |
| Depreciation, depletion, amortization and   accretion         |       | 7,949                                      |       | 50,159 |   | 124,997 |   | 140,078 |   | 134,272 |   |
| Impairment of unproved properties                             |       | 8,117                                      |       | 4,995 |   | 10,112 |   | 54,204 |   | 35,859 |   |
| Exploration expense                                           |       | 8,832                                      |       | 17,970 |   | 22,998 |   | 10,228 |   | 24,794 |   |
| Other                                                         |       | 346                                        |       | 1,471 |   | 883 |   | 3,310 |   | 3,106 |   |
| EBITDAX                                                       |       | $                                          | (629       | ) | $ | 59,980 |   | $ | 208,513 |   | $ | 201,270 |   | $ | 197,678 |   |

 

(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 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.*

 

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

 

**Overview**

 

**Our Company**

 

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

 

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 existing acreage.  As of December 31, 2010, our estimated proved reserves were 3,231 Bcfe, consisting of 2,544 Bcf of natural gas, 104 MMBbl of NGLs, and 10 MMBbl of oil.  As of December 31, 2010, 79% of our proved reserves were natural gas, 14% were proved developed and 87% were operated by us.  From December 31, 2006 through December 31, 2010, we grew our estimated proved reserves from 87 Bcfe to 3,231 Bcfe.  In addition, we grew our average daily production from 31 MMcfe/d for the year ended December 31, 2007 to 133 MMcfe/d for the year ended December 31, 2010.  For the year ended December 31, 2010, we generated cash flow from operations of $125.8 million, net income of $230.2 million and EBITDAX of $197.7 million.  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 a repeatable drilling opportunities.  Our drilling opportunities are focused in the Marcellus Shale of the Appalachian Basin, the Woodford Shale of the Arkoma Basin (the Arkoma Woodford), the Fayetteville Shale of the Arkoma Basin, the Mesaverde tight sands, and the Mancos Shale and Niobrara Shale of the Piceance Basin.  From inception, we have drilled and operated 380 wells through December 31, 2010 with a success

 

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rate of approximately 97%.  Our drilling inventory consists of approximately 15,000 potential well locations, all of which are unconventional resource opportunities.  For information on the possible limitations on our ability to drill our potential locations, see “Item 1A.  Risk Factors.

 

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

 

On November 4, 2010, we entered into an amended and restated senior secured revolving credit agreement (Credit Facility) with our lenders increasing the maximum amount of our Credit Facility from $400 million to $1 billion.  Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved reserves and are subject to semiannual redeterminations.  The initial borrowing base was set at $550 million.  The next semiannual redetermination of the borrowing base is scheduled to occur in April 2011.  At December 31, 2010, we had approximately $432 million of available borrowing capacity under the Credit Facility.

 

On November 5, 2010, we sold our Oklahoma midstream assets and received approximately $259 million of net cash proceeds from the sale and realized a gain of approximately $148 million.  We used the proceeds to pay down advances on our Credit Facility and thereby increase availability on our Credit Facility for working capital, drilling activities and property acquisitions.  We entered into long-term contracts with the purchaser of the midstream assets to continue to gather and process the Company’s Oklahoma gas production.  The terms of the Antero Resources LLC limited liability company operating agreement require us to make distributions sufficient to cover the members’ tax liabilities for taxable gains that are allocated to the members.  As a result of the gain on the sale of the midstream assets, we distributed $28.9 million to the members subsequent to December 31, 2010.

 

On December 1, 2010, we acquired 100% of the partnership interests in Bluestone Energy Partners, a general partnership which owned leasehold rights in approximately 37,250 acres in the Appalachian Basin in West Virginia and Pennsylvania and 96 producing wells.  The leasehold interests are in the same proximity and adjacent to the Company’s existing holdings in the area.  The consideration included approximately $96 million of cash, the assumption of  a $25 million note,  and  3,814,392 newly issued I-5 and B-6 units in Antero Resources LLC having an aggregate fair value of $97 million.

 

During the year ended December 31, 2010, we incurred approximately $332 million of capital expenditures for exploration and development of natural gas and oil properties.  Capital expenditures for exploration and development were allocated 48% to our Marcellus shale project in the Appalachian basin 33% to the Arkoma basin, and 19% to the Piceance Basin. Total capital expenditures during the year ended December 31, 2010, including exploration and development, leasehold acquisition, and gathering systems, were $423 million.  Our board of directors has approved a capital expenditure budget of up to $559 million for 2011 which includes $452 million for drilling and completion $65 million for leasehold acquisitions, and $42 million for construction of gathering pipelines and facilities. Approximately 73% of the budget is allocated to the Marcellus Shale, 14% is allocated to the Woodford Shale and Fayetteville Shale, and 13% is allocated to the Piceance Basin.  Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, commodity prices and drilling results.

 

During 2010, the Company continued its program to hedge part of its future natural gas sales.  At December 31, 2010, the Company has hedged a portion of its production through December 31, 2015 with commodity swaps covering approximately 263 Bcf of production from January 1, 2011 through December 31, 2015 at a weighted average index price of $6.14 per Mcf.  For 2011, we have hedged approximately 58.9 Bcfe of our production at a weighted average index price of $6.04 per Mcfe.

 

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

 

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**Source of Our Revenues**

 

Our production revenues are entirely from the continental United States and currently are comprised of approximately 96% natural gas and 4% oil. Natural gas and oil prices are inherently volatile and are influenced by many factors outside of our control. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a significant portion of our natural gas production. We currently use fixed price natural gas swaps in which we receive a fixed price for future production in exchange for a payment of the variable market price received at the time future production is sold. At each period end we estimate the fair value of these swaps and recognize an unrealized gain or loss. We have not elected hedge accounting and, accordingly, the unrealized gains and losses on open positions are reflected currently in earnings. During the years ended December 31, 2008, 2009 and 2010, we recognized significant unrealized commodity gains or losses on these swaps.  We expect continued volatility in the fair value of these swaps.

 

**Principal Components of Our Cost Structure**

 

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

 

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

 

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

 

·                  *Impairment of unproved and proved properties*.  These costs include unproved property impairment and costs associated with lease expirations. We could also record impairment charges for proved properties if the carrying value were to exceed estimated future cash flows. Through December 31, 2010, it has not been necessary to record any impairment for proved properties.

 

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

 

·                  *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 are included in general and administrative expenses.

 

·                  *Interest expense*.  We finance a portion of our working capital requirements and acquisitions with borrowings under our senior revolving credit facility. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We also have fixed interest at 9.375% on the senior notes having a principal balance of $525 million. We will likely continue to incur significant interest expense as we continue to grow. We have also entered into variable to fixed interest rate swaps to mitigate the effects of interest rate changes. We do not designate these swaps as hedges and therefore do not accord them hedge accounting treatment. Realized and unrealized gains or losses on these interest rate derivative instruments are included as a separate line item in other income (expense).

 

·                  *Income tax expense*.  Each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. We are subject to state and federal income taxes but are currently not in a tax paying

 

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position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income or franchise taxes where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis. Collectively, the operating entities have generated net operating loss carryforwards which expire at various dates from 2024 through 2030. We have not recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will not realize a future benefit equal to the full amount of the loss carryforward over time. The amount of deferred tax assets considered realizable, however, could change in the near term as we generate taxable income or estimates of future taxable income are reduced.

 

**Results of Operations**

 

***Year Ended December 31, 2009 Compared to Year Ended December 31, 2010***

 

The following table sets forth selected operating data for the year ended December 31, 2009 compared to the year ended December 31, 2010:

 
| ** **                                                                 | ** ** | **Year Ended December 31,** | ** ** |
|----------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands, except per unit data)**          | ** ** | **2009**                                   | ** ** | **2010** | ** ** | **Amount of   Increase   (Decrease)** | ** ** | **Percent   Change** | ** ** |
| **Operating revenues:**                                                    |       |                                       |       |   |   |   |   |   |   |
| Natural gas sales                                                          |       | $                                          | 123,915    |   | 197,991 |   | 74,076 |   | 60 | % |
| Oil sales                                                                  |       | 5,706                                      |       | 8,471 |   | 2,765 |   | 48 | % |
| Realized commodity derivative gains                                        |       | 116,550                                    |       | 73,713 |   | (42,837 | ) | (37 | )% |
| Unrealized commodity derivative gains (losses)                             |       | (61,186                                    | )          | 170,571 |   | 231,757 |   |   | * |
| Gathering and processing revenue                                           |       | 23,005                                     |       | 20,554 |   | (2,451 | ) | (11 | )% |
| Gain on sale of Oklahoma midstream assets                                  |       | —                                     |       | 147,559 |   | 147,559 |   |   | * |
| Total operating revenues                                                   |       | 207,990                                    |       | 618,859 |   | 410,869 |   | 198 | % |
| **Operating expenses:**                                                    |       |                                       |       |   |   |   |   |   |   |
| Lease operating expenses                                                   |       | 17,606                                     |       | 25,511 |   | 7,905 |   | 45 | % |
| Gathering, compression and transportation                                  |       | 28,190                                     |       | 45,809 |   | 17,619 |   | 63 | % |
| Production taxes                                                           |       | 4,940                                      |       | 8,777 |   | 3,837 |   | 78 | % |
| Exploration expenses                                                       |       | 10,228                                     |       | 24,794 |   | 14,566 |   | 142 | % |
| Impairment of unproved properties                                          |       | 54,204                                     |       | 35,859 |   | (18,345 | ) | (34 | )% |
| Depletion, depreciation and amortization                                   |       | 139,813                                    |       | 133,955 |   | (5,858 | ) | (4 | )% |
| Accretion of asset retirement obligations                                  |       | 265                                        |       | 317 |   | 52 |   | 20 | % |
| Expenses related to acquisition of business                                |       | —                                     |       | 2,544 |   | 2,544 |   |   | * |
| General and administrative                                                 |       | 20,843                                     |       | 21,952 |   | 1,109 |   | 5 | % |
| Total operating expenses                                                   |       | 276,089                                    |       | 299,518 |   | 23,429 |   | 8 | % |
| Operating income (loss)                                                    |       | (68,099                                    | )          | 319,341 |   | 387,440 |   |   | * |
| **Other income (expense):**                                                |       |                                       |       |   |   |   |   |   |   |
| Interest expense                                                           |       | (36,053                                    | )          | (56,463 | ) | (20,410 | ) | 57 | % |
| Realized and unrealized interest rate derivative   losses                  |       | (4,985                                     | )          | (2,677 | ) | 2,308 |   | (46 | )% |
| Total other expense                                                        |       | (41,038                                    | )          | (59,140 | ) | (18,102 | ) | 44 | % |
| Income (loss) before income taxes                                          |       | (109,137                                   | )          | 260,201 |   | 369,338 |   |   | * |
| Income tax (expense) benefit                                               |       | 2,605                                      |       | (30,009 | ) | (32,614 | ) |   | * |
| Net income (loss)                                                          |       | (106,532                                   | )          | 230,192 |   | 336,724 |   |   | * |
| Non-controlling interest in net loss (income) of   consolidated subsidiary |       | 363                                        |       | (1,564 | ) | (1,927 | ) |   | * |
| Net income (loss) attributable to Antero equity   owners                   |       | $                                          | (106,169   | ) | 228,628 |   | 334,797 |   |   | * |
| **Production data:**                                                       |       |                                       |       |   |   |   |   |   |   |
| Natural gas (Bcf)                                                          |       | 35.1                                       |       | 45.8 |   | 10.7 |   | 30 | % |
| Oil (MBbl)                                                                 |       | 114.0                                      |       | 127.5 |   | 13.5 |   | 12 | % |
| NGLs (MBbl)(1)                                                             |       | 433.3                                      |       | 333.3 |   | (100.0 | ) | (23 | )% |
| Combined (Bcfe)                                                            |       | 38.4                                       |       | 48.6 |   | 10.2 |   | 27 | % |

 

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| ** **                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands, except per unit data)** | ** ** | **2009**                                   | ** ** | **2010** | ** ** | **Amount of   Increase   (Decrease)** | ** ** | **Percent   Change** | ** ** |
| Daily combined production (MMcfe/d)                               |       | 105.2                                      |       | 133.1 |   | 27.9 |   | 27 | % |
| **Average prices before effects   of hedges(2):**                 |       |                                       |       |   |   |   |   |   |   |
| Natural gas (per Mcf)                                             |       | $                                          | 3.53       |   | 4.32 |   | .79 |   | 22 | % |
| Oil (per Bbl)                                                     |       | $                                          | 50.05      |   | 66.44 |   | 16.39 |   | 33 | % |
| NGLs                                                              |       | $                                          | 31.20      |   | 45.12 |   | 13.92 |   | 45 | % |
| Combined (per Mcfe)                                               |       | $                                          | 3.62       |   | 4.43 |   | 0.81 |   | 22 | % |
| **Average realized prices   after-effects of hedges(2):**         |       |                                       |       |   |   |   |   |   |   |
| Natural gas (per Mcf)                                             |       | $                                          | 6.85       |   | 5.93 |   | (0.92 | ) | (13 | )% |
| Oil (per Bbl)                                                     |       | $                                          | 50.05      |   | 66.44 |   | 16.39 |   | 33 | % |
| NGLs                                                              |       | $                                          | 31.20      |   | 45.12 |   | 13.92 |   | 45 | % |
| Combined (per Mcfe)                                               |       | $                                          | 6.88       |   | 6.02 |   | (0.86 | ) | (13 | )% |
| **Average costs (per Mcfe) (2):**                                 |       |                                       |       |   |   |   |   |   |   |
| Lease operating costs                                             |       | $                                          | 0.49       |   | 0.55 |   | 0.06 |   | 12 | % |
| Gathering, compression and transportation                         |       | $                                          | 0.79       |   | 0.98 |   | 0.19 |   | 24 | % |
| Production taxes                                                  |       | $                                          | 0.14       |   | 0.19 |   | 0.05 |   | 36 | % |
| Depletion, depreciation, amortization                             |       | $                                          | 3.91       |   | 2.88 |   | (1.03 | ) | (26 | )% |
| General and administrative                                        |       | $                                          | 0.58       |   | 0.47 |   | (0.11 | ) | (19 | )% |

 

----

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

 

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

 

*                Not meaningful or applicable.

 

*Natural gas and oil sales*. Revenues from production of natural gas and oil increased from $129.6 million for the year ended December 31, 2009 to $206.5 million for the year ended December 31, 2010, an increase of $76.9 million or 59%. Our production increased by 30% from 35.8 Bcfe in 2008 to 46.6 Bcfe in 2010. The net increase in revenues resulted from both commodity price and production volume increases. Price increases accounted for a $37.8 million increase in revenues (calculated as the increase in year-to-year average price times current year production volumes). Increased production volumes increased revenues by $39.0 million (calculated as the increase in year-to-year volumes times the prior year average price). The following table sets forth additional information concerning our production volumes for the years ended December 31, 2009 and 2010:

 
| ** **      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------|------------|--------------------------------------------|------------|
| **(Bcfe)**      | ** ** | **2009**                                   | ** ** | **2010** | ** ** | **Percent   Change** | ** ** |
| Arkoma Woodford |       | 23.6                                       |       | 23.9 |   | 1 | % |
| Piceance Basin  |       | 11.7                                       |       | 11.9 |   | 2 | % |
| Appalachia      |       | 0.5                                        |       | 10.8 |   | 2060 | % |
| Total           |       | 35.8                                       |       | 46.6 |   | 30 | % |

 

*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

 

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agreements as the future strip prices fluctuate from the fixed price we will receive on future production. For the years ended December 31, 2009 and 2010, our hedges resulted in realized gains of $116.5 million and $73.7 million, respectively. For the years ended December 31, 2009 and 2010, our hedges resulted in unrealized losses of $(61.2) million and unrealized gains of $170.6 million, respectively. During 2009, we had realized gains as hedge contracts matured and prices began to recover, and unrealized losses as unrealized gains recorded in 2008 reversed.  Unrealized gains in 2010 resulted from commodity prices at December 31, 2010 below our open commodity swap prices, net of unrealized losses resulting from the reversal of unrealized gains recorded at the end of the previous year.

 

*Gathering and processing revenues*.  Gathering and processing revenues decreased from $23.0 million for the year ended December 31, 2009 to $20.6 million for 2010 because of the sale of our Oklahoma midstream operations effective November 5, 2010.   Gathering and processing revenues are expected to be minimal in the future because of the sale of the Oklahoma midstream operations.

 

*Gain on sale of Oklahoma midstream assets*.  On November 5, 2010, the Company completed the sale of its Oklahoma midstream assets for strategic reasons.  The Company received net cash proceeds from the sale of approximately $258.9 million and recognized a gain on the sale of approximately $147.6 million.  The terms of the Antero Resources LLC limited liability company agreement require us to make distributions sufficient to cover the members’ tax liabilities for taxable transactions that are allocated to the members.  As a result of the gain on the sale of the midstream assets, we distributed $28.9 million to the members subsequent to December 31, 2010.  The Company entered into a contract with the purchaser of the assets to continue to gather and process the Company’s Oklahoma gas production.

 

*Lease operating expenses*. Lease operating expenses increased from $17.6 million for the year ended December 31, 2009 to $25.5 million in 2010, an increase of $7.9 million, or 45%. Lease operating expenses in the Arkoma and Piceance Basins increased primarily because of an increase in workover expenses of approximately $7.6 million and new wells brought online in 2010. Workover expenses increased due primarily to tubing replacement costs in the Piceance and mechanical issues with certain Arkoma wells. Lease operating expenses increased by $1.2 million in the Appalachian Basin as production increased in 2010 from minimal levels in 2009. The following table displays the lease operating expense per Mcfe by basin for the years ended December 31, 2009 and 2010:

 
| ** **                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                        | ** ** | **2009**                                   | ** ** | **,2010** | ** ** |
| **(in thousands, except per Mcfe data)** | ** ** | **Amount**                                 | ** ** | **Per Mcfe** | ** ** | **Amount** | ** ** | **Per Mcfe** | ** ** |
| Arkoma Woodford                                                   |       | $                                          | 5,336      |   | $ | 0.23 |   | $ | 9,664 |   | $ | 0.41 |   |
| Piceance Basin                                                    |       | 12,242                                     |       | $ | 1.04 |   | 14,690 |   | $ | 1.23 |   |
| Appalachia                                                        |       | 28                                         |       | $ | 0.06 |   | 1,157 |   | $ | 0.11 |   |
| Total lease operating expense                                     |       | $                                          | 17,606     |   | $ | 0.49 |   | $ | 25,511 |   | $ | 0.55 |   |

 

*Gathering, compression and transportation expense*.  Gathering, compression and transportation expense increased from $28.2 million for the year ended December 31, 2009 to $45.8 million in 2010. Gathering expenses increased by $7.9 million due to the commencement of significant production in the Appalachian Basin.  The remainder of the increase is primarily due to increased firm commitments in the Arkoma and Piceance Basins.  On a per-Mcfe basis, these expenses increased from $0.79 per Mcfe for 2009 to $0.98 per Mcfe for 2010.

 

*Production tax expense*.  Total production taxes increased from $4.9 million for the year ended December 31, 2009 to $8.7 million for the year ended December 31, 2010, primarily as a result of increased production and increased natural gas and oil prices. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 4.5% for the year ended December 31, 2009 compared to 4.2% for the year ended December 31, 2010. Production taxes are primarily based on the wellhead values of production and the applicable rates vary across the areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

 

*Exploration expense*.  Exploration expense increased from $10.2 million for the year ended December 31, 2009 to $24.8 million for the year ended December 31, 2010, an increase of $14.6 million. The increase was due to an

 

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increase in dry hole expense of $17.8 million, partially offset by a decrease in standby rig costs of $5.0 million and other net increases of $1.8 million.  The increase in dry hole costs in 2010 from 2009 resulted primarily from four  exploratory wells drilled with non-commercial results in the Piceance Basin.

 

*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 $54.2 million for the year ended December 31, 2009 to $35.9 million for the year ended December 31, 2010.  In 2009, we impaired certain leaseholds within our Ardmore and Arkoma Basin acreage which expired at various dates through December 31, 2010 and which we did not intend to renew or drill. We continued to take charges for impairment of certain Arkoma and Piceance acreage in 2010. The amount of acreage to evaluate for impairment in the Arkoma Basin is decreasing because of the significant previous impairment charges taken.

 

*Depreciation, depletion and amortization (DD&A)*.  DD&A decreased from $139.8 million for the year ended December 31, 2009 to $134.0 million for the year ended December 31, 2010, a decrease of $5.8 million, primarily as a result of increased estimates of reserve volumes for 2010 compared to 2009. DD&A per Mcfe decreased from $3.91 per Mcfe for 2009 to $2.88 per Mcfe for 2010.

 

As a successful efforts company, we evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. There were no impairment expenses recorded for the years ended December 31, 2009 or 2010 for proved properties. We had $78.9 million of exploratory well costs at December 31, 2010 included in natural gas and oil properties pending determination of whether proved reserves could be assigned to these well costs.  These costs relate to wells-in-progress which have not been completed as of December 31, 2010.  As of December 31, 2010, no significant well costs have been deferred for over one year pending proved reserves determination.

 

*General and administrative expense*.  General and administrative expense increased from $20.8 million for the year ended December 31, 2009 to $22.0 million for 2010, an increase of $1.2 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 $0.58 per Mcfe for the year ended December 31, 2009 to $0.47 per Mcfe for 2010.

 

*Interest expense and realized and unrealized gains and losses on interest rate derivatives*.  Interest expense increased from $36.1 million for the year ended December 31, 2009 to $56.5 million for 2010, an increase of $20.4 million, primarily as a result of the issuance of $525.0 million of 9.375% senior notes in November 2009 and January 2010.  The fixed interest rate on these senior notes is significantly higher than the Libor-based floating rate we had been paying on our bank credit facility borrowings and on our second lien debt facility (which was repaid in full with the net proceeds of the November 2009 senior notes offering).

