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EX-31.1 - EX-31.1 - RANGE RESOURCES CORPd78300exv31w1.htm
EX-31.2 - EX-31.2 - RANGE RESOURCES CORPd78300exv31w2.htm
EX-32.1 - EX-32.1 - RANGE RESOURCES CORPd78300exv32w1.htm
EX-32.2 - EX-32.2 - RANGE RESOURCES CORPd78300exv32w2.htm
EX-23.3 - EX-23.3 - RANGE RESOURCES CORPd78300exv23w3.htm
EX-23.1 - EX-23.1 - RANGE RESOURCES CORPd78300exv23w1.htm
EX-99.2 - EX-99.2 - RANGE RESOURCES CORPd78300exv99w2.htm
EX-21.1 - EX-21.1 - RANGE RESOURCES CORPd78300exv21w1.htm
EX-99.3 - EX-99.3 - RANGE RESOURCES CORPd78300exv99w3.htm
EX-23.2 - EX-23.2 - RANGE RESOURCES CORPd78300exv23w2.htm
EX-23.4 - EX-23.4 - RANGE RESOURCES CORPd78300exv23w4.htm
EX-99.1 - EX-99.1 - RANGE RESOURCES CORPd78300exv99w1.htm
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
 
(Mark one)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission File Number: 001-12209
 
RANGE RESOURCES CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
 
     
Delaware
(State or Other Jurisdiction of Incorporation or Organization)
  34-1312571
(IRS Employer Identification No.)
     
100 Throckmorton Street, Suite 1200, Fort Worth, Texas
(Address of Principal Executive Offices)
  76102
(Zip Code)
Registrant’s telephone number, including area code
(817) 870-2601
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
Common Stock, $.01 par value   New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
 
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
     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. Yes þ No o
     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 during the proceedings 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No þ
     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. o
     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 (check one):
             
     Large accelerated filer þ   Accelerated filer o  Non-accelerated filer o  Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in 12b-2 of the Act). Yes o No þ
     The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2010 was $6,999,629,000. This amount is based on the closing price of registrant’s common stock on the New York Stock Exchange on that date. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.
     As of February 25, 2011, there were 160,491,399 shares of Range Resources Corporation Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
     Portions of the registrant’s proxy statement to be furnished to stockholders in connection with its 2011 Annual Meeting of Stockholders are incorporated by reference in Part III, Items 10-14 of this report.
 
 

 


 

RANGE RESOURCES CORPORATION
     Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investees. Unless otherwise noted, all information in the report relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If you are not familiar with the oil and gas terms used in this report, please refer to the explanation of such terms under the caption “Glossary of Certain Defined Terms” at the end of Item 15 of this report.
TABLE OF CONTENTS
             
        Page
PART I
   
 
       
ITEM 1.       1  
   
 
       
ITEM 1A.       11  
   
 
       
ITEM 1B.       20  
   
 
       
ITEM 2.       20  
   
 
       
ITEM 3.       29  
   
 
       
ITEM 4.       29  
   
 
       
   
 
       
PART II
   
 
       
ITEM 5.       30  
   
 
       
ITEM 6.       32  
   
 
       
ITEM 7.       34  
   
 
       
ITEM 7A.       54  
   
 
       
ITEM 8.       56  
   
 
       
ITEM 9.       56  
   
 
       
ITEM 9A.       56  
   
 
       
ITEM 9B.       57  
   
 
       
PART III
   
 
       
ITEM 10.       58  
   
 
       
ITEM 11.       61  
   
 
       
ITEM 12.       61  
   
 
       
ITEM 13.       61  
   
 
       
ITEM 14.       61  
   
 
       
PART IV
   
 
       
ITEM 15.       62  
   
 
       
GLOSSARY OF CERTAIN DEFINED TERMS     63  
   
 
       
SIGNATURES     65  
 EX-21.1
 EX-23.1
 EX-23.2
 EX-23.3
 EX-23.4
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2
 EX-99.3

