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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

(Mark one)

For the fiscal year ended December 31, 2010

or

For the transition period from      to      

Commission File No. 333-164876-06

ANTERO RESOURCES LLC

(Exact name of registrant as specified in its charter)

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.

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.

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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.

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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:

(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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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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(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.

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.

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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.

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.

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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