 

We have entered into variable-to-fixed interest rate swap agreements that hedge our exposure to interest rate variations on our senior secured revolving credit facility and second lien term loan facility. At December 31, 2010, one of these swaps remains outstanding with a notional amount of $225.0 million and a fixed pay rate of 4.11%.  This swap expires in July 2011.  For the year ended December 31, 2010, we realized a loss on interest rate swap agreements of $9.6 million, whereas in 2009 we had a realized loss on interest rate swap agreements of $11.1 million. At December 31, 2010, the estimated fair value of the outstanding interest rate swap agreements was a liability of $4.2 million, which is included in current liabilities. The outstanding interest rate swap agreement related to the $225 million second lien term loan facility which was repaid in November 2009; therefore, it is not associated with any floating rate debt.

 

*Income tax expense*.  Income tax expense reflects the fact that each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. 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

 

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by the members of the LLC through the allocation of taxable income.  Accordingly, no taxes were accrued on the gain of $147.6 million on the sale of the midstream operations in 2010.  In general, none of the operating entities have 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. Accordingly, valuation allowances have generally been established against net operating loss carryforwards (NOLs) to the extent that such NOLs exceed net deferred tax liabilities. During the year ended December 31, 2010, we recognized a tax benefit to the extent of existing deferred tax liabilities. We have not recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will not realize a future benefit for the full amount of the loss carryforwards over time. Net income tax expense in 2009 and 2010 reflects the net deferred tax liabilities related to unrealized derivative gains, which were partially offset by decreases in the valuation allowance.  At December 31, 2010, the operating entities had a combined total of approximately $509 million of NOLs, which expire at various dates from 2024 through 2030. Congress recently proposed legislation that would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that legislation is enacted.

 

***Year Ended December 31, 2008 Compared to Year Ended December 31, 2009***

 

The following table sets forth selected operating data for the year ended December 31, 2008 compared to the year ended December 31, 2009:

 
| ** **                                                        | ** ** | **Year Ended   December 31,** | ** ** | **Amount of   Increase** | ** ** | **Percent**    | ** ** |
|-------------------------------------------------------------------|------------|-----------------------------------------|------------|-------------------------------|------------|----------------|------------|
| **(in thousands, except per unit data)** | ** ** | **2008**                                | ** ** | **2009**                      | ** ** | **(Decrease)** | ** ** | **Change** | ** ** |
| **Operating revenues:**                                           |       |                                    |       |                          |       |           |       |   |   |
| Natural gas sales                                                 |       | $                                       | 220,219    |                          | $          | 123,915        |       | $ | (96,304 | ) | (43.7 | )% |
| Oil sales                                                         |       | 9,496                                   |       | 5,706                         |       | (3,790         | )          | (39.9 | )% |
| Realized commodity derivative gains                               |       | 26,053                                  |       | 116,550                       |       | 90,497         |       | 347.3 | % |
| Unrealized commodity derivative gains (losses)                    |       | 90,301                                  |       | (61,186                       | )          | (151,487       | )          |   | * |
| Gathering and processing revenue                                  |       | 20,421                                  |       | 23,005                        |       | 2,584          |       | 12.7 | % |
| Total operating revenues                                          |       | 366,490                                 |       | 207,990                       |       | (158,500       | )          | (43.2 | )% |
| **Operating expenses:**                                           |       |                                    |       |                          |       |           |       |   |   |
| Lease operating expenses                                          |       | 13,350                                  |       | 17,606                        |       | 4,256          |       | 31.9 | % |
| Gathering compression and transportation                          |       | 29,033                                  |       | 28,190                        |       | (843           | )          | (2.9 | )% |
| Production taxes                                                  |       | 10,281                                  |       | 4,940                         |       | (5,341         | )          | (52.0 | )% |
| Exploration                                                       |       | 22,998                                  |       | 10,228                        |       | (12,770        | )          | (55.5 | )% |
| Impairment of unproved properties expense                         |       | 10,112                                  |       | 54,204                        |       | 44,092         |       | 436.0 | % |
| Depletion depreciation and amortization                           |       | 124,821                                 |       | 139,813                       |       | 14,992         |       | 12.0 | % |
| Accretion of asset retirement obligations                         |       | 176                                     |       | 265                           |       | 89             |       | 50.6 | % |
| General and administrative expense                                |       | 16,171                                  |       | 20,843                        |       | 4,672          |       | 28.9 | % |
| Total operating expenses                                          |       | 226,942                                 |       | 276,089                       |       | 49,147         |       | 21.7 | % |
| Operating income (loss)                                           |       | 139,548                                 |       | (68,099                       | )          | (207,647       | )          |   | * |
| **Other income expense:**                                         |       |                                    |       |                          |       |           |       |   |   |
| Interest expense                                                  |       | $                                       | (37,594    | )                             | $          | (36,053        | )          | $ | (1,541 | ) | (4.1 | )% |
| Realized and unrealized interest rate derivative   gains (losses) |       | (15,245                                 | )          | (4,985                        | )          | (10,260        | )          | (67.3 | )% |
| Total other expense                                               |       | (52,839                                 | )          | (41,038                       | )          | (11,801        | )          | (22.3 | )% |
| Income (loss) before income taxes                                 |       | 86,709                                  |       | (109,137                      | )          | (195,846       | )          |   | * |
| Income taxes (expense) benefit                                    |       | (3,029                                  | )          | 2,605                         |       | 5,634          |       |   | * |
| Net income (loss)                                                 |       | 83,680                                  |       | (106,532                      | )          | (190,012       | )          |   | * |
| Non-controlling interest in net loss of   consolidated subsidiary |       | 276                                     |       | 363                           |       | 87             |       |   | * |
| Net income (loss) attributable to Antero equity   owners          |       | $                                       | 83,956     |                          | $          | (106,169       | )          | $ | (190,125 | ) |   | * |
| **Production data:**                                              |       |                                    |       |                          |       |           |       |   |   |
| Natural gas (Bcf)                                                 |       | 30.3                                    |       | 35.1                          |       | 4.8            |       | 15.8 | % |
| Oil (MBbl)                                                        |       | 114.9                                   |       | 114.0                         |       | 0.9            |       | (0.8 | )% |
| NGLs (MBbl)(1)                                                    |       | 150.0                                   |       | 433.3                         |       | 283.3          |       | 188.9 | % |

 

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| ** **                                                        | ** ** | **Year Ended   December 31,** | ** ** | **Amount of   Increase** | ** ** | **Percent**    | ** ** |
|-------------------------------------------------------------------|------------|-----------------------------------------|------------|-------------------------------|------------|----------------|------------|
| **(in thousands, except per unit data)** | ** ** | **2008**                                | ** ** | **2009**                      | ** ** | **(Decrease)** | ** ** | **Change** | ** ** |
| Combined (Bcfe)                                                   |       | 31.9                                    |       | 38.4                          |       | 6.5            |       | 20.4 | % |
| Daily combined production (MMcfe/d)                               |       | 87.4                                    |       | 105.2                         |       | 17.8           |       | 20.4 | % |
| **Average prices before effects   of hedges(2):**                 |       |                                    |       |                          |       |           |       |   |   |
| Natural gas (per Mcf)                                             |       | $                                       | 7.27       |                          | 3.53       |           | (3.74      | ) | (51.4 | )% |
| Oil (per Bbl)                                                     |       | $                                       | 82.65      |                          | 50.05      |           | (32.60     | ) | (39.4 | )% |
| Combined (per Mcfe)                                               |       | $                                       | 7.41       |                          | 3.62       |           | (3.79      | ) | (51.1 | )% |
| **Average realized prices   after-effects of hedges(2):**         |       |                                    |       |                          |       |           |       |   |   |
| Natural gas (per Mcf)                                             |       | $                                       | 8.13       |                          | 6.85       |           | (1.28      | ) | (15.7 | )% |
| Oil (per Bbl)                                                     |       | $                                       | 82.65      |                          | 50.05      |           | (32.60     | ) | (39.4 | )% |
| Combined (per Mcfe)                                               |       | $                                       | 8.25       |                          | 6.88       |           | (1.37      | ) | (16.6 | )% |
| **Average Costs (per Mcfe):**                                     |       |                                    |       |                          |       |           |       |   |   |
| Lease operating costs                                             |       | $                                       | 0.43       |                          | 0.49       |           | 0.06       |   | 14.0 | % |
| Gathering compression and transportation                          |       | $                                       | 0.94       |                          | 0.79       |           | (0.15      | ) | (16.0 | )% |
| Production taxes                                                  |       | $                                       | 0.33       |                          | 0.14       |           | (0.19      | ) | (57.6 | )% |
| Depletion depreciation amortization and accretion                 |       | $                                       | 4.03       |                          | 3.91       |           | (0.12      | ) | (3.0 | )% |
| General and administrative                                        |       | $                                       | 0.52       |                          | 0.58       |           | 0.06       |   | 11.5 | % |

 

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

 

(2)         Average prices shown in the table reflect both of the before-and-after-effects of our realized commodity hedging transactions. Our calculation of such after-effects includes realized gains or losses on cash settlements for commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes. Oil production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

 

*                 Not meaningful or applicable

 

*Natural gas and oil sales*. Revenues from production of natural gas and oil decreased from $229.7 million for the year ended December 31, 2008 to $129.6 million for the year ended December 31, 2009, a decrease of $100.1 million or 43.6%. Our production increased by 15.5% from 31.0 Bcfe in 2008 to 35.8 Bcfe in 2009. The net decrease in revenues resulted from commodity price declines which accounted for a $135.7 million decrease (calculated as the decrease in year-to-year average price times current year production volumes) in revenues as partially offset by increased production volumes which increased revenues by $35.6 million (calculated as the increase in year-to-year volumes times the prior year average price). Realized gains from our commodity hedging contracts partially offset the effect of these price declines by $116.5 million. The following table sets forth additional information concerning our production volumes for the years ended December 31, 2008 and 2009:

 
| ** **      | ** ** | **Year Ended December 31,** | ** ** |
|-----------------|------------|--------------------------------------------|------------|
| **(Bcfe)**      | ** ** | **2008**                                   | ** ** | **2009** | ** ** | **Percent   Change** | ** ** |
| Arkoma Woodford |       | 18.7                                       |       | 23.6 |   | 26.2 | % |
| Piceance Basin  |       | 12.3                                       |       | 11.7 |   | (4.8 | )% |
| Appalachia      |       | —                                     |       | 0.5 |   |   |   |
| Total           |       | 31.0                                       |       | 35.8 |   | 15.5 | % |

 

*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

 

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years ended December 31, 2008 and 2009, our hedges resulted in realized gains of $26.1 million and $116.5 million, respectively. For the years ended December 31, 2008 and 2009, our hedges resulted in unrealized gains of $90.3 million and unrealized losses of $(61.2) million, respectively. Unrealized gains in 2008 occurred as commodity prices began to fall below our fixed price swaps as a result of the weakening U.S. and global economy. During 2009, we realized part of these gains as our 2009 hedge contracts matured and prices began to recover thus partially reversing the unrealized gains recorded in 2008.

 

*Gathering and processing revenues*.  Gathering and processing revenues increased from $20.4 million for the year ended December 31, 2008 to $23.0 million for 2009 as our plants increased utilization and recoveries.

 

*Lease operating expenses*. Lease operating expenses increased from $13.4 million for the year ended December 31, 2008 to $17.6 million in 2009, an increase of 31.9%, primarily as a result of an increase in Arkoma Woodford production volumes and increased water disposal costs in the Piceance Basin. On a per-Mcfe basis, lease operating expenses increased in total from $0.43 per Mcfe in 2008 to $0.49 per Mcfe in 2009 because of the increase in Piceance costs vs. Arkoma costs. In August 2009, two water injection wells were completed in the Piceance Basin and we believe this will decrease future water disposal costs. The following table displays the lease operating expense per Mcfe by basin for the years ended December 31, 2008 and 2009:

 
| ** **                                                        | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                        | ** ** | **2008**                                   | ** ** | **2009** | ** ** |
| **(in thousands, except per Mcfe data)** | ** ** | **Amount**                                 | ** ** | **Per Mcfe** | ** ** | **Amount** | ** ** | **Per Mcfe** | ** ** |
| Arkoma Woodford                                                   |       | $                                          | 5,069      |   | $ | 0.27 |   | $ | 5,336 |   | $ | 0.23 |   |
| Piceance Basin                                                    |       | 8,281                                      |       |   | 0.68 |   | 12,242 |   |   | 1.04 |   |
| Appalachia                                                        |       | —                                     |       | — |   | 28 |   |   | 0.06 |   |
| Total lease operating expense                                     |       | $                                          | 13,350     |   | $ | 0.43 |   | $ | 17,606 |   | $ | 0.49 |   |

 

*Gathering, compression and transportation expense*.  Gathering, compression and transportation expense decreased from $29.0 million for the year ended December 31, 2008 to $28.2 million in 2009. On a per-Mcfe basis, these expenses decreased from $0.94 per Mcfe for 2008 to $0.79 per Mcfe for 2009 as gathering plant utilization increased and as production has increased in the Arkoma Basin as a proportion of our total production. Gathering expenses are less in the Arkoma Basin than in the Piceance Basin because of higher water production rates in the Piceance Basin.

 

*Production tax expense*.  Total production taxes decreased from $10.3 million for the year ended December 31, 2008 to $4.9 million for the year ended December 31, 2009, primarily as a result of a decrease in natural gas and oil prices. Production taxes as a percentage of natural gas and oil revenues before the effects of hedging were 3.8% for the year ended December 31, 2009 compared to 4.5% for the year ended December 31, 2008. Production taxes are primarily based on the wellhead values of production and the applicable rates vary across the areas in which we operate. As the proportion of our production changes from area to area, our production tax rate will vary depending on the quantities produced from each area and the applicable production tax rates then in effect.

 

*Exploration expense*.  Exploration expense decreased from $23.0 million for the year ended December 31, 2008 to $10.2 million for the year ended December 31, 2009. Exploration expense during 2009 primarily consisted of $1.0 million of seismic costs, $1.7 million in dry hole costs, $5.0 million of standby rig costs and $2.5 million of contract landman costs that did not result in leasehold acquisitions. Exploration expense for 2008 primarily consisted of $5.5 million for seismic programs in the Arkoma and Piceance areas, $6.6 million of dry hole costs, and $6.0 million in impairment of rig upgrades and $4.9 million of contract landman costs that did not result in leasehold acquisitions.

 

*Impairment of unproved properties*.  Our impairment of unproved property expense increased from $10.1 million for the year ended December 31, 2008 to $54.2 million for the year ended December 31, 2009, because we decided not renew or drill on certain leaseholds within our Ardmore and Arkoma Basin acreage which expired at various dates through December 31, 2010. 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 remaining lease terms, reservoir performance, commodity price outlooks or future plans to develop the acreage and recognize impairment costs accordingly.

 

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*Depreciation, depletion and amortization (DD&A)*.  DD&A increased from $124.8 million for year ended December 31, 2008 to $139.8 million for the year ended December 31, 2009, an increase of $15.0 million, primarily as a result of increased production for 2009 compared to 2008. DD&A per Mcfe decreased slightly from $4.03 per Mcfe during 2008 to $3.91 per Mcfe during 2009.

 

We evaluate the impairment of our proved natural gas and oil properties on a field-by-field basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we reduce the carrying amount of the oil and gas properties to their estimated fair value. There were no impairment expenses recorded for the years ended December 31, 2008 or 2009 for proved properties. We had $11.9 million of exploratory well costs at December 31, 2009 included in natural gas and oil properties pending determination of whether proved reserves could be assigned to these well costs. These costs result primarily from development activity in the Marcellus Shale. As of December 31, 2009, 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 $16.2 million for the year ended December 31, 2008 to $20.8 million during 2009, an increase of $4.6 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 increased from $0.52 per Mcfe during the year ended December 31, 2008 to $0.58 per Mcfe during 2009.

 

*Interest expense and realized and unrealized gains and losses on interest rate derivatives*.  Interest expense decreased from $37.6 million for the year ended December 31, 2008 to $36.1 million during 2009, a decrease of $1.5 million, primarily as a result of lower market interest rates in 2009. In November 2009, we issued $375.0 million of 9.375% senior notes, and in January 2010, we issued an additional $150.0 million of the same series of 9.375% senior notes.

 

During 2009, we had interest rate swaps outstanding for a notional amount of $426.0 million with fixed pay rates ranging from 2.79% to 4.11% and terms expiring from December 2009 through July 2011. During the year ended December 31, 2009, we realized a loss on interest rate swap agreements of $11.1 million; whereas, during 2008 we had a realized loss on interest rate swap agreements of $1.4 million. At December 31, 2009, the estimated fair value of our interest rate swap agreements was a liability of $11.1 million, which is included in current and long-term liabilities. As of December 31, 2009, we were in a liability position on our interest rate swaps because of the large decline in interest rates since having entered into the agreements.

 

*Income tax expense*.  Income tax expense reflects the fact that each of the operating entities files separate federal and state income tax returns; therefore, our provision for income taxes consists of the sum of our income tax provisions for each of the operating entities. In general, none of the operating entities have 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. Accordingly, valuation allowances have generally been established against net operating loss (NOLs) carryforwards to the extent that such NOLs exceed net deferred tax liabilities resulting in no income tax expense or benefit. During the year ended December 31, 2008, the operating entities had significant net income on a combined basis primarily related to unrealized derivative gains which are not taxable until realized. Net income tax expense in 2008 reflects the net deferred tax liabilities relating to these unrealized derivative gains which were partially offset by a decrease in the valuation allowance. During the year ended December 31, 2009, we recognized a tax benefit to the extent of existing deferred tax liabilities. We have not recognized the full value of these net operating losses on our balance sheets because our management team believes it is more likely than not that we will not realize a future benefit for the full amount of the loss carryforward over

 

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time. At December 31, 2009, the operating entities had a combined total of approximately $276 million of NOLs, which expire starting in 2024 and through 2029. Congress recently proposed legislation that would eliminate or limit future deductions for intangible drilling costs and could significantly affect our future taxable position. The impact of any change will be recorded in the period that legislation is enacted.

 

**Capital Resources and Liquidity**

 

Our primary sources of liquidity have been through issuances of equity securities, borrowings under bank credit facilities, issuance of debt securities, the sale of our Oklahoma midstream assets and net cash provided by operating activities. Our primary use of cash has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. We have approximately 15,000 potential well locations which will take many years to develop.  Additionally our proved undeveloped reserves will require an estimated $4.0 billion of development capital over the next five years.  A portion of this capital requirement will be funded out of operating cash flows. However, we would 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.

 

During 2009 and 2010, we have raised capital through the issuance of approximately $229 million of preferred equity in 2009 and the issuance of $525 million of 9.375% senior notes in November 2009 and January 2010.  In December 2010, we issued $97 million of equity units in Antero Resources LLC as partial consideration for the acquisition of Bluestone Energy Partners, which owns acreage in close proximity and adjacent to our Appalachian Basin acreage.  In November 2010, we also sold our Oklahoma midstream assets, generating net proceeds from the sale of approximately $259 million.  In November 2010, we also entered into an amended and restated senior revolving credit facility (Credit Facility) with our lenders, increasing the maximum amount of our revolving credit facility from $400 million to $1 billion.  Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved reserves and are subject to regular semiannual redeterminations.  The initial borrowing base was set at $550 million.  The next semiannual redetermination of the borrowing based is scheduled to occur in April 2011.  At December 31, 2010, we had approximately $432 million of available borrowing capacity under the Credit Facility.  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 13 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.

 

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

 

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

 

**Cash Flow Provided by Operating Activities**

 

Net cash provided by operating activities was $160.5 million, $149.3 million and $125.8 million for the years ended December 31, 2008, 2009 and 2010, respectively. The decrease in cash flow from operations from 2008 to 2009 was primarily the result of lower gas prices in 2009. The decrease in cash flow from operations for the year ended December 31, 2010 compared to 2009 was primarily the result of an increase in lease operating, gathering and processing, interest expense, and other expenses.

 

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for natural gas and oil production. Prices for these commodities are determined primarily by prevailing market conditions. 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

 

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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” included elsewhere in this report.

 

**Cash Flow Used in Investing Activities**

 

During the years ended December 31, 2008, 2009 and 2010, we used cash flows in investing activities of $1.0 billion, $281.9 million and $228.7 million, respectively, as a result of our capital expenditures for drilling, development and acquisitions.  The decrease in cash used in investing activities in 2009 from 2008 was a result of curtailed investment following the global financial crisis as well as the decline in oil and gas prices. The decrease in cash flows used in investing activities during the year ended December 31, 2010 compared to the prior year period is a result of the $258.9 million net cash proceeds from the sale of the midstream assets reducing cash used in investing activities.

 

Our capital expenditures for drilling, development, leasehold acquisition, gas gathering and other costs for the years ended December 31, 2008, 2009 and 2010 are summarized in the following table. Capital expenditures reflected in the table below differ from the amounts shown in the statements of cash flows in the financial statements because amounts reflected in the table include changes in accounts payable from the previous reporting period for capital expenditures, while the amounts in the statements of cash flows in the financial statements are presented on a cash basis.  The table does not include $261 million of costs allocated to property and equipment as a result of the business acquisition completed on December 1, 2010.

 
| **Capital Expenditures**             | ** ** | **Year Ended December 31,** | ** ** |
|-------------------------------------------|------------|--------------------------------------------|------------|
| **(in thousands)**                   | ** ** | **2008**                                   | ** ** | **2009** | ** ** | **2010** | ** ** |
| Arkoma Basin                              |       | $                                          | 335,516    |   | $ | 77,841 |   | $ | 116,787 |   |
| Piceance Basin                            |       | 297,285                                    |       | 51,250 |   | 74,424 |   |
| Appalachian Basin                         |       | 361,379                                    |       | 68,355 |   | 182,020 |   |
| Gas plant, gathering, pipeline, and other |       | 47,568                                     |       | 6,008 |   | 49,771 |   |
| Total capital expenditures                |       | $                                          | 1,041,748  |   | $ | 203,454 |   | $ | 423,002 |   |

 

Our board of directors has approved a capital budget of up to $559 million for 2011. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas and oil prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

 

**Cash Flow Provided by Financing Activities**

 

Net cash provided by financing activities in 2010 of $101.2 million was primarily a result of, (i) $156.0 million of cash provided by the issuance of senior notes, (ii) net payments of $42.1 million on our Credit Facility, and (iii) $12.7 million of other payment items including deferred financing costs.