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RANGE RESOURCES CORPORATION
Annual Report on Form 10-K
Year Ended December 31, 2010
Disclosures Regarding Forward-Looking Statements
     Certain information included in this report, other materials filed or to be filed with the Securities and Exchange Commission (the “SEC”), as well as information included in oral statements or other written statements made or to be made by us, contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “budget,” “budgeted,” “assumes,” “should,” “goal,” “anticipates,” “expects,” “believes,” “seeks,” “plans,” “estimates,” “may,” “could,” “future,” “potential,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results and the difference between assumed facts or bases and the actual results could be material, depending on the circumstances. It is important to note that our actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based on the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following: the factors listed in Item 1A of this report under the heading “Risk Factors,” production variance from expectations, volatility of natural gas and oil prices, hedging results, the need to develop and replace reserves, the substantial capital expenditures required to fund operations, exploration risks, environmental risks, uncertainties about estimates of reserves, competition, litigation, government regulation, political risks, our ability to implement our business strategy, costs and results of drilling new projects, mechanical and other inherent risks associated with natural gas and oil production, weather, availability of drilling equipment and changes in interest rates. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.
PART I
ITEM 1. BUSINESS
General
     We are a Fort Worth, Texas-based independent natural gas and oil company, engaged in the exploration, development and acquisition of primarily natural gas and oil properties, mostly in the Appalachian and Southwestern regions of the United States. We were incorporated in 1980 under the name Lomak Petroleum, Inc. and, later that year, we completed an initial public offering and began trading on the NASDAQ. In 1996, our common stock was listed on the New York Stock Exchange. In 1998, we changed our name to Range Resources Corporation. Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). During the past five years, we have increased our proved reserves 216% (from 1.4 Tcfe in 2005 to 4.4 Tcfe in 2010), while production has increased 107% (from 87,263 Mmcfe in 2005 to 180,789 Mmcfe in 2010). At year-end 2010, we owned 2,688,000 gross (2,078,000 net) acres of leasehold, including 340,000 acres where we also own a royalty interest. We have built a multi-year drilling inventory that is estimated to contain over 8,100 drilling locations, both proven and unproven.
     At year-end 2010, our proved reserves had the following characteristics:
    4.4 Tcfe of proved reserves;
    80% natural gas;
    49% proved developed;
    85% operated;
    a reserve life of 22.3 years (based on fourth quarter 2010 production);
    a pre-tax present value of $4.6 billion of future net cash flows attributable to our reserves, discounted at 10% per annum (“PV-10”); and
    a standardized after-tax measure of discounted future net cash flows of $3.5 billion.

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     PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before 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 prices 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 discounted estimated future income tax of $1.2 billion at December 31, 2010.
Business Strategy
     Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to employ internally generated drillbit growth occasionally coupled with complementary acquisitions. Our strategy requires us to make significant investments in technical staff, acreage, seismic data and technology to build drilling inventory. Our strategy has the following principal elements:
    Concentrate in Core Operating Areas. We currently operate in two regions: the Appalachian (which includes tight-gas, shale, coal bed methane and conventional natural gas and oil production in Pennsylvania, Virginia, Ohio and West Virginia) and Southwestern (which includes the Barnett Shale of North Texas, the Permian Basin of West Texas and eastern New Mexico, the East Texas Basin, the Texas Panhandle and the Anadarko Basin of Western Oklahoma). Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale. Operating in multiple core areas allows us to blend the production characteristics of each area to balance our portfolio toward our goal of consistent production and reserve growth.
    Maintain Multi-Year Drilling Inventory. We focus on areas where multiple prospective, productive horizons and development opportunities exist. We use our technical expertise to build and maintain a multi-year drilling inventory. A large, multi-year inventory of drilling projects increases our ability to consistently grow production and reserves. Currently, we have over 8,100 identified future drilling locations in inventory, both proven and unproven.
    Focus on cost efficiency. We concentrate in core areas which we believe to have sizeable hydrocarbon deposits in place that will allow us to consistently increase production while controlling costs. As there is little long-term competitive sales price advantage available to a commodity producer, the costs to find, develop, and produce a commodity are important to organizational sustainability and long-term shareholder value creation. We endeavor to control costs such that our cost to find, develop and produce natural gas and oil is in the best performing quartile of our peer group.
    Maintain Long-Life Reserve Base. Long-life natural gas and oil reserves provide a more stable growth platform than short-life reserves. Long-life reserves reduce reinvestment risk as they lessen the amount of reinvestment capital deployed each year to replace production. Long-life natural gas and oil reserves also assist us in minimizing costs as stable production makes it easier to build and maintain operating economies of scale. We use our acquisition, divestiture, and drilling activity to assist in executing this strategy.
    Maintain Flexibility. Because of the risks involved in drilling, coupled with changing commodity prices, we remain flexible and adjust our capital budget throughout the year. We may defer capital projects to seize an attractive acquisition opportunity. If certain areas generate higher than anticipated returns, we may accelerate drilling and acquisitions in those areas and decrease capital expenditures and acquisitions elsewhere. We also believe in maintaining a strong balance sheet and using commodity hedging, which allows us to be more opportunistic in lower price environments and provides more consistent financial results.
    Commitment to environmental, health and safety. We implement the latest technologies and best practices to minimize potential impacts from the development of our nation’s natural resources as it relates to the environment, worker health and safety, and the health and safety of the communities where we operate. Working hand-in-hand with peer companies, regulators, nongovernmental organizations, industries not related to the natural gas industry, and other engaged stakeholders, we consistently analyze and review performance while striving for continual improvement.
    Equity Ownership and Incentive Compensation. We want our employees to think and act like stockholders. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees receive equity grants. As of December 31, 2010, our employees owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $230.9 million.