 

Cash provided by financing activities in 2009 of $104.3 million was primarily the result of cash provided by, (i) the issuance of the senior notes (net of discounts and issuance costs) of $361 million, (ii) the issuance of preferred stock of $105.0 million, and (iii) the issuance of member units in Antero Resources LLC for $123.6 million (net of $1.4 million of issuance costs); net of cash applied to (i) net repayments on the bank credit facility of $254.5 million and (ii) the repayment of the second lien term loan facility of $225.0 million.  Net cash provided by financing activities of $874.4 million during the year ended December 31, 2008 was primarily the result of the issuance of $670.0 million of Series B preferred stock and $207.2 million of net borrowings under our senior secured revolving credit facility.

 

*Senior Secured Revolving Credit Facility*.  Our Credit Facility provides for a maximum borrowing base of $1.0 billion.  The borrowing base is redetermined semiannually and the borrowing base depends on the amount of our

 

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proved oil and gas reserves and estimated cash flows from these reserves and our hedge positions.  The next redetermination is scheduled to occur in April 2011.  As of December 31, 2010, we had a borrowing base of $550 million against which we had $118.1 million of outstanding borrowings and letters of credit.

 

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 175 to 275 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 an applicable margin ranging from 75 to 175 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 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, 2009 and 2010, borrowings and letters of credit outstanding under our senior secured revolving credit facility totaled $142.1 million and $ 118 million, respectively, and had a weighted average interest rate (excluding the impact of our interest rate swaps) of 2.36% and 2.56%, 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;

 

·                  enter into mergers;

 

·                  make certain payments to Antero Resources LLC;

 

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

 

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

 

*Senior Notes*.  We have $525 million of 9.375% senior notes outstanding which are due December 1, 2017.  The notes are unsecured and subordinate to the bank credit facility to the extent of the value of the collateral securing the bank credit facility.  The notes are guaranteed on a senior unsecured basis by Antero Resources LLC, all of its wholly owned subsidiaries (other than Antero Finance), and certain of its future restricted subsidiaries.  Interest on the notes is payable on June 1 and December 1 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

 

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“make-whole” premium.  If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders.

 

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

 

*Treasury Management Facility*.  On September 14, 2010, the Company executed a stand-alone revolving note with a lender under the senior credit facility which provides for up to $7.5 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. At December 31, 2010, there were no outstanding borrowings under this facility.

 

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

 

*Interest Rate Hedges*.  We have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our senior revolving credit facility and second lien term loan facility. At December 31, 2010, we had one interest rate swap outstanding for a notional amount of $225 million with a fixed pay rate of 4.11% with a term expiring in July 2011. During the years ended December 31, 2008, 2009 and 2010, we had realized losses on interest rate swap agreements of $1.4 million, $11.1 million and $9.6 million, respectively. At December 31, 2010, we had unrealized losses on  the interest rate swap agreement of $4.2 million. The amount of future gain or loss actually recognized will be dependent upon future interest rates. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk.”  We did not settle the interest rate swap related to the $225.0 million second lien term facility when it was retired in November 2009; therefore, the interest rate swap outstanding at December 31, 2010 does not have debt associated with it.

 

*Contractual Obligations*. A summary of our contractual obligations as of December 31, 2010 is provided in the following table.

 
| ** **                                     | ** ** | **As of December 31,** | ** ** |
|------------------------------------------------|------------|---------------------------------------|------------|
| **(in millions)**                         | ** ** | **2011**                              | ** ** | **2012** | ** ** | **2013** | ** ** | **2014** | ** ** | **2015** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|                                           |       |                                  |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Credit Facility(1)                             |       | $                                     | —     |   | $ | — |   | $ | — |   | $ | — |   | $ | 100.0 |   | $ | — |   | $ | 100.0 |   |
| Senior notes—interest(2)                  |       | 49.2                                  |       | 49.2 |   | 49.2 |   | 49.2 |   | 49.2 |   | 98.4 |   | 344.4 |   |
| Senior notes—principal(2)                 |       | —                                |       | — |   | — |   | — |   | — |   | 525.0 |   | 525.0 |   |
| Note payable — interest and principal (3) |       | 2.2                                   |       | 2.2 |   | 27.1 |   | — |   | — |   | — |   | 31.5 |   |
| Drilling rig commitments(4)                    |       | 10.5                                  |       | — |   | — |   | — |   | — |   | — |   | 10.5 |   |
| Derivative instruments(5)                      |       | 4.2                                   |       | — |   | — |   | — |   | — |   | — |   | 4.2 |   |
| Asset retirement obligations(6)                |       | —                                |       | — |   | — |   | — |   | — |   | 5.4 |   | 5.4 |   |
| Compression service agreement                  |       | 1.4                                   |       | 1.4 |   | 1.4 |   | 1.4 |   | 1.2 |   | — |   | 6.8 |   |
| Office and equipment leases                    |       | 0.9                                   |       | 0.9 |   | 0.7 |   | 0.6 |   | 0.5 |   | 0.4 |   | 4.0 |   |
| Total                                          |       | $                                     | 68.4       |   | $ | 53.7 |   | $ | 78.4 |   | $ | 51.2 |   | 150.9 |   | $ | 629.2 |   | $ | 1,031.8 |   |
|                                                |            |                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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(1)         Includes outstanding principal amount at December 31, 2010. 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)         The 9.375% senior notes are due December 1, 2017.

 

(3)         Note payable assumed in business acquisition, due December 1, 2013, interest at 9%.

 

(4)         At December 31, 2010 we had three drilling rigs operating in the Appalachian Basin under contracts which expire in 2011. Additionally, subsequent to December 31, 2010, we entered into four additional one-year contracts for drilling rigs (two in Appalachia, one in Arkoma, and one in Piceance) having total commitments of approximately $26.5 million.  Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. Drilling obligations

 

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for individual wells have not been included in the table above. 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 based on our working interest.

 

Drilling rig commitments do not include contingent commitments to drill wells on our unproved properties in order to retain oil and natural gas leasehold interests.  Our acquisition agreement to acquire acreage in the Appalachian Basin contains commitments to drill 179 wells at intervals specified in the agreement.  As of December 31, 2010, the Company has met its required cumulative drilling commitment of 24 wells, and has an additional 30 wells in various stages of drilling or completion.

 

(5)         Derivative instruments represent the fair value for interest rate derivatives presented as liabilities in our consolidated balance sheet as of December 31, 2010. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations.

 

(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.

 

In addition to amounts shown in the above table, we have entered into contracts with third party pipeline owners that provide firm processing rights and firm takeaway capacity on pipeline systems. The remaining terms on these contracts range from one to 14 years and require us to pay transportation demand and commodity charges regardless of the amount of pipeline capacity utilized by us.

 

**Critical Accounting Policies and Estimates**

 

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. 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 of the notes to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

 

***Natural Gas and Oil Properties***

 

*Successful Efforts Method*

 

Our natural gas 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 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 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.

 

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Unevaluated natural gas 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, 2008, 2009, and 2010 we charged impairment expense for expired or expiring leases with a cost of $10.1 million, $54.2 million, and $35.9 million, respectively. The assessment of unevaluated natural gas 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 and Oil Reserve Quantities and Standardized Measure of Future Cash Flows*

 

Our independent engineers and internal technical staff prepare the estimates of natural gas and oil reserves and associated future net cash flows. Current accounting guidance allows only proved natural gas and oil reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of natural gas 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 and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas 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 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 and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions 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 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 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 2008, 2009 or 2010.

 

**Revised Natural Gas and Oil Standard**

 

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting, or Modernization. The Modernization disclosure requirements require reporting of natural gas and oil reserves using an average price based upon the prior 12 month period rather than year end prices and the use of new technologies to determine proved reserves, if those technologies have been demonstrated to result in reliable conclusions about

 

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reserves volumes. Companies are also allowed to disclose probable and possible reserves to investors in SEC filed documents. In addition, companies are required to report the independence and qualifications of their reserves preparer or auditors and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The Modernization disclosure requirements have become effective for the year ending December 31, 2009. The FASB has issued Accounting Standards Update 2010-03 (ASU 2010-03) “Extractive Industries—Oil and Gas” to align its rules for oil and gas reserve estimation and disclosure requirements with the SEC’s final rule. In October 2009, the SEC issued Staff Accounting Bulletin No. 113 (SAB No. 113), which revises portions of the interpretive guidance included in the section of the Staff Accounting Bulletin Series titled Topic 12: Oil and Gas Producing Activities. The principal changes involve revisions to bring Topic 12 into conformity with the contents of the Modernization. We have adopted the Modernization standard in the preparation of our December 31, 2009 oil and gas reserve estimates and related disclosures.

 

**Off-Balance Sheet Arrangements**

 

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

 

**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 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 and oil production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

 

To mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our natural gas and oil production when management believes that favorable future prices can be secured. We typically hedge a fixed price for natural gas at our sales points (New York Mercantile Exchange (“NYMEX”) less basis) to mitigate the risk of differentials to the Centerpoint East, CIG Hub, Transco Zone 4, Dominion South and Columbia Gas Transmission (CGTAP) Indexes.

 

Our financial hedging activities are intended to support natural gas and oil prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. At December 31, 2010, we had in place natural gas swaps covering portions of production from 2011 through 2015. Our senior secured revolving credit facility allows us to hedge up to 85% of our estimated production from proved reserves for up to 12 months in the future, 75% for 13 to 24 months in the future, 65% for 25 to 36 months in the future, 55% for 37 to 48 months in the future and 45% for 49 to 60 months in the future. Based on our annual production and our fixed price swap contracts in place during 2010, our annual income before taxes for the year ended December 31, 2010 would have decreased by approximately $1.0 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.1 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

 

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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 2010, approximately 79% of our natural gas volumes were hedged, which resulted in realized gains on hedges of $73.7 million.  In 2009, approximately 72% of our natural gas volumes were hedged, which resulted in realized gains on hedges of $116.5 million. In 2008, approximately 59% of our natural gas volumes were hedged, which resulted in realized gains on hedges of $26.1 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, 2010, the estimated fair value of all of our commodity derivative instruments was a net asset of $230.4 million comprised of current and noncurrent assets.

 

The table below summarizes the realized and unrealized gains related to natural gas derivative instruments for years ended December 31, 2007, 2008 and 2009:

 
| ** **                                                    | ** ** | **Years Ended December 31,** | ** ** |
|---------------------------------------------------------------|------------|---------------------------------------------|------------|
| **(in thousands)**                                       | ** ** | **2008**                                    | ** ** | **2009** | ** ** | **2010** | ** ** |
| Realized gains on commodity derivative contracts              |       | $                                           | 26,053     |   | $ | 116,550 |   | $ | 73,713 |   |
| Unrealized gains (losses) on commodity derivative   contracts |       | 90,301                                      |       | (61,186 | ) | 170,571 |   |
| Total                                                         |       | $                                           | 116,354    |   | $ | 55,364 |   | $ | 244,284 |   |

 

As of December 31, 2010, we have entered into fixed price natural gas and oil swaps in order to hedge a portion of our production from 2011 through 2015 as summarized in the following table. Hedge agreements referenced to the Centerpoint and Transco Zone 4 indices are for our production in the Arkoma Basin. Hedge agreements referenced to the CIG index are for our gas production in the Piceance Basin and hedge agreements referenced to the NYMEX-WTI index are for our oil production in the Piceance. Hedge agreements referenced to the CGTAP or Dominion South indices are for our production from the Appalachian Basin.

 
| ** **                                | ** ** | **Oil   Bbls/day** | ** ** | **Natural gas   MMbtu/day** | ** ** | **Weighted   average index   price** | ** ** |
|-------------------------------------------|------------|--------------------|------------|----------------------------------|------------|-------------------------------------------|------------|
| **Year ending December 31,   2011:** |       |               |       |                             |       |                                      |       |
| CIG                                       |       |               |       | 45,000                           |       | $                                         | 5.49       |   |
| Transco Zone 4                            |       |               |       | 45,000                           |       | $                                         | 6.39       |   |
| CGTAP                                     |       |               |       | 65,610                           |       | $                                         | 5.81       |   |
| Dominion South                            |       |               |       | 4,043                            |       | $                                         | 8.22       |   |
| NYMEX-WTI                                 |       | 300                |       |                             |       | $                                         | 88.75      |   |
| **Year ending December 31,   2012:** |       |               |       |                             |       |                                      |       |
| CIG                                       |       |               |       | 45,000                           |       | $                                         | 5.71       |   |
| Transco Zone 4                            |       |               |       | 35,000                           |       | $                                         | 7.05       |   |
| CGTAP                                     |       |               |       | 65,556                           |       | $                                         | 6.02       |   |
| Dominion South                            |       |               |       | 3,318                            |       | $                                         | 8.00       |   |
| NYMEX — WTI                          |       | 300                |       |                             |       | $                                         | 90.20      |   |
| **Year ending December 31,   2013:** |       |               |       |                             |       |                                      |       |
| CIG                                       |       |               |       | 60,000                           |       | $                                         | 5.53       |   |
| Transco Zone 4                            |       |               |       | 40,000                           |       | $                                         | 6.51       |   |
| CGTAP                                     |       |               |       | 42,631                           |       | $                                         | 6.36       |   |
| Dominion South                            |       |               |       | 21,702                           |       | $                                         | 5.65       |   |
| NYMEX — WTI                          |       | 300                |       |                             |       | $                                         | 90.30      |   |
| **Year ending December 31,   2014:** |       |               |       |                             |       |                                      |       |
| CIG                                       |       |               |       | 50,000                           |       | $                                         | 5.84       |   |

 

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|                                      |   | **Oil   Bbls/day** | ** ** | **Natural gas   MMbtu/day** | ** ** | **Weighted   average index   price** | ** ** |
|-------------------------------------------|--------|--------------------|------------|----------------------------------|------------|-------------------------------------------|------------|
| Transco Zone 4                            |   |               |       | 20,000                           |       | $                                         | 6.51       |   |
| CGTAP                                     |   |               |       | 70,000                           |       | $                                         | 6.26       |   |
| Centerpoint                               |   |               |       | 10,000                           |       | $                                         | 6.20       |   |
| Dominion South                            |   |               |       | 30,000                           |       | $                                         | 5.48       |   |
| **Year ending December 31,   2015:** |   |               |       |                             |       |                                      |       |
| CIG                                       |   |               |       | 10,000                           |       | $                                         | 5.06       |   |
| Dominion South                            |   |               |       | 60,000                           |       | $                                         | 5.58       |   |

 

By removing price volatility from a portion of our expected natural gas production through December 2014, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

 

By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us 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 eight different counterparties; all but one are lenders in our senior secured revolving credit facility.  As of December 31, 2010, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, Dominion Field Services, Barclays, Union Bank, Credit Suisse, and KeyBank accounted for approximately 46%, 25%,  9%, 7%, 6%, 4%, 2%, and 1%, respectively, of  the net fair value of our commodity derivative assets position. We believe all of these institutions currently are acceptable credit risks. 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, 2010, we have no past due receivables from or payables to any of our counterparties.

 

***Interest Rate Risks and Hedges***

 

During the year end December 31, 2010, we had indebtedness outstanding under our senior secured revolving credit facility which bears interest at floating rates. The average annual interest rate incurred on this indebtedness for the years ended December 31, 2010 and 2009 was approximately 2.54%  and 4.69%, respectively. A 1.0% increase in each of the average LIBOR rate and federal funds rate in 2010 would have resulted in an estimated $0.9 million increase in interest expense for the year ended December 31, 2010 before giving effect to interest rate swaps.

 

Through interest rate derivative contracts, we have attempted to mitigate our exposure to changes in interest rates. We have entered into variable to fixed interest rate swap agreements which hedge our exposure to interest rate variations on our senior secured revolving credit facility and second lien term loan facility. At December 31, 2009, we have one interest rate swap outstanding for a notional amount of $225 million with a fixed pay rate of 4.11% with a term expiring in July 2011. The outstanding swap relates to the floating rate second lien term loan, which was repaid in full with the net proceeds of the November 2009 senior notes offering. We did not terminate this interest rate swap when the second lien term loan was repaid in November 2009; therefore, this interest rate swap does not have floating rate debt associated with it.

 

***Counterparty and Customer Credit Risk***

 

Our principal exposures to credit risk are through receivables resulting from commodity derivatives contracts ($230.4 million at December 31, 2010), joint interest receivables ($6.3 million at December 31, 2010) and the sale of our natural gas production ($24.5 million in receivables at December 31, 2010), 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. We do not require our

 

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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 information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.

 

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

 

Not applicable.

 

**Item 9A.          Controls and Procedures**

 

**Disclosure Controls and Procedures**. Based on an evaluation carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were, as of December 31, 2010, effective.

 

**Changes in Internal Control Over Financial Reporting**. There has been no change in our internal control over financial reporting during the fourth fiscal quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by the rules of the Securities and Exchange Commission for newly public companies.

 

**Item 9B.****                                               ****Other Information**

 

Not applicable.

 

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**PART III**

 

**Item 10.**** ****Directors, Executive Officers and Corporate Governance**

 

**Executive Officers and Directors**

 

The following table sets forth names, ages and titles of our executive officers and directors. Each of the individuals listed below holds the position stated below at Antero Resources LLC and Antero Resources Finance Corporation.

 
| **Name**                        | ** ** | **Age** | ** ** | **Title**                                                                |
|---------------------------------|------------|---------|------------|--------------------------------------------------------------------------|
| Peter   R. Kagan(1)             |       | 42      |       | Director                                                                 |
| W.   Howard Keenan, Jr.(1) |       | 60      |       | Director                                                                 |
| Christopher   R. Manning(1)     |       | 43      |       | Director                                                                 |
| Paul   M. Rady                  |       | 57      |       | Chairman   of the Board of Directors and Chief Executive Officer         |
| Glen   C. Warren, Jr.      |       | 55      |       | Director,   President, Chief Financial Officer and Secretary             |
| Kevin   J. Kilstrom             |       | 56      |       | Vice   President—Production                                         |
| Robert   E. Mueller             |       | 54      |       | Vice   President—Geology                                            |
| Brian   A. Kuhn                 |       | 52      |       | Vice   President—Land                                               |
| Mark   D. Mauz                  |       | 53      |       | Vice   President—Gathering, Marketing and Transportation            |
| Steve   M. Woodward             |       | 52      |       | Vice   President—Business Development                               |
| Alvyn   A. Schopp               |       | 52      |       | Vice   President—Accounting & Administration and Treasurer |
| Kathryn   S. Wilson             |       | 36      |       | General   Counsel and Assistant Secretary                                |

 

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(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 Antero Resources LLC’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.  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 co-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 Broad Oak Energy, Canbriam Energy, Fairfield Energy, Laredo Petroleum, MEG Energy, Resources for the Future, Targa Resources Inc. and Targa Resources Partners L.P. In addition, he is a member of the Visiting Committee of the University of Chicago Law School.

 

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 also 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

 

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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 also 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 of Trilantic Capital Partners, or TCP. Mr. Manning joined TCP in 2009. He 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 Investment Management Division Global Operating Committee and the Private Equity Division Operating Committee. Lehman Brothers Holdings Inc. filed a voluntary petition for protection under the U.S. bankruptcy code in September 2008. Prior to joining TCP, 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 also currently serves on the boards of Enduring Resources, The Cross Group, Mediterranean Resources and VantaCore Partners. He 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 also 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 has served as a director of Diamond Foods, Inc. since 2005 and served as a director of Venoco Inc. from 2005 to 2008.

 

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.

 

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*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.

 

*Robert E. Mueller* has served as Vice President of Geology since April 2005. Mr. Mueller also served as Chief Geologist 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. Mueller was with Williams as a Director of the Raton Basin asset team in 2001 to 2002. Mr. Mueller was Chief Geologist at Barrett Resources from 1996 to 2001. Mr. Mueller worked as a Senior Geologist for North American Resources from 1993 to 1996 after working the prior 11 years for Amoco Production Company. Mr. Mueller holds a B.S. in Geology from Northern Arizona University and an M.S. in Geology from the University of Wyoming.

 

*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. 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.

 

*Kathryn S. Wilson* has served as General Counsel and Assistant Secretary since March 2010. From September 2001 to February 2010, Ms. Wilson was an associate with Vinson & Elkins L.L.P. specializing in securities offerings and mergers and acquisitions. Ms. Wilson holds a B.A. from Wesleyan University and a J.D. from the University of Texas School of Law.

 

**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

 

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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                                 |
| Robert   E. Mueller        |       | Vice   President—Geology                                    |
| Alvyn   A. Schopp          |       | Vice   President—Accounting and Administration              |

 

Each of our Named Executive Officers is an employee of Antero Resources Corporation, which is a wholly owned subsidiary of Antero Resources LLC and one of the parent companies of Antero Resources Finance Corporation. Prior to the November 2009 corporate reorganization, the Compensation Committee of the Board of Directors of Antero Resources Corporation approved all compensation decisions for our officers. Since the reorganization, the Compensation Committee of the Antero Resources LLC Board of Directors, or the Antero Resources LLC Board of Directors, as appropriate, has approved all compensation decisions for our officers. The Antero Resources LLC Board of Directors and the Antero Resources Corporation Board of Directors are comprised of the same members and are collectively referred to in this Item 11 as the “Board.”

 

***Compensation Philosophy and Objectives of Our Compensation Program***

 

Since the inception of Antero Resources Corporation in 2002, we have sought to 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. As a result, until September 2009, our executive compensation program was primarily designed to attract, retain and motivate our employees by compensating them with significant amounts of equity relative to cash compensation. In particular, we kept our Named Executive Officers’ total cash compensation at levels that we believed were sufficient to provide them, in the case of base salaries, with a modest amount of cash sufficient to support their families and, in the case of annual bonuses, with discretionary amounts that rewarded them for overall individual performance, as well as company performance during the year relative to continually evolving company objectives. With respect to non-cash awards, we generally provided disproportionately greater amounts of equity, which we believed would ultimately compensate our Named Executive Officers as they participated in growing our company and creating stakeholder value. We also provided additional opportunities for our Named Executive Officers to purchase various classes of preferred and common shares in our company on the same basis as our institutional private equity owners for the purpose of aligning the interests of our officers with those of our stakeholders.