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Significant Accomplishments in 2010
    Production growth — 2010 marked Range’s eighth consecutive year of sequential production growth. In 2010, our annual production averaged 495.3 Mmcfe per day, an increase of 14% from 2009. Targeted drilling to the liquids rich — portion of the Marcellus Shale play in Pennsylvania drove our production growth.
    Reserve growth — Total proved reserves increased 42% in 2010 to 4.4 Tcfe, marking the ninth consecutive year our proved reserves have increased. This achievement is the result of our continued drilling success, as a significant portion of our production and reserve growth in 2010 came from our drilling program. While consistent growth is challenging to sustain, we believe the quality of our technical teams and our substantial inventory of drilling locations provide the basis for future reserve, production and cash flow growth.
    Successful drilling program — In 2010, we drilled 367 gross wells. Production was replaced by 780% through drilling in 2010 and our overall drilling success rate was approximately 98%. As we continue to build our drilling inventory for the future, our ability to drill a large number of wells each year on a cost effective and efficient basis is critical.
    Large resource potential from unconventional plays — Maintaining a large exposure to potential resources is important. We continued expansion of our unconventional resource shale plays in 2010. We have three large unconventional plays — the Marcellus, Utica and Upper Devonian shales in Pennsylvania, the Huron Shale in Virginia and the Barnett Shale in North Texas. These plays cover expansive areas, provide multi-year drilling opportunities and have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. We have now leased 1.1 million net acres in these three shale plays. We also have 282,000 net acres in our coal bed methane plays in Virginia West Virginia and Pennsylvania.
    Maintenance of a strong balance sheet — Financial leverage, as measured by the debt-to-capitalization ratio, increased from 42% in 2009 to 47% in 2010. We refinanced $287.1 million of shorter-term bank debt by issuing $500.0 million of senior subordinated fixed rate 6.75% notes having a 10-year maturity. The remainder of the proceeds we received from the issuance of the 6.75% senior subordinated notes was used to redeem our 7.375% senior subordinated notes due 2013. This helped to better align the maturity schedule of our debt with the long-term life of our assets and reduce interest rate volatility.
    Successful acquisitions completed — In 2010, we acquired $166.7 million of acreage located in our core areas, primarily in the Marcellus Shale. We continued to see outstanding results in the Marcellus Shale. Production in the Marcellus Shale increased 113% while we continue to prove up additional unproved acreage, acquire additional acreage and gain access to additional pipeline and processing capacity. In June 2010, we purchased proved and unproved natural gas properties in Virginia for approximately $134.5 million. These properties were adjacent to our existing properties in Virginia.
    Successful dispositions completed — In second quarter 2010, we sold our tight gas sand properties in Ohio for of $323.0 million.
Industry Operating Environment
     The oil and natural gas industry is affected by many factors that we generally cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on operations and profitability. For several years preceding the 2008 worldwide economic decline, the oil and gas industry had been characterized by volatile but upward trending oil, NGL and natural gas commodity prices. However, since mid-year 2008, we have experienced declines in commodity prices, especially with regard to natural gas prices. NYMEX prices for natural gas averaged $4.40 per mcf in 2010, with a high of $5.82 per mcf in January and a low of $3.32 per mcf in November. Natural gas prices continue to be under pressure due to concerns over excess supply of natural gas due to the high productivity of emerging shale plays in the United States and continued lower product demand caused by a weakened economy. Natural gas prices are generally determined by North American supply and demand and are also affected by imports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.
     Significant factors that will impact 2011 crude oil prices include: political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to manage oil supply through export quotas. NYMEX prices averaged $79.59 per barrel in 2010 with a high of $89.23 per barrel in December and a low of $74.12 per barrel in May.
Segment and Geographical Information
     Our operations consist of one reportable segment. We have a single, company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise

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and not on an area-by-area basis. We focus on both unconventional resource plays and conventional plays in the Appalachian and Southwestern regions of the United States.
Plans for 2011
     Our capital expenditure budget for 2011 has been initially set at approximately $1.38 billion. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices and drilling success. The 2011 budget includes $1.1 billion for drilling, $159.8 million for land, $55.5 million for seismic and $66.6 million for the expansion and enhancement of gathering systems and facilities. Approximately 90% of the budget is attributable to the Appalachian region and 10% to the Southwestern region.
     In October 2010, we announced our plan to offer for sale Barnett Shale properties in North Central Texas. The properties include approximately 350 producing wells and 700 proven and unproven drilling locations. Parties began conducting evaluations in December 2010 and on February 28, 2011 we announced that we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to typical post-closing adjustments. However, the completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.
Production, Price and Cost History
     The following table sets forth information regarding natural gas, natural gas liquids, and oil production, realized prices and production costs for the last three years. For additional information see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
                         
    Year Ended December 31,  
    2010     2009     2008  
Production
                       
Natural gas (Mmcf)
    142,034       130,649       114,323  
Natural gas liquids (Mbbls)
    4,490       2,187       1,386  
Crude oil (Mbbls)
    1,969       2,557       3,084  
Total (Mmcfe) (a)
    180,789       159,112       141,145  
 
                       
Average sales prices (wellhead)
                       
Natural gas (per mcf)
  $ 3.75     $ 3.32     $ 8.07  
Natural gas liquids (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.29       54.98       96.77  
Total (per mcfe) (a)
    4.67       4.00       9.14  
 
                       
Average realized prices (including derivatives that qualify for hedge accounting):
                       
Natural gas (per mcf)
  $ 4.21     $ 4.77     $ 8.15  
Natural gas liquids (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.30       59.75       73.38  
Total (per mcfe) (a)
    5.03       5.28       8.69  
 
                       
Average realized prices (including all derivative settlements)
                       
Natural gas (per mcf)
  $ 4.46     $ 6.13     $ 8.15  
Natural gas liquids (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.31       62.58       68.20  
Total (per mcfe) (a)
    5.23       6.44       8.58  
 
                       
Production costs
                       
Lease operating (per mcfe)
  $ 0.69     $ 0.78     $ 0.92  
Workovers (per mcfe)
    0.03       0.04       0.07  
Stock-based compensation (per mcfe)
    0.01       0.02       0.02  
 
                 
Total (per mcfe)
  $ 0.73     $ 0.84     $ 1.01  
 
                 
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

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Employees
     As of January 1, 2011, we had 713 full-time employees, 292 of whom were field personnel. All full-time employees are eligible to receive equity awards approved by the Compensation Committee of the Board of Directors. No employees are covered by a labor union or other collective bargaining arrangement. We believe that the relationship with our employees is excellent. We regularly use independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field, on-site production services and certain accounting functions.
Available Information
     Our internet website is available under the name http://www.rangeresources.com. We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. In addition, other information such as company presentations is also available on our website. Also, our Corporate Governance Guidelines, the charters of the Audit Committee, the Compensation Committee, the Dividend Committee, and the Governance and Nominating Committee, and the Code of Business Conduct and Ethics are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the chief executive officer and senior financial officer.
     We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Range, that file electronically with the SEC. The public can obtain any document we file with the SEC at http://www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Competition
     We encounter substantial competition in developing and acquiring natural gas and oil properties, securing and retaining personnel, conducting drilling and field operations and marketing production. Competitors in exploration, development, acquisitions and production include the major oil companies as well as numerous independent oil and gas companies, individual proprietors and others. Although our sizable acreage position and core area concentration provide some competitive advantages, many competitors have financial and other resources substantially exceeding ours. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources allow. Our ability to replace and expand our reserve base depends on our ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling. See “Item 1A. Risk Factors.”
Marketing and Customers
     We market the majority of our natural gas, NGL and oil production from the properties we operate for both our interest and that of the other working interest owners and royalty owners. We sell our gas pursuant to a variety of contractual arrangements, generally month-to-month and one to five-year contracts. Less than 10% of our production is subject to contracts longer than five years. Pricing on the month-to-month and short-term contracts is based largely on the New York Mercantile Exchange (“NYMEX”) pricing, with fixed or floating basis. For one to five-year contracts, our natural gas is sold on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. We sell less than 300 mcf per day under long-term fixed price contracts. Many contracts contain provisions for periodic price adjustment, redetermination and other terms customary in the industry. Our natural gas is sold to utilities, marketing companies and industrial users. Our oil is sold under contracts ranging in terms from month-to-month, up to as long as one year. The pricing for oil is based upon the posted prices set by major purchasers in the production area, reporting publications, or upon NYMEX pricing or fixed pricing. All oil pricing is adjusted for quality and transportation differentials. Our NGL production is primarily sold to natural gas processors. Currently, there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region so, for our Appalachian production volumes, ethane remains in the natural gas stream. Natural gas, NGL and oil purchasers are selected on the basis of price, credit quality and service reliability. For a summary of purchasers of our natural gas, NGL and oil production that accounted for 10% or more of consolidated revenue, see Note 15 to our consolidated financial statements. Because alternative purchasers of natural gas and oil are usually readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on us.
     We enter into hedging transactions with unaffiliated third parties for a substantial but varying portion of our production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas and oil prices. For a

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more detailed discussion, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.” Proximity to local markets, availability of competitive fuels and overall supply and demand are factors affecting the prices for which our production can be sold. Market volatility due to fluctuating weather conditions, international political developments, overall energy supply and demand, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.
     We incur gathering and transportation expenses to move our natural gas and crude oil from the wellhead and tanks to purchaser specified delivery points. These expenses vary based on volume, distance shipped and the fee charged by the third-party transporters. In the Southwestern region, our natural gas and oil production is transported primarily through third-party trucks, field gathering systems and transmission pipelines. Transportation capacity on these gathering systems and pipelines is occasionally constrained. In Appalachia, we own approximately 2,750 miles of gas gathering pipelines, which transport a portion of our Appalachian gas production and third-party gas to transmission lines and directly to end-users, and interstate pipelines. Our remaining Appalachian gas volume is transported on third-party pipelines on which, in some cases, we hold long-term contractual capacity. For additional information, see “Risk Factors — Our business depends on natural gas and oil transportation and processing facilities, most of which are owned by others,” in Item 1A of this report.
Seasonal Nature of Business
     Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial end users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand.
Governmental Regulation
     Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas and oil production and related operations are, or have been, subject to taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, 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 and 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.
     In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, the EPAct 2005 amends the Natural Gas Act (“NGA”), to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful 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; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction which includes the reporting requirements under Order Nos. 704 and 720, described below. It therefore reflects a significant expansion of FERC’s enforcement authority. Range has not been affected differently than any other producer of natural gas by this act.
     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 oil and gas industry are regularly considered by Congress, the states, the FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

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     On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). 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 a final rule on the daily scheduled flow and capacity posting requirements (“Order 720”), which was modified on January 21, 2010 (“Order 720-A”) and July 21, 2010 (“Order 720-B”). Under Orders 720, 720-A and 720-B, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million Mmbtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 Mmbtu per day.
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 protected areas, require some form of remedial action to prevent or mitigate pollution from existing and former operations such as plugging abandoned wells or closing earthen impoundments 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.
     The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons may include owners or operators of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, all of these persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties, pursuant to environmental statutes, common law or both, to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Although petroleum, including crude oil and natural gas, is not a “hazardous substance” under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA. While we generate materials in the course of our operations that may be regulated as hazardous