 

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Our strategy since September 2009 has been to structure our compensation program so that we may seek out highly qualified and experienced individuals capable of contributing to the continued growth of our development stage company, both in terms of size and enterprise value, and an effective transition into the new obligations we face as a SEC registrant. Accordingly, over the course of several months in late 2009, we undertook various reporting company preparedness initiatives to ensure the competitiveness of our executive compensation programs and further align the interests of our Named Executive Officers and other employees with the long-term objectives of our company. In connection with these initiatives, we engaged a compensation consultant to benchmark our officers’ compensation to ensure that our programs were roughly in the median range of our peer group companies. This engagement is discussed in more detail below under “—Implementing Our Objectives.”

 

***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, with support provided periodically by our compensation consultant and their review of 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 executive officer’s performance during the year and the company’s performance during the year, but rely primarily on their business judgment and personal experience. 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 Named Executive Officers have assumed a role in the evaluation, design or administration of our executive officer compensation program.

 

*Role of External Advisors*

 

In September 2009, Antero’s management engaged Cogent Compensation Partners, Inc. (“Cogent”) to provide periodic executive compensation consulting services, as determined by management. Cogent did not provide, and does not currently provide, any other services to our company. Management’s objective when hiring Cogent was to assess our level of competitiveness for executive-level talent and receive recommendations for attracting, motivating and retaining key employees in light of our transition into the new obligations we would be facing as a SEC registrant. Pursuant to the terms of its engagement, Cogent:

 

·                  Collected and reviewed all relevant company information, including our historical executive compensation data and our organizational structure, and conducted individual interviews with our executive officers and our largest institutional investors to gain insight into the vision, business strategy, culture and effectiveness of our current executive compensation program as well as expectations for the future;

 

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

 

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

 

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

 

Cogent’s report was presented by management to the Board as a whole in September 2009. The report was utilized by Messrs. Rady and Warren when making their recommendations to the Board for fiscal 2010 compensation decisions. Management reevaluated Cogent’s report in 2010 and determined that because there had not been any material changes in the competitive environment since the report was prepared, the information previously presented to the Board remained relatively current.  Accordingly, neither management nor the

 

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Compensation Committee engaged Cogent or any other compensation consultant during fiscal 2010 for fiscal 2011 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.

 

Prior to September 2009, Messrs. Rady and Warren made informal comparisons of our executive compensation program to the compensation paid to executives of publicly traded and other privately held companies similar in size and location to our company. Beginning in September 2009, Messrs. Rady and Warren took a more formal approach and hired Cogent to assess the compensation levels of our top eight executive officers relative to the market. In addition, Messrs. Rady and Warren used statistical information from the 2009 Oil and Gas E&P Industry Compensation Survey (the “2009 ECI Survey”) prepared by Effective Compensation, Incorporated (“ECI”) to supplement Cogent’s peer group data. Messrs. Rady and Warren considered the results of the Cogent and ECI survey data when making their recommendations to the Board for the fiscal 2010 compensation decisions.

 

·                  Cogent Survey Data.  In 2009, Cogent used the following parameters when constructing the peer group for its assessment: (1) resource focused exploration and production companies that are publicly 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 $1.0 billion in enterprise value. Using these parameters and collaborating with Messrs. Rady and Warren, Cogent developed an industry reference group comprised of 16 companies (the “Cogent Peer Group”). The Cogent Peer Group included the following companies:

 

·                  Berry Petroleum Company;

 

·                  Bill Barrett Corporation;

 

·                  Cabot Oil & Gas Corporation;

 

·                  Carrizo Oil & Gas, Inc.;

 

·                  Comstock Resources, Inc.;

 

·                  Concho Resources Inc.;

 

·                  Continental Resources, Inc.;

 

·                  Encore Acquisition Company;

 

·                  EXCO Resources, Inc.;

 

·                  Newfield Exploration Company;

 

·                  Petrohawk Energy Corporation;

 

·                  Quicksilver Resources, Inc.;

 

·                  Range Resources Corporation;

 

·                  Sandridge Energy, Inc.;

 

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·                  Southwestern Energy Company; and

 

·                  Ultra 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 believe we compete for talent. The 2009 ECI Survey was used to compare our executive compensation program against the following companies, which were selected by Messrs. Rady and Warren, and which have comparable revenues, market capitalization, capital expenditure budgets, business strategies, geographic and geologic focus and numbers of employees (the “ECI Peer Group”):

 

·                  Berry Petroleum Company;

 

·                  Bill Barrett Corporation;

 

·                  Cimarex Energy Co.;

 

·                  Comstock Resources, Inc.;

 

·                  Concho Resources Inc.;

 

·                  Forest Oil Corporation;

 

·                  Mariner Energy, Inc.;

 

·                  Quicksilver Resources Inc.;

 

·                  St. Mary Land & Exploration Company; and

 

·                  Whiting Petroleum Corporation.

 

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 our peer group companies.  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 our 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.

 

We believe that targeting this level of compensation helps us meet our overall total rewards strategy and executive compensation objectives outlined above.

 

***Elements of Compensation***

 

Compensation of our Named Executive Officers includes the following key components:

 

·                  Base salaries;

 

·                  Annual cash bonus incentive payments;

 

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·                  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 either our internal 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, we also consider pay levels within the company to appropriately align each of our Named Executive Officer’s salary level relative to the salary levels of our other officers so that it accurately reflects the officer’s relative skills, responsibilities, experience and contributions to our company. To that end, annual 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.

 

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 2010 Decisions.  In October 2009, after comparing base salary levels to the Cogent Peer Group and ECI Peer Group (as described in more detail above under “—Competitive Benchmarking”) and considering the individual and business factors described above, Messrs. Rady and Warren recommended, and the Board approved, increases in the base salaries of our Named Executive Officers as shown in the table below. These increases, which became effective in November 2009, were made as part of the overall shift in our compensation strategy as described in more detail above under “—Compensation Philosophy and Objectives of Our Compensation Program.” The adjusted base salary amounts were slightly below or at the median of both the Cogent Peer Group and the ECI Peer Group.

 
| **Executive Officer** | ** ** | **Base Salary Prior   to November 2009** | ** ** | **Base Salary as of   November 2009** | ** ** | **Percentage   Increase** | ** ** |
|----------------------------|------------|--------------------------------------------------------------|------------|-----------------------------------------------------------|------------|---------------------------|------------|
| ** **                 | ** ** | **($)**                                                      | ** ** | **($)**                                                   | ** ** | **(%)**                   | ** ** |
| Paul M. Rady               |       | 240,000                                                      |       | 450,000                                                   |       | 88                        |       |
| Glen C. Warren, Jr.   |       | 222,500                                                      |       | 375,000                                                   |       | 69                        |       |
| Kevin J. Kilstrom          |       | 200,000                                                      |       | 280,000                                                   |       | 40                        |       |
| Robert E. Mueller          |       | 200,000                                                      |       | 260,000                                                   |       | 30                        |       |
| Alvyn A. Schopp            |       | 185,000                                                      |       | 275,000                                                   |       | 49                        |       |

 

No other adjustments were made to base salaries paid during fiscal 2010.

 

Fiscal 2011 Decisions.  In November 2010, after considering the individual and company performance factors described above along with the competitive benchmarking performed in 2009, Messrs. Rady and Warren

 

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recommended, and the Board approved, nominal increases in the base salaries of our Named Executive Officers to reflect adjustments for inflation and cost of living increases. These increases became effective as of January 2011.

 

*Annual Cash Incentive Payments*

 

Annual cash incentive payments, which we also refer to as cash bonuses, are a key part 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 amount to some or all of our employees, including our Named Executive Officers, and, if so, the amount of any 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. 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 2010 Decisions.  A discretionary cash bonus was awarded to each of our Named Executive Officers in December 2010. These awards were made based upon the factors described above under “—Base Salaries.” The bonuses paid to each Named Executive Officer are reflected below in the “Bonus” column of the Summary Compensation Table.

 

*Transaction Bonuses*

 

Under our 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. That Transaction Bonus Pool is an amount equal to three percent 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 any employee are 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 Resources LLC and in Antero Resources Employee Holdings LLC (which are described below under “—Long-Term Equity-Based Incentive Awards”).

 

Fiscal 2010 Decisions. In connection with our sale of Antero Resources Midstream Corporation in November 2010, a transaction bonus pool was created and transaction bonuses were awarded and paid to each of our Named Executive Officers. Factors considered in determining the particular amounts allocated to each Named Executive Officer included each officer’s historical contribution to the management of Antero Resources Midstream Corporation and the other factors described above under “—Base Salaries.”  The bonuses allocated to each Named Executive Officer are reflected below in the “Bonus” column of the Summary Compensation Table along with the discretionary cash bonuses described above.

 

*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

 

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Antero Resources LLC 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.

 

Fiscal 2009 Decisions.  In November 2009, the Compensation Committee approved grants of restricted Class A-2 and Class B-2 unit awards in Holdings to each of our Named Executive Officers. These awards are not necessarily intended to be granted on an annual basis. The units granted in connection with these awards are intended to constitute “profits interests” in Holdings that will participate solely in any future profits of Holdings that result from any distributions on our units that are held by Holdings. The units vest in equal amounts on each of the first four anniversaries of the applicable vesting commencement date set forth in the Named Executive Officer’s restricted unit agreement and are subject forfeiture and repurchase in certain circumstance, as described below under “—Potential Payments Upon a Termination or a Change in Control.” In determining whether, and in what amounts, to grant the November 2009 awards, the Compensation Committee considered recommendations from our compensation consultant and Messrs. Rady and Warren.

 

Fiscal 2010 Decisions.  Because a portion of the units granted in November 2009 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 award units to our Named Executive Officers in 2010.

 

***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 and dental insurance, as well as medical and dependent care flexible spending 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 employer discretionary contributions, we have only made one such contribution in 2004.  We do not provide any matching contributions under the 401(k) plan. 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 currently 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,” the Named Executive Officers could be entitled to receive certain payments or accelerated vesting of any of their unit awards that remain unvested upon their termination of employment with us under certain circumstances or the occurrence of certain corporate events.

 

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***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 we are a limited liability company and 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 “Code”), which generally imposes a $1 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 Antero. In connection with this risk assessment, we 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.

 

We believe 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. We believe our overall compensation program provides a reasonable balance between short and long-term objectives, which help 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 our Compensation Committee in determining cash bonuses are based on overall individual performance relative to continually evolving company objectives, and our 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 the 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, 2010.

 

The preceding report is presented by the following members of the board of directors who comprise the Compensation Committee:

 
|   | Peter   R. Kagan             |
|--------|------------------------------|
|   | W.   Howard Keenan, Jr. |
|   | Christopher   R. Manning     |

 

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***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, 2010 and 2009.

 

**Summary Compensation Table for the Year Ended December 31, 2010 and 2009**

 
| **Name and Principal Position**                               | ** ** | **Year** | ** ** | **Salary** | ** ** | **Bonus (2)** | ** ** | **Option   Awards(1)** | ** ** | **All Other   Compensation (3)** | ** ** | **Total**  | ** ** |
|------------------------------------------------------------------------------|------------|----------|------------|------------|------------|--------------------|------------|------------------------|------------|---------------------------------------|------------|------------|------------|
|                                                                         | ** ** | **($)**  | ** ** | **($)**    | ** ** | **($)**            | ** ** | **($)**                | ** ** | **($)**                               | ** ** | ** ** | ** ** |
| Paul M. Rady                                                                 |       | 2010     |       | $          | 450,000    |               | $          | 1,319,267              |       | $                                     | —     |       | $          | — |   | $ | 1,769,267 |   |
| *(Chairman of the Board and Chief*                                           |       | 2009     |       | $          | 275,000    |               | $          | 225,000                |       | $                                     | 168,013    |       | $          | 293,467 |   | $ | 961,480 |   |
| *Executive Officer)*                                                         |       |     |       |       |       |               |       |                   |       |                                  |       |       |       |
| * *                                                                     |       |     |       |       |       |               |       |                   |       |                                  |       |       |       |
| Glen C. Warren, Jr.                                                     |       | 2010     |       | $          | 375,000    |               | $          | 912,845                |       | $                                     | —     |       | $          | — |   | $ | 1,287,845 |   |
| *(Director, President and Chief Financial Officer   and Secretary)*          |       | 2009     |       | $          | 247,917    |               | $          | 175,000                |       | $                                     | 111,120    |       | $          | 195,967 |   | $ | 730,004 |   |
|                                                                         |       |     |       |       |       |               |       |                   |       |                                  |       |       |       |
| Kevin J. Kilstrom                                                            |       | 2010     |       | $          | 280,000    |               | $          | 460,000                |       | $                                     | —     |       | $          | — |   | $ | 740,000 |   |
| *(Vice President—Production)*                                           |       | 2009     |       | $          | 213,333    |               | $          | 140,000                |       | $                                     | —     |       | $          | 348,973 |   | $ | 702,306 |   |
|                                                                         |       |     |       |       |       |               |       |                   |       |                                  |       |       |       |
| Robert E. Mueller                                                            |       | 2010     |       | $          | 260,000    |               | $          | 415,000                |       | $                                     | —     |       | $          | — |   | $ | 675,000 |   |
| *(Vice President—Geology)*                                              |       | 2009     |       | $          | 210,000    |               | $          | 110,000                |       | $                                     | 78,006     |       | $          | 229,406 |   | $ | 627,412 |   |
|                                                                         |       |     |       |       |       |               |       |                   |       |                                  |       |       |       |
| Alvyn A. Schopp                                                              |       | 2010     |       | $          | 275,000    |               | $          | 525,000                |       | $                                     | —     |       | $          | — |   | $ | 800,000 |   |
| *(Vice President—Accounting & Administration   and Treasurer)* |       | 2009     |       | $          | 200,000    |               | $          | 140,000                |       | $                                     | 150,007    |       | $          | 96,700 |   | $ | 586,707 |   |

 

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(1)          Represents the aggregate grant date fair value of options granted in fiscal 2009 to purchase shares of the common stock of certain of our operating subsidiaries, calculated in accordance with FASB ASC Topic 718. These options were cancelled immediately prior to the 2009 reorganization. The valuation assumptions used in determining these amounts are described in Note 7 to the financial statements included elsewhere in this report.

 

(2)          Bonus compensation for 2010 represents the aggregate amount of the annual discretionary cash bonuses paid to each Named Executive Officer, as well as 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; Mr. Mueller, $275,000; and Mr. Schopp, $350,000.

 

(3)          All Other Compensation for 2009 represents the total amounts paid to each Named Executive Officer as a result of the termination of the stock incentive plans of our operating subsidiaries. The amounts consist of (a) a waiver payment paid to each officer in 2009 in exchange for signing a release and waiver of all claims and entitlements pursuant to the cancelled options and restricted stock awards and (b) the amount of cash out payments paid in 2010 with respect to certain vested in-the-money options that were cancelled in 2009 in connection with our restructuring.  A portion of the cash out payments necessary to satisfy the applicable FICA tax requirements was remitted to the Internal Revenue Service on behalf of each executive officer in December 2009. However, due to the applicable rules imposed under Section 409A of the Code, each operating subsidiary paid the remaining portion of its respective cash out payment, if any, due to each executive officer in November 2010 without interest.

 

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***Grants of Plan-Based Awards for Fiscal Year 2010***

 

There were no plan-based awards granted to our Named Executive Officers during the fiscal year ended December 31, 2010.

 

***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*

 

The following table sets forth the approximate percentage of each Named Executive Officer’s total compensation that we paid in the form of base salary and annual cash incentive awards during fiscal 2010.

 
| **Name**                 | ** ** | **Percentage of   Total 2010   Compensation** | ** ** |
|--------------------------|------------|---------------------------------------------------------|------------|
| Paul M. Rady             |       | 48                                                      | %          |
| Glen C. Warren, Jr. |       | 52                                                      | %          |
| Kevin J. Kilstrom        |       | 59                                                      | %          |
| Robert E. Mueller        |       | 59                                                      | %          |
| Alvyn A. Schopp          |       | 56                                                      | %          |

 

**Outstanding Equity Awards Value at 2010 Fiscal Year-End**

 

The following table provides information concerning stock that has not vested for our Named Executive Officers as of December 31, 2010.

 

**Outstanding Equity Awards as of December 31, 2010**

 
| ** **                  | ** ** | **Stock Awards**                                                                             | ** ** |
|-----------------------------|------------|---------------------------------------------------------------------------------------------------|------------|
| **Name**                    | ** ** | **Number of   Shares or 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** | ** ** |
| ** **                  | ** ** | **(#)**                                                                                           | ** ** | **($)** | ** ** | **(#)** | ** ** | **($)** | ** ** |
| Paul M. Rady                |       |                                                                                              |       |   |   |   |   |   |   |
| *Restricted Award Units(1)* |       | 125,000                                                                                           | (4)(7)     | $ | — |   | — |   | $ | — |   |
| Glen C. Warren, Jr.    |       |                                                                                              |       |   |   |   |   |   |   |
| *Restricted Award Units(1)* |       | 83,333                                                                                            | (4)(7)     | $ | — |   | — |   | $ | — |   |
| Kevin J. Kilstrom           |       |                                                                                              |       |   |   |   |   |   |   |
| *Restricted Award Units(1)* |       | 50,000                                                                                            | (6)(7)     | $ | — |   | — |   | $ | — |   |
| *Restricted Award Units(1)* |       | 100,000                                                                                           | (5)(7)     | $ | — |   | — |   | $ | — |   |
| *Class I-3 Units(2)*   |       | 5,000                                                                                             | (3)(8)     | $ | — |   | — |   | $ | — |   |
| *Class B-1 Units(2)*   |       | 50,000                                                                                            | (3)(8)     | $ | — |   | — |   | $ | — |   |
| *Class B-3 Units(2)*   |       | 31,746                                                                                            | (3)(8)     | $ | — |   | — |   | $ | — |   |
| *Class B-5 Units(2)*   |       | 15,385                                                                                            | (3)(8)     | $ | — |   | — |   | $ | — |   |
| Robert E. Mueller           |       |                                                                                              |       |   |   |   |   |   |   |
| *Restricted Award Units(1)* |       | 100,000                                                                                           | (5)(7)     | $ | — |   | — |   | $ | — |   |
| Alvyn A. Schopp             |       |                                                                                              |       |   |   |   |   |   |   |
| *Restricted Award Units(1)* |       | 31,250                                                                                            | (5)(7)     | $ | — |   | — |   | $ | — |   |

 

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(1)          Represents the number of restricted Class A-2 and/or Class B-2 units 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 4, 5 and 6 below for a description of the vesting schedule for the awards that remained outstanding as of December 31, 2010.

 

(2)          Reflects awards that were originally issued by certain of the operating subsidiaries as restricted stock awards with respect to the subsidiary’s Series C preferred stock and Series D, E, and F common stock. In connection with our November 2009 corporate reorganization, all awards were exchanged for Class I-3, B-1, B-3 and B-5 units in Antero Resources LLC. The vesting conditions associated with the original restricted stock awards were kept in place upon exchange. Please see footnote 3 below for a description of the awards that remained outstanding as of December 31, 2010.

 

(3)          Represents awards that were granted on August 10, 2007 with a vesting commencement date of August 10, 2007. The awards vested 20% upon issuance and the remaining portion will vest 20% on each of the first four anniversaries of the vesting commencement date.

 

(4)          Represents non-vested restricted unit awards that were granted on November 3, 2009 with a vesting commencement date of August 10, 2007. The awards vest 25% per year beginning on the first anniversary of the vesting commencement date.

 

(5)          Represents non-vested restricted unit awards that were granted on November 20, 2009 with a vesting commencement date of August 10, 2007. The awards vest 25% per year beginning on the first anniversary of the vesting commencement date.

 

(6)          Represents non-vested restricted unit awards that were granted on November 20, 2009 with a vesting commencement date of June 4, 2007. The awards vest 25% per year beginning on the first anniversary of the vesting commencement date.

 

(7)          The fair market value of each class of units in Holdings was determined to be $0.00 as of December 31, 2010.  This valuation was established based on the aggregate gross asset values of our operating subsidiaries, as determined through an independent appraisal, and adjusted to reflect the distribution rights of Holdings with respect to our units pursuant to our LLC Agreement and a discount to reflect the fact that the company does not have publicly traded equity.

 

(8)          The fair market value per unit of each of 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 2010**

 

The following table provides information concerning each vesting of stock, including restricted stock, restricted stock units and similar instruments, during fiscal 2010 on an aggregated basis with respect to each of our Named Executive Officers. No options were exercised during fiscal 2010 because all options were terminated in 2009.

 

**Option Exercises and Stock Vested for the Year Ended December 31, 2010**

 
| ** **                 | ** ** | **Stock Awards**                                       | ** ** |
|----------------------------|------------|-------------------------------------------------------------|------------|
| **Name**                   | ** ** | **Number of   Shares   Acquired on   Vesting(1)** | ** ** | **Value Realized   Upon Vesting** | ** ** |
| ** **                 | ** ** | **(#)**                                                     | ** ** | **($)** | ** ** |
| Paul M. Rady               |       | —                                                      |       | $ | — |   |
| Glen C. Warren, Jr.   |       | —                                                      |       | $ | — |   |
| Kevin J. Kilstrom          |       |                                                        |       |   |   |
| Class I-3 Units(2)(3) |       | 5,000                                                       |       | $ | 0 |   |
| Class B-1 Units(2)(3) |       | 50,000                                                      |       | $ | 0 |   |
| Class B-3 Units(2)(3) |       | 31,746                                                      |       | $ | 0 |   |
| Class B-5 Units(2)(3) |       | 15,385                                                      |       | $ | 0 |   |
| Robert E. Mueller          |       | —                                                      |       | $ | — |   |
| Alvyn A. Schopp            |       | —                                                      |       | $ | — |   |

 

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(1)          The number of shares acquired on vesting represents the gross number of units vested. There were no federal income or payroll taxes withheld from these awards.