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substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA or comparable state laws. Other state laws regulate the disposal of oil and gas wastes, and new state and federal legislative initiatives that could have a significant impact on us may periodically be proposed and enacted.
     We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), which imposes requirements related to the handling and disposal of solid and hazardous wastes. While there is an exclusion from the definition of hazardous wastes for “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy,” these wastes may be regulated by the United States Environmental Protection Agency (“EPA”) or state agencies as non-hazardous solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, can be regulated as hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies.
     We currently own or lease, and have in the past owned or leased, properties that for many years have been used for the exploration and production of crude oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.
     The Federal Water Pollution Control Act, as amended (“FWPCA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and 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 EPA or the state. 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 greater than threshold quantities of oil. We regularly review our natural gas and oil 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.
     The Oil Pollution Act of 1990, as amended, or the OPA, contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.
     The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations. 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.
     Changes in environmental laws and regulations sometimes occur, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements for any substances used or produced in our operations could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.
     At least 20 states have already taken legal measures to control emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. In California, for example, the California Global Warming Solutions Act of 2006 requires the California Air Resources Board to adopt regulations by 2012 that will achieve an overall reduction in greenhouse gas emissions from all sources in California of 25% by 2020.

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     On April 2, 2007, the United States Supreme Court held that, if EPA found that greenhouse gas concentrations endanger public health and welfare, it was obligated to regulate their emissions under the Clean Air Act. On December 15, 2009, EPA issued “Endangerment and Cause of Contribute Findings for Greenhouse Gases under section 202(a) of the Clean Air Act,” in which it concluded that the atmospheric concentrations of several greenhouse gases threaten the health and welfare of future generations, and that the combined emissions of these gases from motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases, and, hence, to the threat of climate change. On April 1, 2010, EPA and the Department of Transportation finalized rules that limit emissions of greenhouse gases from motor vehicles and on April 2, 2010, EPA finalized a rule that declared greenhouse gases “subject to regulation” on January 2, 2011, the date on which EPA’s mobile source rules impose actual compliance obligations.
     While EPA’s endangerment findings and its rules on greenhouse gas emissions from mobile sources do not specifically address stationary sources, it is EPA’s view that once the mobile source rules were finalized in April 2010, emissions of greenhouse gases from stationary sources became covered under the federal Prevention of Significant Deterioration (“PSD”) and Title V air permit programs, which apply to “major sources” of air emissions. For purposes of the PSD program, the “major source” threshold is, at most, 250 tons per year of any regulated pollutant and for purposes of the Title V operating permit program, the threshold is 100 tons per year. In order to deal with the problem of an excessive number of sources being drawn into these programs, EPA has reset the “major source” thresholds to higher levels than set by statute in the “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule.” For the first six months of 2011, greenhouse gas sources are required to undergo PSD or Title V review only if they are otherwise subject to PSD review or Title V permitting due to other emissions, and BACT review applies to the PSD applicant if the expected GHG emission increase is greater than 75,000 tons per year. Beginning on July 1, 2011, sources not otherwise brought into PSD or Title V may be required to undergo PSD or Title V review due to their greenhouse gas emissions alone, if in excess of 100,000 tons per year.
     On September 23, 2009, EPA finalized a greenhouse gas reporting rule establishing a national greenhouse gas emissions collection and reporting program. The EPA rules require covered entities to measure greenhouse gas emissions commencing in 2011 and to submit reports commencing no later than March 31, 2012. While we do not operate stationary sources that emit significant quantities of greenhouse gases, including carbon dioxide, we do utilize gas processing plants to process the natural gas that we produce and, thus if such processors were to incur increased costs to acquire and surrender emission allowances or otherwise to capture and dispose of greenhouse gases, it is possible that these costs, which might be significant, could be passed along to us as well as similarly situated producers. Moreover, any adoption of a program to tax the emission of carbon dioxide and other greenhouse gases potentially could be imposed on us and other similarly situated producers of natural gas. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our products. Given the possible impact of legislation and/or regulation of carbon dioxide, methane and other greenhouse gases, we have considered and expect to continue to consider the impact of laws or regulations intended to address climate change on our operations. Under the new regulations, our operations require reporting or monitoring of carbon dioxide emissions. Since our emissions are minimal, we do not expect this to have a material effect on our operations. In addition, we also operate mobile equipment in the normal course of our business that emits carbon dioxide as well as some stationary engines that power compressors and pumping equipment. Methane is a primary constituent of natural gas and, like all oil and gas exploration and production companies, we produce significant quantities of natural gas; however, such production of natural gas, including its constituent hydrocarbon methane, is gathered and transported in pipelines under pressure and we therefore do not emit significant quantities of methane in connection with our operations. Given our lack of significant points of carbon dioxide emissions, we have focused most of our efforts on physical environmental ground, water and air issues in our operations.
     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.
     The federal Safe Drinking Water Act, as amended (“SDWA”) and comparable state laws regulate the nation’s public drinking water supply by regulating “public water systems” as well as underground sources of drinking water. Under the SDWA, EPA sets standards for drinking water quality and oversees the states, localities and water suppliers that implement those standards. The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the FRAC Act, to amend SDWA to repeal an exemption from regulation for hydraulic fracturing. Hydraulic fracturing is an important and commonly used process involving the injection of water, sand and small amounts of chemical additives under pressure into rock formations to stimulate oil or natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could result in third parties opposing the hydraulic fracturing process to initiate legal proceedings based on