 

(2)          The value realized upon vesting was the gross number of units vested multiplied by the fair market value of the units. Because our units do not have a public market value and we do not measure the awards on a regular basis, the value realized upon vesting is the value at the point of the last measurement of our units, which was November 3, 2009, the date of the corporate reorganization. The fair market value per unit of each class of our units on that date was $0.00.

 

(3)          Reflects awards that were originally issued by certain of the operating subsidiaries as restricted stock awards with respect to the subsidiary’s Series C preferred stock and Series D, E, and F common stock. In connection with our November 2009 corporate reorganization, any vested awards were exchanged for Class I-3, B-1, B-3 and B-5 units in Antero Resources LLC. The vesting conditions associated with the original restricted stock awards were kept in place upon exchange.

 

***Pension Benefits***

 

We do not currently provide pension benefits to our employees.

 

***Nonqualified Deferred Compensation***

 

We do not currently 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 the Named Executive Officers; however, each of our Named Executive Officers have been awarded certain units in Holdings that may be affected by the officer’s termination of 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 the officers in connection with the grant of the unit awards, as well as the Holdings LLC Agreement.

 

The Holdings LLC Agreement provides that upon the 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 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. 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

 

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the following actions in its discretion: (1) require some or all of the 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) willfully 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 (1) as a sale or other transfer of all or substantially all of our units (including by way of merger, consolidation, share exchange, or similar transaction); or (2) the sale or other transfer of all or substantially all of our assets promptly followed by a dissolution and liquidation of our company; or (3) a combination of both. A “qualified IPO” means 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 (1) aggregate cash proceeds of not less than $50,000,000 (without deducting underwriting discounts, expenses, and commissions) and (2) the listing of such interests or securities on the New York Stock Exchange, the NYSE Euronext or the Nasdaq Stock Market.

 

*Antero Units*

 

At the time of the 2009 reorganization, Mr. Kilstrom was the only Named Executive Officer that held outstanding unvested restricted stock awards with respect to the operating subsidiaries’ Series C preferred stock and Series D, E, and F common stock (the “Restricted Stock Awards”). All of our other Named Executive Officers were fully vested in their Restricted Stock Awards due to the fact that they had a longer tenure with Antero than Mr. Kilstrom. Pursuant to the Contribution Agreement entered into as of November 3, 2009 among Antero, each of the operating subsidiaries, certain institutional investors of the operating subsidiaries and members of our management team, the Restricted Stock Awards were exchanged for Class I-3, B-1, B-3 and B-5 units in Antero and the units retained the same vesting schedules as the original awards. Thus, all of Mr. Kilstrom’s Class I-3, B-1, B-3 and B-5 units that remain outstanding will vest on August 10, 2011, subject to certain forfeiture restrictions described below.

 

The Antero units Mr. Kilstrom received in connection with such exchange will also vest in accordance with the terms and conditions contained within the Antero limited liability company agreement. Upon Mr. Kilstrom’s death or “disability,” any unvested units will immediately vest. In the event Mr. Kilstrom is terminated without “cause,” or he voluntarily resigns, his unvested Antero units will become subject to repurchase at his original cost for such units, if any. Mr. Kilstrom’s termination for “cause” will subject his units to repurchase at their original cost. Any vested units in Antero that Mr. Kilstrom holds upon his voluntary resignation will also be subject to repurchase, although such a repurchase would occur at the fair market value of the units at the time of repurchase rather than his original cost for the units. The terms “disability” and “cause” are defined in the Antero limited liability company agreement based on the meanings ascribed to such terms in the Holdings LLC Agreement described above.

 

All time-based vesting restrictions will also lapse with respect to Mr. Kilstrom’s Antero units upon the occurrence of a change of control. The Antero limited liability company agreement generally defines a “change of control” as (1) the disposition of Antero’s membership interests, a merger or similar transaction that results in Antero’s members immediately prior to the transaction no longer representing a majority of Antero’s membership immediately following such transaction, (2) the sale of all or substantially all of Antero’s assets, or (3) the consolidation or other form of reorganization that results in Antero’s membership interests being exchanged for (or converted into) cash, securities or other property of an entity in which the Antero members do not also own a

 

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majority of the voting power. However, in the event Antero conducts a public offering of its interests, certain members of Antero may, in accordance with the terms of the Antero limited liability company agreement, determine that such a transaction does not constitute a change of control.

 

***Potential Payments Upon Termination or Change in Control Table for Fiscal 2010***

 

The information set forth in the table below is based on the assumption that the applicable triggering event occurred on December 31, 2010, the last business day of fiscal 2010. Accordingly, the information reported in the table is our best estimation of our obligations to each Named Executive Officer and will only be determinable with any certainty upon the occurrence of the applicable event. In order to provide the most accurate information possible, neither the acceleration of vesting nor any repurchase rights that are subject to the absolute discretion of either Holdings’ or Antero’s Board of Directors have been taken into account for purposes of calculating the values set forth in the table below. Note, however, that because the fair market value per unit of each applicable unit in Holdings and Antero was $0.00 on December 31, 2010, we would not have had any financial obligation to provide benefits to any of the Named Executive Officers upon a termination of employment by reason of death or disability nor upon the occurrence of an exit event as of December 31, 2010.

 
| **Name**                  | ** ** | **Termination of   Employment by   Reason of Death or   Disability** | ** ** | **Occurrence of an   Exit Event or a   Change of Control** | ** ** |
|---------------------------|------------|-----------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|------------|
| Paul M. Rady              |       |                                                                                          |       |                                                                                          |       |
| *Class B-2 Units(1)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| Glen C. Warren, Jr.  |       |                                                                                          |       |                                                                                          |       |
| *Class B-2 Units(1)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| Kevin J. Kilstrom         |       |                                                                                          |       |                                                                                          |       |
| *Class A-2 Units(2)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| *Class B-2 Units(1)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| *Class I-3 Units(3)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| *Class B-1 Units(3)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| *Class B-3 Units(3)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| *Class B-5 Units(3)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| Robert E. Mueller         |       |                                                                                          |       |                                                                                          |       |
| *Class B-2 Units(1)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |
| Alvyn A. Schopp           |       |                                                                                          |       |                                                                                          |       |
| *Class B-2 Units(1)* |       | $                                                                                             | 0          |                                                                                          | $          | 0 |   |

 

----

(1)          The numbers of unvested Holdings Class B-2 units that would have been subject to accelerated vesting as of December 31, 2010 for each of the officers above are as follows: Mr. Rady—125,000; Mr. Warren—83,333; Mr. Mueller—100,000; Mr. Kilstrom—100,000; and Mr. Schopp—31,250.

 

(2)          The number of unvested Holdings Class A-2 units that would have been subject to accelerated vesting as of December 31, 2010 for Mr. Kilstrom was 50,000.

 

(3)          Mr. Kilstrom held 5,000 Class I-3 units, 50,000 Class B-1 units, 31,746 Class B-3 units, and 15,385 Class B-5 units in Antero that could have potentially been subject to accelerated vesting as of December 31, 2010.

 

***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.

 

***Compensation Committee Interlocks and Insider Participation***

 

None of our executive officers has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

 

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

 

**Beneficial Ownership**

 

The operating subsidiaries together own all of Antero Resources Finance Corporation’s outstanding shares of common stock.  Antero Resources LLC owns all of the outstanding shares of common stock of each of the operating subsidiaries.

 

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. This information reflects our November 2009 corporate restructuring and equity placements. See “Business—Corporate Sponsorship and Structure.” Except as other noted, information is presented as of March 15, 2011 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                                        |       | 38.7                                                                | %          |
| Yorktown Energy Partners(3)                                       |       |                                              |       |                                                                |       |
| 410 Park Avenue, 19th Floor                                       |       |                                              |       |                                                                |       |
| New York, NY 10022                                                |       | 15,942,448                                        |       | 10.9                                                                | %          |
| Trilantic Capital Partners(4)                                     |       |                                              |       |                                                                |       |
| 399 Park Avenue                                                   |       |                                              |       |                                                                |       |
| New York, NY 10022                                                |       | 12,471,533                                        |       | 8.5                                                                 | %          |
| Peter R. Kagan(5)                                                 |       | 56,557,133                                        |       | 38.7                                                                | %          |
| W. Howard Keenan, Jr.(6)                                     |       | 15,942,448                                        |       | 10.9                                                                | %          |
| Christopher R. Manning(7)                                         |       | 12,471,533                                        |       | 8.5                                                                 | %          |
| Paul M. Rady(8)                                                   |       | 21,125,461                                        |       | 14.4                                                                | %          |
| Glen C. Warren, Jr.(9)                                       |       | 14,083,641                                        |       | 9.6                                                                 | %          |
| Robert E. Mueller                                                 |       | 827,302                                           |       | 0.6                                                                 | %          |
| Alvyn A. Schopp                                                   |       | 855,574                                           |       | 0.6                                                                 | %          |
| Kevin J. Kilstrom                                                 |       | 530,653                                           |       | 0.4                                                                 | %          |
| Directors and officers as a group (12 persons)                    |       | 39,515,015                                        |       | 27.0                                                                | %          |

 

----

*                 Less than one percent.

 

(1)          Based on 146,288,521 total outstanding voting units at March 15, 2011.

 

(2)          The Warburg Pincus members are Warburg Pincus Private Equity VIII, L.P., a Delaware limited partnership (together with its two affiliated partnerships, “WP VIII”), 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, the “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 partnership, and an indirect subsidiary of WP X and WP X O&G.  Warburg Pincus X, L.P., a Delaware limited partnership (“WP X GP”), is the general partner of the 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.  Warburg Pincus Partners, LLC, a New York limited liability company (“WP Partners”) and a direct subsidiary of Warburg Pincus & Co., a New York general partnership (“WP”), is the sole member of WP X LLC and the sole general partner of WP.  WP is the managing member of WP Partners.  Warburg Pincus LLC, a New York limited liability company (“WP LLC”), is the manager of WP VIII, WP X Funds, and WP X O&G.

 

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(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 Trilantic Capital Partners III L.P., a Delaware limited partnership (together with its affiliated partnerships, “TCP III”), and Trilantic Capital Partners IV L.P., a Delaware limited partnership (together with its affiliated partnerships, “TCP IV”).  LB TCP Associates III L.P., a Delaware limited partnership (“TCP III GP”), is the general partner of TCP III.  Trilantic Capital Partners Associates IV L.P., a Delaware limited partnership (“TCP IV GP”) is the general partner of TCP IV.  Trilantic Capital Partners Associates MGP IV LLC, a Delaware limited liability company is the general partner of TCP IV GP and the ultimate general partner of TCP IV.  Trilantic Capital Management LLC, a Delaware limited liability company (“TCM”), is the investment adviser of TCP III and TCP IV.  Trilantic Capital Partners Executive LLC is the managing member of TCM.

 

(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.  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. Kagan, Kaye and Landy disclaim 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, Chairman of the Board and one of our directors, is the managing member of Salisbury Investment Holdings, LLC and the holdings of Mr. Rady reflected above include both the direct personal holdings of Mr. Rady and the holdings of Salisbury Investment Holdings, LLC.  Mr. Rady has sole voting and investment power over the units held by Salisbury Investment Holdings, LLC.

 

(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—Business—Corporate Sponsorship and Structure” 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

 

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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 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.

 

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**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 2010.  Because the Company was not an SEC registrant until 2010, not all fees paid in 2009 were pre-approved.

 

**Fees**

 

KPMG served as our independent registered public accounting firm during 2009 and 2010. 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,** | ** ** |
|--------------------|------------|------------------------------------------|------------|
| ** **         | ** ** | **2009**                                 | ** ** | **2010** | ** ** |
| Audit              |       | $                                        | 371,000    |   | $ | 779,000 |   |
| Audit-Related Fees |       | $                                        | 332,000    |   | $ | 217,000 |   |
| Tax Fees           |       | $                                        | 187,000    |   | $ | 232,000 |   |
| All Other Fees     |       | $                                        | 139,000    |   | $ | — |   |

 

All other fees in 2009 are for services performed to evaluate the Company’s processes and procedures.

 

**Item 15.****   ****Exhibits, Financial Statement Schedules**

 

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

 

See “Item 8. Financial Statements and Supplementary Data” beginning on page F-1(a).

 

**(a)(3) Exhibits.**

 
| **Exhibit    Number** | ** ** | **Description of Exhibits**                                                                                                                                                                                                                                                                                                        |
|----------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2.1                        |       | Purchase   and Sale Agreement by and among Antero Resources LLC, Antero Resources   Midstream Corporation and Cardinal Arkoma Midstream, LLC, dated as of   October 1, 2010 (incorporated by reference to Exhibit 2.1 to   Current Report on Form 8-K (Commission File No. 333-164876) filed   on October 4, 2010). |
|                       |       |                                                                                                                                                                                                                                                                                                                                         |
| 2.2                        |       | Stock   Purchase Agreement by and between Antero Resources LLC and Cardinal   Arkoma, Inc., dated as of October 1, 2010 (incorporated by   reference to Exhibit 2.2 to Current Report on Form 8-K (Commission   File No. 333-164876) filed on October 4, 2010).                                                |
|                       |       |                                                                                                                                                                                                                                                                                                                                         |
| 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).                                                                                                                       |

 

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| 3.3    |   | Certificate   of Formation of Antero Resources LLC (incorporated by reference to   Exhibit 3.3 to Registration Statement on Form S-4 (Commission File   No. 333-164876) filed on February 12, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |
|--------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 3.4    |   | Amended   and Restated Limited Liability Company Agreement of Antero Resources LLC   dated as of December 1, 2010 (incorporated by reference to Exhibit 3.1   to Current Report on Form 8-K (Commission File No. 333-164876)   filed on December 3, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 4.1    |   | Indenture   dated as of November 17, 2009 among Antero Resources Finance   Corporation, the several guarantors named therein, and Wells Fargo Bank,   National Association, as trustee (incorporated by reference to   Exhibit 4.1 to Registration Statement on Form S-4 (Commission File   No. 333-164876) filed on February 12, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 4.2    |   | Registration   Rights Agreement dated as of November 17, 2009 among Antero Resources   Finance Corporation, the several guarantors named therein, and the initial   purchasers named therein (incorporated by reference to Exhibit 4.2 to   Registration Statement on Form S-4 No. (Commission File   No. 333-164876) filed on February 12, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 4.3    |   | Registration   Rights Agreement dated as of January 19, 2010 among Antero Resources   Finance Corporation, the several guarantors named therein, and the initial   purchasers named therein (incorporated by reference to Exhibit 4.3 to   Registration Statement on Form S-4 (Commission File No. 333-164876)   filed on February 12, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 4.4    |   | Registration   Rights Agreement dated as of November 3, 2009 by and among Antero   Resources LLC and the other parties named therein (incorporated by reference   to Exhibit 4.4 to Registration Statement on Form S-4 No. (File   No. 333-164876) filed on February 12, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 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   |   | Amended   and Restated Farmout Acquisition Agreement dated September 23, 2008, by   and between Dominion Exploration & Production, Inc., Dominion   Transmission, Inc. and Dominion Appalachian Development, LLC and Antero   Resources Appalachian Corporation (incorporated by reference to Exhibit 10.7   to Amendment No. 1 to Registration Statement on Form S-4   (Commission File No. 333-164876) filed on April 30, 2010).                                                                                                                                                                                                                                                                                                                                                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.3   |   | Farmout   Agreement dated September 29, 2008 but effective September 30, 2008   by and between Dominion Exploration & Production, Inc.,   Dominion Transmission, Inc. and Dominion Appalachian Development, LLC   and Antero Resources Appalachian Corporation (incorporated by reference to   Exhibit 10.7 to Amendment No. 1 to Registration Statement on   Form S-4 (Commission File No. 333-164876) filed on April 30,   2010).                                                                                                                                                                                                                                                                                                                                                                                                                            |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 10.4   |   | 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).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| 21.1*  |   | Subsidiaries   of Antero Resources Finance Corporation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |

 

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| 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 Appalachian Basin properties.                                                                        |
|   |   |                                                                                                                                                          |
| 99.2*  |   | Summary   Report of DeGolyer and MacNaughton relating to Arkoma Basin Woodford Shale   and Fayetteville Shale properties.                                     |
|   |   |                                                                                                                                                          |
| 99.3*  |   | Summary   Report of Ryder Scott Company, L.P. relating to Piceance Basin properties.                                                                          |

 

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.

 

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**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:                      | April 11, 2012 |

 

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          |   | April   11, 2012 |
|------------------------------|--------|--------------------------------------------------------------|--------|------------------|
| Paul M. Rady                 |   | Officer (principal executive officer)                        |   |             |
|                         |   |                                                         |   |             |
| /s/ Glen C. Warren, Jr. |   | Director, President, Chief Financial Officer and Secretary   |   | April   11, 2012 |
| Glen C. Warren, Jr.     |   | (principal financial officer)                                |   |             |
|                         |   |                                                         |   |             |
| /s/ Alvyn A. Schopp          |   | Vice President—Accounting & Administration and |   | April   11, 2012 |
| Alvyn A. Schopp              |   | Treasurer (principal accounting officer)                     |   |             |
|                         |   |                                                         |   |             |
| /s/ Peter R. Kagan           |   | Director                                                     |   | April   11, 2012 |
| Peter R. Kagan               |   |                                                         |   |             |
|                         |   |                                                         |   |             |
| /s/ W. Howard Keenan, Jr.    |   | Director                                                     |   | April   11, 2012 |
| W. Howard Keenan, Jr.        |   |                                                         |   |             |
|                         |   |                                                         |   |             |
| /s/ Christopher R. Manning   |   | Director                                                     |   | April   11, 2012 |
| Christopher R. Manning       |   |                                                         |   |             |

 

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**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

** **

**Table of Contents**

** **
| ** **                                                                                                                                   | ** ** | **Page** |
|----------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|
|                                                                                                                                         |       |     |
| Report   of Independent Registered Public Accounting Firm                                                                                    |       | F-2      |
|                                                                                                                                         |       |     |
| Consolidated Balance Sheets as of December 31,   2009 and 2010                                                                          |       | F-3      |
|                                                                                                                                         |       |     |
| Consolidated Statements of Operations for the years ended   December 31, 2008, 2009, and 2010                                           |       | F-5      |
|                                                                                                                                         |       |     |
| Consolidated Statements of Members’ Equity and Comprehensive   Income (Loss) for the years ended December 31, 2008, 2009, and 2010 |       | F-6      |
|                                                                                                                                         |       |     |
| Consolidated Statements of Cash Flows for the years   ended December 31, 2008, 2009, and 2010                                           |       | F-7      |
|                                                                                                                                         |       |     |
| Notes to Consolidated Financial Statements                                                                                                   |       | F-8      |

 

F-1

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Table of Contents

 

**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 (the Company) as of December 31, 2009 and 2010, and the related consolidated statements of operations, members’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2010. 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 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 consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2009 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

 

/s/ KPMG LLP

 

Denver, Colorado March 30, 2011

 

F-2

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)

 
| ** **                                                                                                                 | ** ** | **2009**  | ** ** | **2010**  | ** ** |
|----------------------------------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|
| **Assets**                                                                                                                 |       |      |       |      |       |
| Current assets:                                                                                                            |       |      |       |      |       |
| Cash and cash equivalents                                                                                                  |       | $         | 10,669     |      | 8,988      |   |
| Accounts receivable – trade, net of allowance for   doubtful accounts of $424 and $272 in 2009 and 2010, respectively |       | 35,897    |       | 30,971    |       |
| Accrued revenue                                                                                                            |       | 17,459    |       | 24,868    |       |
| Prepaid expenses                                                                                                           |       | 7,419     |       | 7,087     |       |
| Derivative instruments                                                                                                     |       | 22,105    |       | 82,960    |       |
| Inventories                                                                                                                |       | 1,295     |       | 2,031     |       |
| Total current assets                                                                                                       |       | 94,844    |       | 156,905   |       |
| Property and equipment:                                                                                                    |       |      |       |      |       |
| Natural gas properties, at cost (successful   efforts method):                                                             |       |      |       |      |       |
| Unproved properties                                                                                                        |       | 596,694   |       | 737,358   |       |
| Producing properties                                                                                                       |       | 1,340,827 |       | 1,762,206 |       |
| Gathering systems and facilities                                                                                           |       | 185,688   |       | 85,404    |       |
| Other property and equipment                                                                                               |       | 3,302     |       | 5,975     |       |
|                                                                                                                       |       | 2,126,511 |       | 2,590,943 |       |
| Less accumulated depletion, depreciation, and   amortization                                                               |       | (322,992  | )          | (431,181  | )          |
| Property and equipment, net                                                                                                |       | 1,803,519 |       | 2,159,762 |       |
| Derivative instruments                                                                                                     |       | 18,989    |       | 147,417   |       |
| Other assets, net                                                                                                          |       | 19,214    |       | 22,203    |       |
| Total assets                                                                                                               |       | $         | 1,936,566  |      | 2,486,287  |   |

 

(Continued)

 

F-3

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Consolidated Balance Sheets

December 31, 2009 and 2010

(In thousands)

 
| ** **                                         | ** ** | **2009**  | ** ** | **2010**  | ** ** |
|----------------------------------------------------|------------|-----------|------------|-----------|------------|
| **Liabilities   and Equity**                       |       |      |       |      |       |
| Current liabilities:                               |       |      |       |      |       |
| Accounts payable                                   |       | $         | 48,594     |      | 82,436     |   |
| Accrued expenses                                   |       | 24,572    |       | 21,746    |       |
| Revenue distributions payable                      |       | 29,304    |       | 29,917    |       |
| Advances from joint interest owners                |       | 1,400     |       | 1,478     |       |
| Derivative instruments                             |       | 8,623     |       | 4,212     |       |
| Deferred income tax liability                      |       | —    |       | 12,694    |       |
| Total current liabilities                          |       | 112,493   |       | 152,483   |       |
| Long-term liabilities:                             |       |      |       |      |       |
| Bank credit facility                               |       | 142,080   |       | 100,000   |       |
| Senior notes                                       |       | 372,397   |       | 527,632   |       |
| Long-term note                                     |       | —    |       | 25,000    |       |
| Derivative instruments                             |       | 2,464     |       | —    |       |
| Asset retirement obligations                       |       | 3,487     |       | 5,374     |       |
| Deferred income tax liability                      |       | 424       |       | 77,489    |       |
| Other long-term liabilities                        |       | 4,114     |       | 3,322     |       |
| Total liabilities                                  |       | 637,459   |       | 891,300   |       |
| Equity:                                            |       |      |       |      |       |
| Members’ equity                               |       | 1,392,833 |       | 1,489,806 |       |
| Accumulated earnings (deficit)                     |       | (123,447  | )          | 105,181   |       |
| Total Antero equity                                |       | 1,269,386 |       | 1,594,987 |       |
| Noncontrolling interest in consolidated subsidiary |       | 29,721    |       | —    |       |
| Total equity                                       |       | 1,299,107 |       | 1,594,987 |       |
| Total liabilities and equity                       |       | $         | 1,936,566  |      | 2,486,287  |   |

 

See accompanying notes to consolidated financial statements.

 

F-4

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**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Consolidated Statements of Operations

Years ended December 31, 2008, 2009, and 2010

(In thousands)

 
| ** **                                                                                                                                                                             | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Revenue:                                                                                                                                                                               |       |     |       |     |       |     |       |
| Natural gas sales                                                                                                                                                                      |       | $        | 220,219    |     | 123,915    |     | 197,991    |   |
| Oil sales                                                                                                                                                                              |       | 9,496    |       | 5,706    |       | 8,471    |       |
| Realized and unrealized gain on commodity   derivative instruments (including unrealized gains (losses) of $90,301,   $(61,186) and $170,571 in 2008, 2009, and 2010, respectively)    |       | 116,354  |       | 55,364   |       | 244,284  |       |
| Gas gathering and processing revenue                                                                                                                                                   |       | 20,421   |       | 23,005   |       | 20,554   |       |
| Gain on sale of Oklahoma midstream assets                                                                                                                                              |       | —   |       | —   |       | 147,559  |       |
| Total revenue                                                                                                                                                                          |       | 366,490  |       | 207,990  |       | 618,859  |       |
| Operating expenses:                                                                                                                                                                    |       |     |       |     |       |     |       |
| Lease operating expenses                                                                                                                                                               |       | 13,350   |       | 17,606   |       | 25,511   |       |
| Gathering, compression, and transportation                                                                                                                                             |       | 29,033   |       | 28,190   |       | 45,809   |       |
| Production taxes                                                                                                                                                                       |       | 10,281   |       | 4,940    |       | 8,777    |       |
| Exploration expenses                                                                                                                                                                   |       | 22,998   |       | 10,228   |       | 24,794   |       |
| Impairment of unproved properties                                                                                                                                                      |       | 10,112   |       | 54,204   |       | 35,859   |       |
| Depletion, depreciation, and amortization                                                                                                                                              |       | 124,821  |       | 139,813  |       | 133,955  |       |
| Accretion of asset retirement obligations                                                                                                                                              |       | 176      |       | 265      |       | 317      |       |
| Expenses related to business acquisition                                                                                                                                               |       | —   |       | —   |       | 2,544    |       |
| General and administrative                                                                                                                                                             |       | 16,171   |       | 20,843   |       | 21,952   |       |
| Total operating expenses                                                                                                                                                               |       | 226,942  |       | 276,089  |       | 299,518  |       |
| Operating income (loss)                                                                                                                                                                |       | 139,548  |       | (68,099  | )          | 319,341  |       |
| Other expense:                                                                                                                                                                         |       |     |       |     |       |     |       |
| Interest expense                                                                                                                                                                       |       | (37,594  | )          | (36,053  | )          | (56,463  | )          |
| Realized and unrealized losses on interest   derivative instruments, net (including unrealized gains (losses) of $(13,817),   $6,163, and $6,875 in 2008, 2009 and 2010, respectively) |       | (15,245  | )          | (4,985   | )          | (2,677   | )          |
| Total other expense                                                                                                                                                                    |       | (52,839  | )          | (41,038  | )          | (59,140  | )          |
| Income (loss) before income taxes                                                                                                                                                      |       | 86,709   |       | (109,137 | )          | 260,201  |       |
| Income tax (expense) benefit                                                                                                                                                           |       | (3,029   | )          | 2,605    |       | (30,009  | )          |
| Net income (loss)                                                                                                                                                                      |       | 83,680   |       | (106,532 | )          | 230,192  |       |
| Noncontrolling interest in net loss (income) of   consolidated subsidiary                                                                                                              |       | 276      |       | 363      |       | (1,564   | )          |
| Net income (loss) attributable to Antero equity   owners                                                                                                                               |       | $        | 83,956     |     | (106,169   | )        | 228,628    |   |

 

See accompanying notes to consolidated financial statements.

 

F-5

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**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Consolidated Statements of Equity and Comprehensive Income (Loss)

Years ended December 31, 2008, 2009, and 2010

(In thousands)

 
| ** **                                                                                                         | ** ** | ** **        | ** ** | ** **    | ** ** | ** ** | ** ** | **Capital in** | ** ** | ** **      | ** ** | ** **            | ** ** | ** **         | ** ** | ** ** | ** ** |
|--------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|---------------|------------|------------|------------|---------------------|------------|-----------------|------------|-----------------------|------------|--------------------|------------|------------|------------|
| ** **                                                                                                         | ** ** | **Members’** | ** ** | **Preferred** | ** ** | **Common** | ** ** | **excess of**  | ** ** | **Accumulated** | ** ** | **Total Antero** | ** ** | **Noncontrolling** | ** ** | **Total**  | ** ** |
| ** **                                                                                                         | ** ** | **equity**        | ** ** | **stock**     | ** ** | **stock**  | ** ** | **par value**  | ** ** | **deficit**     | ** ** | **equity**            | ** ** | **interest**       | ** ** | **equity** | ** ** |
| Balances, December 31, 2007                                                                                   |       | $                 | —     |          | 493,005    |       | 145        |                | 384        |            | (99,232    | )                     | 394,302    |               | —     |       | 394,302    |   |
| Issuance of preferred stock                                                                                        |       | —            |       | 670,000       |       | —     |       | —              |       | —          |       | 670,000               |       | —             |       | 670,000    |       |
| Stock compensation                                                                                                 |       | —            |       | —        |       | 29         |       | 241                 |       | —          |       | 270                   |       | —             |       | 270        |       |
| Sale of noncontrolling interest in Centrahoma                                                                      |       | —            |       | —        |       | —     |       | —              |       | —          |       | —                |       | 29,594             |       | 29,594     |       |
| Other                                                                                                              |       | —            |       | —        |       | —     |       | (291                | )          | —          |       | (291                  | )          | —             |       | (291       | )          |
| Net income and comprehensive income                                                                                |       | —            |       | —        |       | —     |       | —              |       | 83,956          |       | 83,956                |       | (276               | )          | 83,680     |       |
| Balances, December 31, 2008                                                                                   |       | —            |       | 1,163,005     |       | 174        |       | 334                 |       | (15,276         | )          | 1,148,237             |       | 29,318             |       | 1,177,555  |       |
| Issuance of preferred stock, net of issuance costs   of $1                                                         |       | —            |       | 105,000       |       | —     |       | (1                  | )          | —          |       | 104,999               |       | —             |       | 104,999    |       |
| Stock compensation                                                                                                 |       | —            |       | —        |       | —     |       | 2,822               |       | —          |       | 2,822                 |       | —             |       | 2,822      |       |
| Cancellation of stock option plan                                                                                  |       | —            |       | —        |       | —     |       | (1,717              | )          | (2,002          | )          | (3,719                | )          | —             |       | (3,719     | )          |
| Return of capital to common stockholders                                                                           |       | —            |       | —        |       | —     |       | (345                | )          | —          |       | (345                  | )          | —             |       | (345       | )          |
| Exchange of preferred stock and common stock in   Antero entities for members’ equity in Antero Resources LLC |       | 1,269,272         |       | (1,268,005    | )          | (174       | )          | (1,093              | )          | —          |       | —                |       | —             |       | —     |       |
| Issuance of equity net of issuance costs of $1,439                                                                 |       | 123,561           |       | —        |       | —     |       | —              |       | —          |       | 123,561               |       | —             |       | 123,561    |       |
| Contribution received from noncontrolling interest                                                                 |       | —            |       | —        |       | —     |       | —              |       | —          |       | —                |       | 766                |       | 766        |       |
| Net loss and comprehensive loss                                                                                    |       | —            |       | —        |       | —     |       | —              |       | (106,169        | )          | (106,169              | )          | (363               | )          | (106,532   | )          |
| 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  |   |

 

See accompanying notes to consolidated financial statements.

 

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Consolidated Statements of Cash Flows

Years ended December 31, 2008, 2009, and 2010

(In thousands)

 
| ** **                                                                                | ** ** | **2008**   | ** ** | **2009**   | ** ** | **2010**   | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|
| Cash flows from operating activities:                                                     |       |       |       |       |       |       |       |
| Net income (loss)                                                                         |       | $          | 83,680     |       | (106,532   | )          | 230,192    |   |
| Adjustment to reconcile net income (loss) to net   cash provided by operating activities: |       |       |       |       |       |       |       |
| Depletion, depreciation, and amortization                                                 |       | 124,821    |       | 139,813    |       | 133,955    |       |
| Dry hole costs                                                                            |       | 6,582      |       | 1,671      |       | 19,471     |       |
| Impairment of unproved properties                                                         |       | 10,112     |       | 54,204     |       | 35,859     |       |
| Accretion of asset retirement obligations                                                 |       | 176        |       | 265        |       | 317        |       |
| Accretion of bond discount (premium), net                                                 |       | —     |       | 26         |       | (361       | )          |
| Amortization and write-off of deferred financing   costs                                  |       | 1,283      |       | 7,268      |       | 4,052      |       |
| Stock compensation                                                                        |       | 269        |       | 2,822      |       | —     |       |
| Unrealized (gains) losses on derivative   instruments, net                                |       | (76,484    | )          | 55,023     |       | (177,446   | )          |
| Deferred taxes                                                                            |       | 3,029      |       | (2,605     | )          | 30,009     |       |
| Gain on sale of midstream assets                                                          |       | —     |       | —     |       | (147,559   | )          |
| Changes in current assets and liabilities:                                                |       |       |       |       |       |       |       |
| Accounts receivable                                                                       |       | (17,641    | )          | 19,169     |       | (4,306     | )          |
| Accrued revenue                                                                           |       | (3,798     | )          | 1,346      |       | (7,408     | )          |
| Prepaid expenses                                                                          |       | (5,973     | )          | 196        |       | 1,079      |       |
| Inventories                                                                               |       | (1,005     | )          | 553        |       | (818       | )          |
| Accounts payable                                                                          |       | 3,713      |       | (16,730    | )          | 9,779      |       |
| Accrued expenses                                                                          |       | 5,984      |       | 1,470      |       | (2,849     | )          |
| Revenue distributions payable                                                             |       | 17,306     |       | (2,159     | )          | 1,747      |       |
| Advance from joint interest owners                                                        |       | 5,461      |       | (6,493     | )          | 78         |       |
| Net cash provided by operating activities                                                 |       | 157,515    |       | 149,307    |       | 125,791    |       |
| Cash flows from investing activities:                                                     |       |       |       |       |       |       |       |
| Proved property acquisitions                                                              |       | (3,466     | )          | (1,029     | )          | —     |       |
| Additions to unproved properties                                                          |       | (457,879   | )          | (16,118    | )          | (41,277    | )          |
| Drilling costs                                                                            |       | (512,112   | )          | (258,520   | )          | (299,926   | )          |
| Additions to gathering systems and facilities                                             |       | (51,964    | )          | (5,819     | )          | (47,124    | )          |
| Additions to other property and equipment                                                 |       | (1,674     | )          | (188       | )          | (2,647     | )          |
| Increase in other assets                                                                  |       | (1,479     | )          | (225       | )          | (556       | )          |
| Sale of noncontrolling interest in subsidiary                                             |       | 24,564     |       | —     |       | —     |       |
| Proceeds from sale of midstream assets                                                    |       | —     |       | —     |       | 258,918    |       |
| Net assets of business acquired, net of cash of   $170                                    |       | —     |       | —     |       | (96,060    | )          |
| Net cash used in investing activities                                                     |       | (1,004,010 | )          | (281,899   | )          | (228,672   | )          |
| Cash flows from financing activities:                                                     |       |       | ** ** | ** ** | ** ** | ** ** | ** ** |
| Borrowings on treasury management revolving note   payable, net                           |       | (6,307     | )          | —     |       | —     |       |
| Issuance of senior notes                                                                  |       | —     |       | 372,371    |       | 156,000    |       |
| Borrowings on bank credit facility                                                        |       | 279,200    |       | 170,000    |       | 324,000    |       |
| Payments on bank credit facility                                                          |       | (72,000    | )          | (424,500   | )          | (366,080   | )          |
| Repayment of second lien term note                                                        |       | —     |       | (225,000   | )          |       |       |
| Payments of deferred financing costs                                                      |       | (758       | )          | (17,845    | )          | (10,459    | )          |
| Issuance of preferred stock                                                               |       | 670,000    |       | 105,000    |       | —     |       |
| Issuance of members’ equity                                                          |       | —     |       | 125,000    |       | —     |       |
| Net cash received (paid) from (to) noncontrolling   interest                              |       | 4,623      |       | 1,176      |       | (2,507     | )          |
| Return of capital to common stockholders                                                  |       | —     |       | (345       | )          | —     |       |
| Equity issuance cost                                                                      |       | (291       | )          | (1,440     | )          | (27        | )          |
| Other                                                                                     |       | (117       | )          | (125       | )          | 273        |       |
| Net cash provided by financing activities                                                 |       | 874,350    |       | 104,292    |       | 101,200    |       |
| Net increase (decrease) in cash and cash   equivalents                                    |       | 27,855     |       | (28,300    | )          | (1,681     | )          |
| Cash and cash equivalents, beginning of year                                              |       | 11,114     |       | 38,969     |       | 10,669     |       |
| Cash and cash equivalents, end of year                                                    |       | $          | 38,969     |       | 10,669     |       | 8,988      |   |
| Supplemental disclosure of cash flow information:                                         |       |       |       |       |       |       |       |
| Cash paid during the year for interest                                                    |       | $          | 38,896     |       | 28,395     |       | 52,326     |   |
| Supplemental disclosure of noncash investing   activities:                                |       |       |       |       |       |       |       |
| Changes in accounts payable for additions to   properties, systems, and facilities        |       | $          | 14,653     |       | (78,220    | )          | 32,028     |   |

 

See accompanying notes to consolidated financial statements.

 

F-7

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

** **

**(1)****      ****Organization**

*** ***

***(a)******      ******Business and Organization***

 

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

 

Our consolidated financial statements as of December 31, 2010 include the accounts of Antero Resources LLC, and its directly and indirectly owned subsidiaries. The subsidiaries include Antero Resources Corporation (Antero Arkoma), Antero Resources Piceance Corporation (Antero Piceance), Antero Resources Pipeline Corporation (Antero Pipeline), Antero Resources Appalachian Corporation and its subsidiary, Antero Resources Bluestone LLC (Antero Appalachian), and Antero Resources Finance Corporation (Antero Finance) (collectively referred to as the Antero Entities). The financial statements as of December 31, 2008 include the combined accounts of the Antero Entities, when ownership was under common control; the outstanding equity instruments of these operating entities were held by the same individuals or entities in the same percentage. In October 2009, the equity structure was reorganized in a nontaxable transaction by the formation of Antero Resources LLC, which issued units of members’ equity to the stockholders of the operating entities in exchange for all of their preferred and common shares in each operating entity. The assets and liabilities of each of the operating entities are included for all periods presented at their historical basis.

*** ***

***(b)******      ******Sale of Oklahoma Midstream Operations***

 

On November 5, 2010, the Company sold its investment in Antero Midstream Corporation (Midstream) and Midstream’s 60% ownership interest in Centrahoma Processing LLC. The Company realized a gain of approximately $147.6 million on the sale. The Company used the net proceeds from the sale of approximately $258.9 million to pay down outstanding borrowings under its revolving credit facility and for working capital. The results of operations for Midstream are included in our consolidated results through the date of the sale.

** **

**(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 requiring disclosure were identified.

 

(Continued)

 

F-8

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Table of Contents

** **

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***(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 future reserves, and impairment of oil and gas properties. Reserve estimates by their nature are inherently imprecise.

*** ***

***(c)******       ******Risks and Uncertainties***

 

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

*** ***

***(d)******      ******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 such 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

 

(Continued)

 

F-9

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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 for leases which have expired or are expected to expire was $10.1 million, $54.2 million, and $35.9 million for the years ended December 31, 2008, 2009, and 2010, 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 properties to their estimated fair value. The factors used to determine fair value include estimates of proved reserves, future commodity prices, 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, 2008, 2009, and 2010.

 

At December 31, 2010, the Company had capitalized costs related to exploratory wells-in-progress, which were pending determination of proved reserves of $78.9 million. The Company had no costs which have been deferred for longer than one year pending proved reserves at December 31, 2010.

 

The provision for depreciation, depletion, and amortization of oil and gas properties is calculated on a geological reservoir basis using the units-of-production method. Depreciation, depletion, and amortization expense for oil and gas properties was $116.9 million, $130.1 million, and $124.3 million for the years ended December 31, 2008, 2009, and 2010, respectively.

*** ***

***(f)******       ******Inventories***

 

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

*** ***

***(g)******      ******Gathering Systems***

 

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, 2008, 2009, and 2010, depreciation expense for gathering systems and processing facilities was $7.5 million, $9.0 million, and $8.8 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

 

(Continued)

 

F-10

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

discounted future cash flows or other techniques, as appropriate. No impairments for such assets have been recorded through December 31, 2010.

 

***(i)******       ******Other Property and Equipment***

 

Other property and equipment, consisting of vehicles and office equipment, is depreciated using the straight-line method over estimated useful lives ranging from three to five years. For the years ended December 31, 2008, 2009, and 2010, depreciation expense for other property and equipment was $390,000, $660,000, and $839,000, respectively. A gain or loss is recognized upon the sale or disposal of property and equipment.

*** ***

***(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 notes 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 and for deferred charges relating to parties to its bank credit facility who do not continue to participate. The amounts amortized and the write-off of previously deferred debt issuance costs were $1.3 million, $7.3 million, and $4.1 million for the years ended December 31, 2008, 2009, and 2010, 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).

*** ***

***(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

 

(Continued)

 

F-11

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Table of Contents

** **

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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. We 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 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, 2009 and 2010, the Company has not accrued 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 and Oil Revenues***

 

The Company utilizes the accrual method of accounting for oil and natural gas revenues, whereby revenues are recognized as the Company’s entitlement share of oil and natural gas 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 of oil and natural gas revenues. At December 31, 2009 and 2010, the Company had no significant imbalance positions.

*** ***

***(o)******      ******Gathering and Processing Fees Revenue***

 

The Company utilizes the accrual method of accounting for gas processing fee revenues. The amount of revenue is determinable when the sale of the applicable product has been completed. Service fees are recognized as revenue when services are performed.

 

The Company obtains access to unprocessed natural gas and provides services to customers under a processing agreement. The processing agreement contains a fee-based provision, whereby the Company receives a fee based on the volume of natural gas processed. In addition, proceeds from selling natural gas liquids (NGLs) are remitted back to customers based on a contractual calculation of the liquids available for separation, as determined from an analysis of the raw natural gas received. The margin earned on NGLs sold in excess of payments made to the customers is not directly dependant on the value of these products and is reported net.

 

The Company sold its Oklahoma midstream assets in November 2010. See note 1(b).

 

(Continued)

 

F-12

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Table of Contents

*** ***

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

*** ***

***(p)******      ******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, 2008, 2009, and 2010 are as follows:

 
| ** ** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
|------------|------------|----------|------------|----------|------------|----------|------------|
| Company A  |       | 49       | %          | 44       | %          | 23       | %          |
| Company B  |       | 41       |       | 15       |       | 13       |       |
| Company C  |       | —   |       | 12       |       | 11       |       |
| All others |       | 10       |       | 29       |       | 53       |       |
|       |       | 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.

 

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

*** ***

***(q)******      ******Stock Compensation***

 

Awards of membership interests to the Antero Resources Employee Holdings LLC (Antero Holdings) are classified as liability instruments because the method of settlement is not within the Company’s control. Compensation expense for these awards is recognized when all performance, market, and service conditions are probable of being satisfied.

 

Prior to the formation of Antero Resources LLC, the Antero Entities granted various equity awards to certain employees. The estimated fair value of restricted stock at the date of the award was charged to expense over the vesting period of the award. The estimated fair value of stock option awards was charged to expense over the service period of the award. Fair value of stock option awards was estimated using the Black Scholes option pricing model. These awards were canceled in connection with the reorganization of the Company’s ownership structure in November 2009 and compensation was recorded at the time of cancelation. No stock compensation was recognized in 2010.

 

***(r)******       ******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.

 

(Continued)

 

F-13

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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. At December 31, 2009 and 2010, the Company has no unrecognized tax benefits from uncertain tax positions that would impact the Company’s effective tax rate and has made no provisions for interest or penalties related to uncertain tax positions. The tax years 2007 through 2010 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 2006 through 2010.

*** ***

***(s)******       ******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 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.

 

(Continued)

 

F-14

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***(t)******       ******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)****      ****Acquisitions**

 

Much of the Company’s acquisition and development activity in the Arkoma and Piceance Basins has been through the acquisition of unproved properties involving individually insignificant costs and subsequent Company-operated drilling and development activity on internally generated prospects on those properties. The following describes significant transactions to acquire unproved and proved properties during the three years ended December 31, 2010:

* *

*Antero Piceance* — In July 2008, Antero Piceance acquired 21 producing wells, unproved acreage, and the related gathering assets in Garfield County, Colorado for $39.2 million. The allocation of the purchase price was approximately $35.7 million for nonproducing leasehold costs and $3.5 million for proved properties.