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allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.
     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. However, we regularly have expenditures to comply with environmental laws and those costs continue to increase as our operations expand.
Action by the United States Environmental Protection Agency
     On December 7, 2010, the United States Environmental Protection Agency, Region VI, issued an administrative order (the “Order”) to Range, and our subsidiary Range Production Company, directing us to take certain action with regard to the existence of natural gas in two water wells in southern Parker County, Texas. The Order was issued without prior notice and without an opportunity for us to respond to the allegations on which the order was based, including the EPA’s conclusion that two of our subsidiary’s wells completed and producing from the Barnett Shale formation at a depth of approximately 5,800 feet caused or contributed to the presence of natural gas in the aquifer which is found at a depth of approximately 200-400 feet. Because we believe the Order was factually baseless and legally deficient, we advised the EPA that we would not voluntarily comply with the Order. Instead we requested that EPA review additional data provided by us to EPA and, withdraw the Order based on the fact the conclusions in the Order were based on insufficient data and incorrect analysis. Additionally, the Texas Railroad Commission (the “Commission”), the state agency with jurisdiction over our operations of the wells, had an ongoing investigation into the occurrence of natural gas in one of the two subject water wells (an investigation in which we were cooperating) and, in reaction to the Order, ordered a hearing to address the conclusions in the Order. The EPA declined to participate in the Commission hearing held on January 19 and 20, 2011.
      Prior to the hearing, in cooperation with the Commission’s Oil and Gas Division, we conducted a further investigation, in addition to the investigative efforts made from August 2010 to December 2010, including additional gas sampling, water sampling, soil sampling and analyses of natural gas from our wells, water from more than 25 area water wells and several hundred soil gas samples. Expert witness testimony and other evidence at the Commission hearing demonstrated, in summary, that: (i) it is impossible for hydraulic fracturing of our wells to have caused any harm to any water aquifer at the depths of the subject aquifer; (ii) isotopic and compositional gas sample analysis demonstrated that the source of the natural gas in the water aquifer is a shallow rock formation known as the Strawn formation which lies directly beneath the water aquifer and has geologic connection to the water aquifer including flow pathways to the aquifer, (iii) the EPA’s factual conclusions from its isotopic analysis are flawed and do not support the legal conclusions in the Order; (iv) our wells are sound with properly designed and constructed wellbores that are not a pathway for natural gas to flow into the water aquifer; (v) a number of other water wells in the area, which predate the drilling and completion of our wells, have produced significant quantities and are known to contain natural gas; (vi) a number of other water wells in the area have been drilled through the water aquifer into the Strawn formation, providing additional potential pathways beyond the geologic connection of the Strawn to the water aquifer, for natural gas to migrate from the Strawn into the water aquifer; (vii) the water sampling indicates that water from the aquifer is safe to drink; and (viii) provided the water wells in the area are properly vented, human health is protected and any safety hazards associated with the levels of natural gas in the water wells are removed. The hearing examiners have closed the evidentiary record but not yet issued their recommendation to the Commission for consideration in issuing a final order. However, we believe that the record before the Commission will demonstrate that the EPA Order is wrong and that Range neither caused nor contributed to any contamination of the water aquifer.
     On January 18, 2011, the EPA filed an action in the United States District Court for the Northern District of Texas, Dallas Division, seeking a judgment enforcing the Order and of up to $16,500 per day for each alleged violation of the Order. On January 21, 2011, Range filed an appeal of the Order in the United States Court of Appeals for the Fifth Circuit (the proper forum for such an appeal) seeking to invalidate the Order on the basis of the factual errors and legal deficiencies. Both the enforcement action and the appeal are in the early stages and, while we believe that the Order lacks sufficient factual and legal bases, and Range will vigorously pursue the appeal of the Order and defend the enforcement action, at this time we cannot predict the outcome of either the enforcement action or the appeal. However, we do not believe the ultimate resolution of this matter will have a material impact on our financial position, statement of operations or cash flows.