* *

*Antero Appalachian* — On September 30, 2008, Antero Appalachian acquired deep rights in properties, including the Marcellus Shale formation on approximately 114,000 net acres in the Appalachian Basin in southwestern Pennsylvania and northern West Virginia. The purchase price was approximately $347 million and was allocated to unproved property. The acquisition agreement contains various drilling commitments which requires Antero Appalachian to drill 179 wells at intervals specified in the agreement over a seven-year period. As of December 31, 2010, the Company has met its required cumulative drilling commitment of 24 wells, and has an additional 30 wells in various stages of drilling or completion. If the Company does not fulfill its drilling commitments, portions of the unproved property may revert to the seller.

 

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. Much of the acreage acquired is in close proximity and adjacent to the Company’s existing holdings in the Appalachian Basin. Of the 96 purchased wells, 47 are completed in the Marcellus formation and the balance in other shallow formations. Of the 47 Marcellus wells, three are horizontal Marcellus producers which account for 68% of the net production of the 96 purchased wells.

 

(Continued)

 

F-15

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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, 2010) |   | $      | 2.5    |   |
| Fair values of identifiable assets acquired and   liabilities assumed:                                                                                 |   |   |   |
| Current assets                                                                                                                                         |   | $      | 17.2   |   |
| Property, plant, and equipment:                                                                                                                        |   |   |   |
| 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  |   |

 

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 I-5 and B-6 units 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.

 

The amounts of BEP’s revenue and income included in the consolidated statement of operations for Antero Resources LLC for the year ended December 31, 2010, and the revenue and income (loss) of the combined entity had the acquisition date been January 1, 2009, are (in millions):

 
| ** **                                                         | ** ** | ** **  | ** ** | **Income** | ** ** |
|--------------------------------------------------------------------|------------|-------------|------------|------------|------------|
| ** **                                                         | ** ** | **Revenue** | ** ** | **(loss)** | ** ** |
| Actual from December 1, 2010 through   December 31, 2010 |       | $           | 1.0        |       | (0.3       | ) |
| Supplemental pro forma for the year ended   December 31, 2010 |       | 641.7       |       | 233.3      |       |
| Supplemental pro forma for the year ended   December 31, 2009 |       | 236.8       |       | (97.1      | )          |
|                                                                    |            |             |            |            |            |  |

 

(Continued)

 

F-16

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

**(4)****      ****Credit Facilities**

*** ***

***(a)******      ******Bank Credit Facility***

 

On November 4, 2010, the Company entered into an amended and restated credit agreement (Credit Facility) with its lenders increasing the maximum amount of its revolving credit facility from $400 million to $1 billion. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our proved reserves and are subject to regular semiannual redeterminations. The initial borrowing base was set at $550 million. The next semiannual redetermination of the borrowing base was scheduled to occur in April 2011.

 

The Credit Facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. All advances are due and payable on November 4, 2015. The Credit Facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and leverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with its financial debt covenants as of December 31, 2009 and 2010.

 

As of December 31, 2010, the Company had an outstanding balance under the Credit Facility of $100 million, with a weighted average interest rate of 2.56%, and outstanding letters of credit of approximately $18.1 million. Outstanding borrowings at December 31, 2009 were $142 million and $3.0 million of letters of credit. The Company pays commitment fees of 0.50% of the unused borrowing base.

*** ***

***(b)******      ******Senior Notes***

 

On November 17, 2009, an indirect wholly owned finance subsidiary of Antero Resources LLC, Antero Finance, issued $375 million of 9.375% senior notes due December 1, 2017 at a discount of $2.6 million. In January 2010, the Company issued an additional $150 million of the same series of 9.375% senior notes at a premium of $6 million. The notes are unsecured and subordinate 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. In addition, on or before December 1, 2012, Antero Finance may redeem up to 35% of the aggregate principal amount of the notes with the net cash proceeds of certain equity offerings, if certain conditions are met, at a redemption price of 109.375%. At any time prior to December 1, 2013, Antero Finance may also redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes plus a “make-whole” premium. If Antero Resources LLC undergoes a change of control, Antero Finance may be required to offer to purchase notes from the holders. Antero Resources Corporation, 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.

 

(Continued)

 

F-17

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Table of Contents

 

**ANTERO RESOURCES LLC****AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

The Company has unamortized underwriting discounts and other offering costs aggregating approximately $12.3 million, which were recorded as deferred financing costs in other long-term assets and are being amortized over the life of the notes using the effective interest method.

*** ***

***(c)******       ******Treasury Management Facility***

 

On September 14, 2010, the Company executed a stand-alone revolving note with a lender under the senior credit facility which provides for up to $7.5 million of cash management obligations in order to facilitate the Company’s daily treasury management. Borrowings under the revolving note are secured by the collateral for the revolving credit facility. Borrowings under the facility bear interest at the lender’s prime rate plus 1.0%. The note matures on September 12, 2011. At December 31, 2010, there were no outstanding borrowings under this facility.

*** ***

***(d)******      ******Note Payable***

 

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

** **

**(5)****      ****Asset Retirement Obligations**

 

The following is a reconciliation of the Company’s ARO for the years ended December 31, 2009 and 2010 (in thousands).

 
| ** **                                            | ** ** | **2009** | ** ** | **2010** | ** ** |
|-------------------------------------------------------|------------|----------|------------|----------|------------|
| Asset retirement obligations — beginning of year |       | $        | 3,034      |     | 3,487      |   |
| Obligations incurred                                  |       | 188      |       | 332      |       |
| Obligations assumed in business acquisition           |       | —   |       | 1,243    |       |
| Accretion expense                                     |       | 265      |       | 312      |       |
| Asset retirement obligations — end of year       |       | $        | 3,487      |     | 5,374      |   |

 

The fair value of obligations incurred is valued utilizing Level 3 inputs.

** **

**(6)****      ****Reorganization of Ownership Structure**

 

Since the inception of the Antero Entities in 2004, the Company has raised capital from private equity, institutional, and management investors through the issuance of various classes of preferred stock and common stock by the Antero Entities, each of which were owned by the same investors having substantially identical ownership in each of the entities. The Company also awarded preferred stock and common stock shares to various members of management and employees in the form of restricted share awards with restrictions that lapse over time. The Company also granted options to purchase shares of common stock to various members of management and employees.

 

On November 3, 2009, the stockholders of the Antero Entities contributed their shares of preferred stock and common stock to a newly formed entity, Antero Resources LLC, in exchange for an equivalent number of Class I-1, I-2, and I-3 units and Class A-1, A-3, B-1, B-3, and B-5 units in the Company. The newly issued units in Antero Resources LLC are substantially similar in character to the contributed stock in the Antero Entities, including the relative rights in the equity of the newly formed LLC. The exchange was

 

(Continued)

 

F-18

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

accounted for at the historical amounts recorded for the common stock and preferred stock and the basis in the assets of the Antero Entities was not changed. Outstanding stock options were canceled and the Company paid the excess of the fair value of the underlying stock over the exercise price of the options to the employees in cash in 2010.

 

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

 

In November 2009, Antero Resources LLC issued new Class I-4 units for $125 million and incurred approximately $1.4 million of offering costs for the new units. The proceeds of this equity placement were used to repay a portion of the borrowings outstanding under the senior secured revolving credit facility.

 

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 3).

 

At December 31, 2010, 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             |       |

 

At December 31, 2010, 164,926 restricted units are outstanding and not vested under the terms of the awards in the Antero Entities for which they were exchanged.

 

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 convertible into indebtedness. The Company has no obligation to repurchase these units at the election of the unit holders.

 

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 Antero Entity, a portion of the proceeds is allocated to the employees of the Company based on a requisite return financial threshold. In general, distributions are made first to holders of the Class I units until they have received their investment amount and an 8% special allocation and then, as a group, to the holders of all classes of units together. The Class I units participate on a pro rata basis with the other classes of units in funds available for distributions in excess of the Class I unit investment and special allocation amounts.

 

(Continued)

 

F-19

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

At December 31, 2010, the Class I units have an aggregate liquidation priority, including the special allocation of 8% per annum, of $1.86 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 sufficient for the members to fund income tax liabilities for partnership income allocated to them. As a result of the gain recognized on the sale of Midstream by Antero Resources LLC for the year ended December 31, 2010, the Company distributed approximately $28.9 million to the members in February 2011.

 

**(7)****                    ****Stock Compensation**

 

Prior to the reorganization of the ownership structure described in note 6, the Antero Entities had granted various equity compensation awards in the form of restricted shares of preferred and common stock as well as stock options. The restricted share awards were exchanged for restricted units in Antero Resources LLC. The stock option plans were terminated and the Company agreed with the holders to cash settle the options for the difference between the fair market value of the stock underlying the options at the date of the plan termination and the exercise price of the options. The plan termination liabilities in the amount of $3.7 million were accrued as a liability and charged to additional paid-in capital in November 2009. Unamortized stock option expense related to the terminated options of $440,000 was charged to stock compensation expense in 2009. There was no compensation expense related to stock awards in 2010 and no unamortized stock expense at December 31, 2010.

 

The Antero Entities had reserved 3,240,000 shares of Class A common stock and 12,881,562 shares of Class C common stock for the granting of options to directors, consultants, and employees. The term of the options was seven years and the options vested in equal installments over four years from the earlier of the optionee’s original date of employment or grant date.

 

The fair value of each option award was estimated on the date of grant using the Black-Scholes option pricing model and the weighted average assumptions in the following table. The Company used historical data to estimate the expected term of the option, such as employee option exercise and employee post— vesting departure behavior. The Company used peer group data to estimate volatility. Separate groups of employees that have similar historical exercise behavior were considered separately for valuation purposes. The risk-free rate for the expected term of the option was based on the U.S. Treasury yield curve in effect at the time of grant. The Company granted certain options at the date of the reorganization of the ownership structure described in note 6, which were 100% vested at the date of grant. The Company charged compensation expense for these option grants for $1.3 million, the amount for which the Company agreed to settle the options at the date of the reorganization.

 

|                     | ** ** | **2008**             |
|--------------------------|------------|----------------------|
| Valuation   assumptions: |       |                 |
| Expected dividend yield  |       | None                 |
| Expected volatility      |       | 22.00% – 40.00% |
| Expected term (years)    |       | 4.75                 |
| Risk-free interest rate  |       | 1.52% – 3.49%   |

 

(Continued)

 

F-20

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***Stock Compensation Expense***

 

Stock compensation expense is summarized as follows for the years ended December 31, 2008 and 2009 (in thousands):

 
| Year ended December 31, 2009:     |   |   |   |
|----------------------------------------|--------|--------|--------|
| Preferred stock awards                 |   | $      | 189    |   |
| Common stock awards                    |   | 623    |   |
| Stock options                          |   | 2,010  |   |
| Total stock-based compensation expense |   | $      | 2,822  |   |
| Year ended December 31, 2008:     |   |   |   |
| Preferred stock awards                 |   | $      | 30     |   |
| Common stock awards                    |   | (45    | )      |
| Stock options                          |   | 285    |   |
| Total stock-based compensation expense |   | $      | 270    |   |

 
| ** **                                                                                  | ** ** | **Antero** | ** ** | **Antero**   | ** ** | ** **    | ** ** | **Antero**   | ** ** | **Antero**      | ** ** |
|---------------------------------------------------------------------------------------------|------------|------------|------------|--------------|------------|---------------|------------|--------------|------------|-----------------|------------|
| ** **                                                                                  | ** ** | **Arkoma** | ** ** | **Piceance** | ** ** | **Midstream** | ** ** | **Pipeline** | ** ** | **Appalachian** | ** ** |
| Weighted average grant date fair value of restricted   shares granted (per share):          |       |       |       |         |       |          |       |         |       |            |       |
| 2009                                                                                        |       | $          | —     |         | —     |          | 18.51      |         | 36.52      |            | —     |   |
| 2008                                                                                        |       | 5.74       |       | 0.58         |       | 0.12          |       | 0.12         |       | —          |       |
| Weighted average grant date fair value of   Class C share options granted (per share): |       |       |       |         |       |          |       |         |       |            |       |
| 2009                                                                                        |       | $          | 4.00       |         | 0.78       |          | 17.56      |         | —     |            | 1.57       |   |
| 2008                                                                                        |       | 0.27       |       | 0.66         |       | 4.40          |       | —       |       | 0.01            |       |

 

(Continued)

 

F-21

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

** **

**(8)****                    ****Membership Interests Awards**

 

In connection with the reorganization of the Company’s ownership structure in November 2009 and cancellation of the stock option plans, the Company issued membership interests in Antero Resources Employee Holdings LLC, a newly formed limited liability company owned by certain officers and employees. The membership interests participate only in 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, 2010 is summarized as follows: 

 
| ** **                            | ** ** | **Units** | ** ** |
|---------------------------------------|------------|-----------|------------|
| Balance, January 1, 2010         |       | 6,625,283 |       |
| Granted                               |       | 648,000   |       |
| Forfeited/canceled                    |       | (79,500   | )          |
| Outstanding at December 31, 2010 |       | 7,193,783 |       |

 

**(9)****                    ****Financial Instruments**

 

The carrying values of trade receivables, trade payables, and credit facilities at December 31, 2010 and 2009 approximated market value. The carrying value of the bank credit facility at December 31, 2010 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 $549.3 million, based on market data at December 31, 2010.

 

See note 10 for information regarding the fair value of derivative financial instruments.

 

**(10)****             ****Derivative Instruments**

 

***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, 2008, 2009, and 2010, the Company was party to natural gas fixed price swaps. When actual commodity prices exceed the fixed price provided by the swap contracts, the Company pays the excess to the counterparty, and when actual commodity prices are below the contractually provided fixed price the Company receives the difference from the counterparty. The Company’s natural gas swaps have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently.

 

(Continued)

 

F-22

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

As of December 31, 2010, 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, 2011 through December 31, 2015 as summarized in the following table. Hedge agreements referenced to the Centerpoint and Transco Zone 4 indices are for production in the Arkoma Basin. Hedge agreements referenced to the CIG index and NYMEX-WTI are for production in the Piceance Basin. Hedge agreements referenced to the CGTAP and the Dominion indices are for production from the Appalachian Basin.

 
| ** **                          | ** ** | ** **           | ** ** | ** **   | ** ** | **Weighted**           | ** ** |
|-------------------------------------|------------|----------------------|------------|--------------|------------|------------------------|------------|
| ** **                          | ** ** | **Natural Gas** | ** ** | **Oil**      | ** ** | **average index** | ** ** |
| ** **                          | ** ** | **MMbtu/day**        | ** ** | **Bbls/day** | ** ** | **price**              | ** ** |
|                                |       |                 |       |         |       |                   |       |
| Year ending December 31, 2011: |       |                 |       |         |       |                   |       |
| CIG                                 |       | 45,000               |       |         |       | $                      | 5.49       |   |
| Transco zone 4                      |       | 45,000               |       |         |       | 6.39                   |       |
| CGTAP                               |       | 65,610               |       |         |       | 5.81                   |       |
| Dominion                            |       | 4,043                |       |         |       | 8.22                   |       |
| NYMEX-WTI                           |       |                 |       | 300          |       | 88.75                  |       |
|                                |       |                 |       |         |       |                   |       |
| Year ending December 31, 2012: |       |                 |       |         |       |                   |       |
| CIG                                 |       | 45,000               |       |         |       | $                      | 5.71       |   |
| Transco zone 4                      |       | 35,000               |       |         |       | 7.05                   |       |
| CGTAP                               |       | 65,556               |       |         |       | 6.02                   |       |
| Dominion                            |       | 3,318                |       |         |       | 8.00                   |       |
| NYMEX-WTI                           |       |                 |       | 300          |       | 90.20                  |       |
|                                |       |                 |       |         |       |                   |       |
| Year ending December 31, 2013: |       |                 |       |         |       |                   |       |
| CIG                                 |       | 60,000               |       |         |       | $                      | 5.53       |   |
| Transco zone 4                      |       | 40,000               |       |         |       | 6.51                   |       |
| CGTAP                               |       | 42,631               |       |         |       | 6.36                   |       |
| Dominion                            |       | 21,702               |       |         |       | 5.65                   |       |
| NYMEX-WTI                           |       |                 |       | 300          |       | 90.30                  |       |
|                                |       |                 |       |         |       |                   |       |
| Year ending December 31, 2014: |       |                 |       |         |       |                   |       |
| CIG                                 |       | 50,000               |       |         |       | $                      | 5.84       |   |
| Transco zone 4                      |       | 20,000               |       |         |       | 6.51                   |       |
| Centerpoint                         |       | 10,000               |       |         |       | 6.20                   |       |
| CGTAP                               |       | 70,000               |       |         |       | 6.26                   |       |
| Dominion                            |       | 30,000               |       |         |       | 5.48                   |       |
|                                |       |                 |       |         |       |                   |       |
| Year ending December 31, 2015: |       |                 |       |         |       |                   |       |
| CIG                                 |       | 10,000               |       |         |       | $                      | 5.06       |   |
| Dominion                            |       | 60,000               |       |         |       | 5.58                   |       |

 

(Continued)

 

F-23

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

As of December 31, 2010, derivative positions with JP Morgan, BNP Paribas, Wells Fargo, Dominion Field Services, Barclays, Union Bank, Credit Suisse, and KeyBank accounted for approximately 46%, 25%, 9%, 7%, 6%, 4%, 2%, and 1%, respectively, of the net fair value of our commodity derivative assets position. The Company has no collateral from any counterparties. Commodity and interest rate derivative positions are primarily with institutions that have a position in our Credit Facility and are secured by the collateral pledged on the Credit Facility and cross default provisions between the Credit Facility and the derivative instruments. There are no past due receivables from or payables to any of our counterparties.

*** ***

***Interest Rate Derivatives***

 

The Company has entered into various floating-to-fixed interest rate swap derivative contracts to manage exposures to changes in interest rates from variable rate obligations under the second lien term loan (retired in 2009) and the bank credit facility. Under the swaps, the Company makes payments to the swap counterparty when the variable LIBOR three-month rate falls below the fixed rate or receives payments from the swap counterparty when the variable LIBOR three-month rate goes above the fixed rate. The Company has one outstanding swap agreement at December 31, 2010 summarized as follows:

 
| **Notional amount of swap** | ** ** | **Covering periods** | ** ** | **Fixed rate** | ** ** |
|--------------------------------------------|------------|---------------------------|------------|---------------------|------------|
| $225 million                               |       | May 2007 to July 1, 2011  |       | 4.11                | %          |

 

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

 

(Continued)

 

F-24

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***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, 2009 and 2010. None of the Company’s derivative instruments are designated as hedges for accounting purposes.

 
| ** **                                                                | ** ** | **2009**               | ** ** | **2010**             | ** ** |
|---------------------------------------------------------------------------|------------|------------------------|------------|----------------------|------------|
| ** **                                                                | ** ** | **Balance sheet** | ** ** | ** **           | ** ** | **Balance sheet** | ** ** | ** ** | ** ** |
| ** **                                                                | ** ** | **location**           | ** ** | **Fair value**  | ** ** | **location** | ** ** | **Fair value** | ** ** |
| ** **                                                                | ** ** | ** **             | ** ** | **(In   thousands)** | ** ** | ** ** | ** ** | **(In   thousands)** | ** ** |
| ** **                                                                | ** ** | ** **             | ** ** | ** **           | ** ** | ** ** | ** ** | ** ** | ** ** |
| Asset derivatives not designated as hedges for   accounting purposes:     |       |                   |       |                 |       |   |   |   |   |
| Commodity contracts                                                       |       | Current   assets       |       | $                    | 22,105     |   | Current   assets |   | $ | 82,960 |   |
| Commodity contracts                                                       |       | Long-term   assets     |       | 18,989               |       | Long-term   assets |   | 147,417 |   |
|                                                                      |       |                   |       |                 |       |   |   |   |   |
| Total asset derivatives                                                   |       |                   |       | $                    | 41,094     |   |   |   | $ | 230,377 |   |
|                                                                      |       |                   |       |                 |       |   |   |   |   |
| Liability derivatives not designated as hedges for   accounting purposes: |       |                   |       |                 |       |   |   |   |   |
| Interest rate contracts                                                   |       | Current   liabilities  |       | $                    | 8,623      |   | Current   liabilities |   | $ | 4,212 |   |
| Interest rate contracts                                                   |       | Long-term liabilities  |       | 2,464                |       | Long-term liabilities |   | — |   |
|                                                                      |       |                   |       |                 |       |   |   |   |   |
| Total liability derivatives                                               |       |                   |       | $                    | 11,087     |   |   |   | $ | 4,212 |   |

 

(Continued)

 

F-25

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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, 2008, 2009, and 2010 (in thousands): 

 
| ** **                                             | ** ** | **Statement of**    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|--------------------------------------------------------|------------|--------------------------|------------|------------|------------|------------|------------|------------|------------|
| ** **                                             | ** ** | **operations**           | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                             | ** ** | **location**             | ** ** | **2008**   | ** ** | **2009**   | ** ** | **2010**   | ** ** |
|                                                   |       |                     |       |       |       |       |       |       |       |
| Realized gains on commodity contracts                  |       | Revenue                  |       | $          | 26,053     |       | 116,550    |       | 73,713     |   |
| Unrealized gains (losses) on commodity contracts       |       | Revenue                  |       | 90,301     |       | (61,186    | )          | 170,571    |       |
|                                                   |       |                     |       |       |       |       |       |       |       |
| Total gains on commodity contracts                     |       |                     |       | 116,354    |       | 55,364     |       | 244,284    |       |
|                                                   |       |                     |       |       |       |       |       |       |       |
| Realized losses on interest rate contracts             |       | Other income   (expense) |       | (1,428     | )          | (11,148    | )          | (9,552     | )          |
| Unrealized gains (losses) on interest rate   contracts |       | Other income   (expense) |       | (13,817    | )          | 6,163      |       | 6,875      |       |
|                                                   |       |                     |       |       |       |       |       |       |       |
| Total losses on interest rate contracts                |       |                     |       | (15,245    | )          | (4,985     | )          | (2,677     | )          |
|                                                   |       |                     |       |       |       |       |       |       |       |
| Net gains on derivative contracts                      |       |                     |       | $          | 101,109    |       | 50,379     |       | 241,607    |   |

 

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

** **

**(11)****             ****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 subsidiaries of Antero Resources LLC are corporations subject to federal and state income taxes. The subsidiaries have not been in an income tax paying situation for the years ended December 31, 2008, 2009, or 2010.

 

(Continued)

 

F-26

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

The income tax expense (benefit) differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 34% to consolidated income for the years ended December 31, 2008, 2009, and 2010, as a result of the following (in thousands):

 
| ** **                                                                           | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** |
|--------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Federal income tax (benefit)                                                         |       | $        | 29,481     |     | (37,107    | )        | 88,468     |   |
| State income tax expense (benefit), net of federal   benefit                         |       | 2,376    |       | (3,920   | )          | 5,398    |       |
| Change in tax rate                                                                   |       | 760      |       | —   |       | —   |       |
| Change in valuation allowance                                                        |       | (29,631  | )          | 40,504   |       | (14,410  | )          |
| Gain on sale of midstream assets passed through to   members of Antero Resources LLC |       | —   |       | —   |       | (50,170  | )          |
| Other                                                                                |       | 43       |       | (2,082   | )          | 723      |       |
|                                                                                 |       |     |       |     |       |     |       |
| Total income tax expense (benefit)                                                   |       | $        | 3,029      |     | (2,605     | )        | 30,009     |   |

 

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, 2009 and 2010 is as follows (in thousands): 

 
| ** **                                   | ** ** | **2009**   | ** ** | **2010**   | ** ** |
|----------------------------------------------|------------|------------|------------|------------|------------|
| ** **                                   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Deferred tax assets:                         |       |       |       |       |       |
| Net operating loss carryforwards             |       | $          | 103,846    |       | 191,369    |   |
| Capital loss carryforwards                   |       |       | —     |       | 3,558      |   |
| Other                                        |       | 2,289      |       | 3,198      |       |
| Total deferred tax assets                    |       | 106,135    |       | 198,125    |       |
| Valuation allowance                          |       | (46,952    | )          | (32,542    | )          |
| Net deferred tax assets                      |       | 59,183     |       | 165,583    |       |
| Deferred tax liabilities:                    |       |       |       |       |       |
| Unrealized gains on derivative instruments   |       | 11,984     |       | 88,057     |       |
| Depreciation differences on gathering system |       | 14,437     |       | 3,795      |       |
| Oil and gas properties                       |       | 33,186     |       | 163,914    |       |
| Total deferred tax liabilities               |       | 59,607     |       | 255,766    |       |
| Net deferred tax liabilities                 |       | $          | (424       | )          | (90,183    | ) |

 

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 

 

(Continued)

 

F-27

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Due to the lack of historical profitable operations and based upon the projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes that the Company will not realize the benefits of all of these deductible differences and has recorded a valuation allowance of approximately $32.5 million at December 31, 2010. 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 reduced.

 

The subsidiaries of Antero Resources LLC have net operating loss carryforwards as of December 31, 2010 as follows (in millions):

 
| ** **                      | ** ** | **Antero** | ** ** | **Antero**   | ** ** | **Antero**   | ** ** | **Antero**      | ** ** | **Combined** | ** ** |
|---------------------------------|------------|------------|------------|--------------|------------|--------------|------------|-----------------|------------|--------------|------------|
| ** **                      | ** ** | **Arkoma** | ** ** | **Piceance** | ** ** | **Pipeline** | ** ** | **Appalachian** | ** ** | **total**    | ** ** |
| ** **                      | ** ** | ** ** | ** ** | ** **   | ** ** | ** **   | ** ** | ** **      | ** ** | ** **   | ** ** |
| Net operating loss carryforward |       | $          | 256        |         | 229        |         | 10         |            | 14         |         | 509        |   |
|                                 |            |            |            |              |            |              |            |                 |            |              |            |  |

 

The net operating loss carryforwards expire at various dates from 2024 through 2030. The tax years 2007 through 2010 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 2006 through 2010.

 

**(12)****             ****Commitments and Contingencies**

*** ***

***(a)******                     ******Operating Leases***

 

The Company has commitments under office lease agreements as follows (in thousands):

 
| 2011       |   | $   | 924    |   |
|------------|--------|-----|--------|--------|
| 2012       |   | 923 |   |
| 2013       |   | 680 |   |
| 2014       |   | 570 |   |
| 2015       |   | 533 |   |
| Thereafter |   | 383 |   |
|       |   | $   | 4,013  |   |

 

Rent expense for lease agreements was approximately $526,000, $886,000, and $819,000 during the years ending December 31, 2008, 2009, and 2010, respectively.

*** ***

***(b)******                     ******Firm Transportation Commitments***

** **

**Arkoma Basin**

 

We currently have firm takeaway capacity of 20 MMcf/d on the Ozark Gas Transmission Pipeline through August 2012 and 30 MMcf/d of firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline through July 2014. Of the 30 MMcf/d firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline, 20 MMcf/d has been released to a financial intermediary who is obligated to purchase our gas at a Transco Zone 4 market based price, less applicable transportation fees, for the

 

(Continued)

 

F-28

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Table of Contents

** **

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

term of the capacity release. Beginning August 1, 2011, we have an additional 10 MMcf/d of firm takeaway capacity on the Boardwalk Gulf Crossing Pipeline through July 2014. As of August 1, 2014, the commitment is reduced to 20 MMcf/d until August 1, 2015, when the commitment is further reduced to 10 MMcf/d until August 1, 2016 when the commitment expires.

 

**Piceance Basin**

 

We currently have 40 MMcf/d of firm takeaway capacity on the WIC Pipeline through September 2020. The El Paso WIC Pipeline expansion from Meeker, Colorado to Opal, Wyoming is fully operational and provides incremental capacity to more liquid markets. Additionally, we have contracted for 25 MMcf/d of firm takeaway capacity for 10 years on the El Paso Ruby Pipeline that is currently under construction. The Ruby Pipeline will begin in Opal, Wyoming and is expected to provide approximately 1.3 Bcf/d of incremental pipeline capacity from the Rocky Mountain region to the Northwest and West Coast of the United States beginning in July 2011.

 

**Appalachian Basin**

 

We have 40 MMcf/d of firm transportation capacity on the Columbia Pipeline from August 2009 for 7.5 years. Additionally, we have 110 MMcf/d of firm transportation capacity on the Columbia Pipeline through March 2021; 40 MMcf/d of this commitment will not be effective until April 2011. As a result of our acquisition of Bluestone Energy Partners on December 1, 2010, we acquired an additional 10 MMcf/d of firm transportation capacity on the Columbia Pipeline through December 2013 and 13.1 MMcf/d of firm capacity on the Columbia Pipeline through September 2025. As a result of the business acquisition in 2010, we acquired 3.5 MMcf/d of firm transportation capacity on the Dominion Transmission Gateway expansion project for a term of 10 years from the initial in-service date which is currently projected to be September 2012. Based on the Company’s forecasted production and estimates of current reserves, we believe our future production will be sufficient to meet our delivery commitments under these contracts.

 

***(c)******                      ******Drilling Rig Service Commitments and Compressor Service Agreements***

 

The Company has entered into contracts for the services of three rigs, which expire in 2011. Commitments under these agreements are approximately $10.5 million at December 31, 2010. Subsequent to December 31, 2010, the Company entered into one-year contracts for four rigs having commitments for $26.5 million.

 

The Company has entered into a compressor service agreement with a third party to provide gas compression services in the Appalachian Basin. The agreement provides for payments based on volumes compressed; the aggregate minimum payment obligation is approximately $1.4 million per year through October 2015.

 

***(d)******                     ******Processing Commitment***

 

The Company has entered into a long-term gas processing agreement for Piceance Basin production allowing us to realize the value of our NGLs effective January 1, 2011. The agreement expires December 1, 2025 and provides for the processing of quantities from 60 MMcf/d until October 1, 2011 increasing to 120 MMcf/d in 2013. For processed gas, we will realize the sales price of NGLs less gathering and processing fees and other expenses.

 

(Continued)

 

F-29

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Table of Contents

** **

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***(e)******                      ******Litigation***

 

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

 

**(13)****             ****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** | ** ** |
|----------------------------------------|------------|-------------------------------------------|------------|
| ** **                             | ** ** | **2009**                                  | ** ** | **2010** | ** ** |
| ** **                             | ** ** | **(In thousands)**                   | ** ** |
| Producing properties                   |       | $                                         | 1,340,827  |   | 1,762,206 |   |
| Unproved properties                    |       | 596,694                                   |       | 737,358 |   |
|                                   |       | 1,937,521                                 |       | 2,499,564 |   |
| Accumulated depreciation and depletion |       | (297,694                                  | )          | (422,433 | ) |
| Net capitalized costs                  |       | $                                         | 1,639,827  |   | 2,077,131 |   |

 

 

***(b)******                     ******Costs Incurred in Certain Oil and Gas Activities***

 
| ** **                          | ** ** | **Year ended December 31** | ** ** |
|-------------------------------------|------------|-------------------------------------------|------------|
| ** **                          | ** ** | **2008**                                  | ** ** | **2009** | ** ** | **2010** | ** ** |
| ** **                          | ** ** | **(In thousands)**                   | ** ** |
| Proved property acquisition costs   |       | $                                         | 3,466      |   | 1,029 |   | 50,657 |   |
| Unproved property acquisition costs |       | 457,879                                   |       | 16,118 |   | 247,733 |   |
| Development costs and other         |       | 512,112                                   |       | 258,520 |   | 299,926 |   |
| Asset retirement obligation         |       | 1,518                                     |       | 188 |   | 332 |   |
| Total costs incurred                |       | $                                         | 974,975    |   | 275,855 |   | 598,648 |   |

 

Costs incurred include costs allocated to proved and unproved properties of $50.7 million and $206.3 million, respectively, as a result of the business acquisition on December 1, 2010. See note 3.

 

(Continued)

 

F-30

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

***(c)******                      ******Results of Operations for Oil and Gas Producing Activities***

 
| ** **                         | ** ** | **Year ended December 31** | ** ** |
|------------------------------------|------------|-------------------------------------------|------------|
| ** **                         | ** ** | **2008**                                  | ** ** | **2009** | ** ** | **2010** | ** ** |
| ** **                         | ** ** | **(In thousands)**                   | ** ** |
| Revenues                           |       | $                                         | 229,715    |   | 129,621 |   | 206,462 |   |
| Production expenses                |       | 44,998                                    |       | 41,582 |   | 73,852 |   |
| Exploration expenses               |       | 22,998                                    |       | 10,228 |   | 24,794 |   |
| Depreciation and depletion expense |       | 116,906                                   |       | 130,128 |   | 124,341 |   |
| Impairment                         |       | 10,112                                    |       | 54,204 |   | 35,859 |   |
|                               |       | 34,701                                    |       | (106,521 | ) | (52,384 | ) |
| Income tax (expense) benefit       |       | (3,029                                    | )          | 2,605 |   | (30,009 | ) |
| Results of operations              |       | $                                         | 31,672     |   | (103,916 | ) | (82,393 | ) |

 

***(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, 2010 were prepared by DeGolyer and MacNaughton and Ryder Scott utilizing data compiled by us. All reserves are located in the United States. 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.

 

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.

 

In December 2008, the SEC adopted revisions to its oil and gas reserve reporting requirements to modify their rules for modernization of oil and gas development technology and to change the rules for pricing oil and gas reserves. In January 2010, the FASB issued Accounting Standards Update 2010-03, *Oil and Gas Reserve Estimation and Disclosures*, to provide consistency with the SEC rules.

 

In accordance with these new rules, as of December 31, 2009, the Company changed its definition of proved undeveloped reserves to include development spacing areas surrounding productive wells that are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. Additionally, the Company estimated proved reserves using 12 month average pricing beginning as of December 31, 2009 as required by the rules. Previously, rules required the use of year end pricing. The Company’s development plans 

 

(Continued)

 

F-31

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

related to scheduled drilling 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.

 

As of December 31, 2009 and 2010, the Company estimated proved reserves using average pricing for the previous twelve months. At December 31, 2008, the Company used year-end pricing to estimate proved reserves.

 
| ** **                                  | ** ** | **Oil and** | ** ** | ** **  | ** ** | **Natural** | ** ** | **Total**       | ** ** |
|---------------------------------------------|------------|------------------|------------|-------------|------------|-------------|------------|-----------------|------------|
| ** **                                  | ** ** | **condensate**   | ** ** | **NGLS**    | ** ** | **Gas**     | ** ** | **equivalents** | ** ** |
| ** **                                  | ** ** | **(MMBbl)**      | ** ** | **(MMBbl)** | ** ** | **(Bcf)**   | ** ** | **(Bcfe)**      | ** ** |
| Proved developed and undeveloped reserves:  |       |             |       |        |       |        |       |            |       |
| December 31, 2007                      |       | 1.0              |       | —      |       | 228.8       |       | 234.7           |       |
| Revisions                                   |       | (0.5             | )          | —      |       | (2.5        | )          | (5.5            | )          |
| Extensions, discoveries and other additions |       | 0.7              |       | —      |       | 470.1       |       | 474.6           |       |
| Production                                  |       | —           |       | —      |       | (30.3       | )          | (30.3           | )          |
| Purchase of reserves                        |       | —           |       | —      |       | 6.1         |       | 6.1             |       |
| Sale of reserves in place                   |       | —           |       | —      |       | —      |       | —          |       |
|                                        |       |             |       |        |       |        |       |            |       |
| December 31, 2008                      |       | 1.2              |       | —      |       | 672.2       |       | 679.6           |       |
| Revisions                                   |       | 0.5              |       | —      |       | (133.9      | )          | (130.9          | )          |
| Extensions, discoveries and other additions |       | 0.1              |       | —      |       | 627.2       |       | 627.8           |       |
| Production                                  |       | (0.1             | )          | —      |       | (35.2       | )          | (35.8           | )          |
| Purchase of reserves                        |       | —           |       | —      |       | —      |       | —          |       |
| Sale of reserves in place                   |       | —           |       | —      |       | —      |       | —          |       |
|                                        |       |             |       |        |       |        |       |            |       |
| December 31, 2009                      |       | 1.7              |       | —      |       | 1,130.3     |       | 1,140.7         |       |
| Revisions                                   |       | 1.0              |       | 34.9        |       | 37.8        |       | 252.9           |       |
| Extensions, discoveries and other additions |       | 7.8              |       | 69.2        |       | 1,248.4     |       | 1,711.7         |       |
| Production                                  |       | (0.1             | )          | —      |       | (45.0       | )          | (46.5           | )          |
| Purchase of reserves                        |       | —           |       | —      |       | 172.0       |       | 172.0           |       |
| Sale of reserves in place                   |       | —           |       | —      |       | —      |       | —          |       |
|                                        |       |             |       |        |       |        |       |            |       |
| December 31, 2010                      |       | 10.4             |       | 104.1       |       | 2,543.5     |       | 3,230.8         |       |

 

(Continued)

 

F-32

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 
| ** **                   | ** ** | **NGLs**    | ** ** | **Natural gas** | ** ** | **Oil**   | ** ** | **Equivalents** | ** ** |
|------------------------------|------------|-------------|------------|----------------------|------------|-----------|------------|-----------------|------------|
| ** **                   | ** ** | **(MMBbl)** | ** ** | **(Bcf)**            | ** ** | **MMBbl** | ** ** | **(Bcfe)**      | ** ** |
| Proved developed reserves:   |       |        |       |                 |       |      |       |            |       |
| December 31, 2007       |       | —      |       | 106.6                |       | 0.4       |       | 109.1           |       |
| December 31, 2008       |       | —      |       | 236.9                |       | 0.3       |       | 238.7           |       |
| December 31, 2009       |       | —      |       | 271.7                |       | 0.7       |       | 275.8           |       |
| December 31, 2010       |       | 8.6         |       | 400.4                |       | 0.9       |       | 457.3           |       |
| Proved undeveloped reserves: |       |        |       |                 |       |      |       |            |       |
| December 31, 2007       |       | —      |       | 122.2                |       | 0.6       |       | 125.6           |       |
| December 31, 2008       |       | —      |       | 435.3                |       | 0.9       |       | 440.9           |       |
| December 31, 2009       |       | —      |       | 858.6                |       | 1.0       |       | 864.9           |       |
| December 31, 2010       |       | 95.5        |       | 2,143.1              |       | 9.5       |       | 2,773.5         |       |

 

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2008, 2009, and 2010 in the above table include the following:

 

·                              *Extensions and Discoveries —*The additions to the Company’s proved reserves through new discoveries and extensions result from (i) extensions of the proved acreage of previously discovered reservoirs through additional drilling of development wells and (ii) discovery of new fields with proved reserves through drilling of exploratory wells.

 

·                               2008 — Of the 474.6 Bcfe of 2008 extensions and discoveries, 265.2 Bcfe related to the Arkoma Basin, 197.7 Bcfe related to the Piceance Basin, and 11.7 Bcfe related to our other areas. The increase in extensions and discoveries is the result of an expanded drilling program.

 

·                               2009 — Of the 627.8 Bcfe of 2009 extensions and discoveries, 280.0 Bcfe related to the Arkoma Basin in Oklahoma, 199.9 Bcfe related to the Piceance Basin in Colorado, 116.6 Bcfe related to the Appalachia Basin in Pennsylvania and West Virginia, and 31.3 Bcfe related to our other areas. The increase in extensions and discoveries is the result of entering into the Marcellus Shale play in the Appalachia Basin and the changes in rules for estimating proved reserves.

 

·                               2010 — Of the 1,711.7 Bcfe of extensions and discoveries in 2010, 249.0 Bcfe related to the Arkoma Basin in Oklahoma, 1,130.4 Bcfe related to the Piceance Basin in Colorado, 300.8 Bcfe related to the Appalachian Basin in Pennsylvania and West Virginia, and 31.5 Bcfe related to other areas. The increase in extensions and discoveries is the result of increased activity in the 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.

 

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves. Future cash inflows as of December 31, 2009 and 2010 were computed by applying historical 12-month unweighted first day of the month average prices. Future cash inflows as of December 31, 2008 were computed by applying year-end prices of oil and gas to estimated future production of proved reserves. The estimated effect of this change in the method of pricing proved reserves was to decrease the standardized measure of the discounted future net cash flows attributable to our proved reserves by approximately $1.2 billion at December 31, 2009. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

 

(Continued)

 

F-33

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

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.

 
| ** **                                                 | ** ** | **Year ended December 31** | ** ** |
|------------------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                                 | ** ** | **2008**                                  | ** ** | **2009** | ** ** | **2010** | ** ** |
| ** **                                                 | ** ** | **(In millions)**                    | ** ** |
| Future cash inflows                                        |       | $                                         | 2,931      |   | 3,571 |   | 13,114 |   |
| Future production costs                                    |       | (599                                      | )          | (820 | ) | (3,088 | ) |
| Future development costs                                   |       | (637                                      | )          | (1,389 | ) | (4,036 | ) |
| Future net cash flows before income tax                    |       | 1,695                                     |       | 1,362 |   | 5,990 |   |
| Future income tax expense                                  |       | (268                                      | )          | (60 | ) | (1,438 | ) |
| Future net cash flows                                      |       | 1,427                                     |       | 1,302 |   | 4,552 |   |
| 10% annual discount for estimated timing of cash   flows   |       | (738                                      | )          | (1,067 | ) | (3,455 | ) |
| Standardized measure of discounted future net cash   flows |       | $                                         | 689        |   | 235 |   | 1,097 |   |

 

(Continued)

 

F-34

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Table of Contents

 

**ANTERO RESOURCES LLC AND SUBSIDIARIES**

Notes to Consolidated Financial Statements

December 31, 2008, 2009, and 2010

 

The 12-month weighted average prices for the year ended December 31, 2010 and the year-end spot prices used to estimate the Company’s total equivalent reserves were as follows:

 
| ** **                             | ** ** | **Arkoma** | ** ** | **Piceance**       | ** ** | **Appalachia** | ** ** |
|----------------------------------------|------------|------------|------------|--------------------|------------|----------------|------------|
| ** **                             | ** ** | ** ** | ** ** | **(Per Mcf)** | ** ** | ** **     | ** ** |
| December 31, 2008 (spot price)    |       | $          | 4.61       |               | 4.61       |           | —     |   |
| December 31, 2009 (average price) |       | 3.25       |       | 3.07               |       | 4.15           |       |
| December 31, 2010 (average price) |       | 4.18       |       | 3.93               |       | 4.51           |       |
|                                        |            |            |            |                    |            |                |            |  |

 

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

 
| ** **                                     | ** ** | **Year ended December 31** | ** ** |
|------------------------------------------------|------------|-------------------------------------------|------------|
| ** **                                     | ** ** | **2008**                                  | ** ** | **2009** | ** ** | **2010** | ** ** |
| ** **                                     | ** ** | **(In millions)**                    | ** ** |
|                                           |       |                                      |       |   |   |   |   |
| Sales of oil and gas, net of productions costs |       | $                                         | (177       | ) | (205 | ) | (171 | ) |
| Net changes in prices and production costs     |       | (152                                      | )          | (257 | ) | 382 |   |
| Development costs incurred during the period   |       | 115                                       |       | 7 |   | 81 |   |
| Net changes in future development costs        |       | (126                                      | )          | (239 | ) | (61 | ) |
| Extensions, discoveries and other additions    |       | 533                                       |       | 223 |   | 695 |   |
| Acquisitions                                   |       | —                                    |       | — |   | 92 |   |
| Revisions of previous quantity estimates       |       | (8                                        | )          | (42 | ) | 113 |   |
| Accretion of discount                          |       | 70                                        |       | 62 |   | 29 |   |
| Net change in income taxes                     |       | (33                                       | )          | (50 | ) | (359 | ) |
| Other changes                                  |       | 35                                        |       | 47 |   | 61 |   |
| Net increase (decrease)                        |       | 257                                       |       | (454 | ) | 862 |   |
| Beginning of year                              |       | 432                                       |       | 689 |   | 235 |   |
| End of year                                    |       | $                                         | 689        |   | 235 |   | 1,097 |   |

 

F-35

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