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ITEM 1A. RISK FACTORS
     We are subject to various risks and uncertainties in the course of our business. The following summarizes some, but not all, of the risks and uncertainties, which may adversely affect our business, financial condition or results of operations. Our business could also be impacted by additional risks and uncertainties not currently known to us or that we currently deem to be immaterial.
Risks Related to Our Business
Volatility of natural gas and oil prices significantly affects our cash flow and capital resources and could hamper our ability to produce natural gas and oil economically
     Natural gas and oil prices are volatile, and a decline in prices adversely affects our profitability and financial condition. The oil and gas industry is typically cyclical, and prices for natural gas and oil have been volatile. Historically, the industry has experienced downturns characterized by oversupply and/or weak demand. Long-term supply and demand for oil and gas is uncertain and subject to a myriad of factors such as:
    the domestic and foreign supply of natural gas and oil;
    the price and availability of alternative fuels;
    weather conditions;
    the level of consumer demand;
    the price of foreign imports;
    worldwide economic conditions;
    the availability, proximity and capacity of transportation facilities and processing facilities;
    the effect of worldwide energy conservation efforts;
    political conditions in natural gas and oil producing regions; and
    domestic (federal, state and local) and foreign governmental regulations and taxes.
     In July 2008, the average New York Mercantile Exchange (“NYMEX”) price of oil was $133.49 per barrel and the average NYMEX price of gas was $12.96 per mcf. In December 2008, the average NYMEX price of oil had fallen to $42.04 per barrel and gas was $6.56 per mcf. In 2009, oil prices rebounded to $74.60 per barrel as of December 31, 2009, while gas prices remained depressed at $4.46 per mcf. In December 2010, the average NYMEX price for oil had increased to $89.23 per barrel while gas prices declined to $4.27 per mcf. Significant or extended price declines can adversely affect the amount of natural gas, NGL and oil that we can economically produce. A reduction in production could result in a shortfall in expected cash flows and require a reduction in capital spending or require additional borrowing. Without the ability to fund capital expenditures, we would be unable to replace reserves which would negatively affect our future rate of growth.
Information concerning our reserves and future net cash flow estimates is uncertain
     There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves and their values, including many factors beyond our control. Estimates of proved reserves are by their nature uncertain. Although we believe these estimates are reasonable, actual production, revenues and costs to develop will likely vary from estimates and these variances could be material.
     Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of natural gas and oil that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves and future net cash flows based on the same available data. Because of the subjective nature of natural gas and oil reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:
    the amount and timing of natural gas and oil production;
    the revenues and costs associated with that production; and
    the amount and timing of future development expenditures.
     The discounted future net cash flows from our proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on a twelve month average price (beginning of month) while cost estimates are as of the end of the year. Actual future prices and costs may be materially higher or lower. In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting

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purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.
If natural gas and oil prices decrease or drilling efforts are unsuccessful, we may be required to record writedowns of our natural gas and oil properties
     In the past we have been required to write down the carrying value of certain of our natural gas and oil properties, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur when natural gas and oil prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in our drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the expected economics.
     Accounting rules require that the carrying value of natural gas and oil properties be periodically reviewed for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write down the carrying value of a property based on natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, and other factors. While an impairment charge reflects our long-term ability to recover an investment, it does not impact cash or cash flow from operating activities, but it does reduce our reported earnings and increases our leverage ratios.
Significant capital expenditures are required to replace our reserves
     Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, our bank credit facility and debt and equity issuances. We have also engaged in asset monetization transactions. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of natural gas and oil and our success in developing and producing new reserves. If our access to capital were limited due to numerous factors, which could include a decrease in revenues due to lower natural gas and oil prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to replace our reserves. We may not be able to incur additional bank debt, issue debt or equity, engage in asset monetization or access other methods of financing on an economic basis to meet our reserve replacement requirements.
     The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders, at their discretion, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The decline in natural gas and oil prices in 2008 adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. If commodity prices (particularly natural gas prices) continue to decline, it will have similar adverse effects on our reserves and borrowing base.
Our future success depends on our ability to replace reserves that we produce
     Because the rate of production from natural gas and oil properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional natural gas and oil reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future natural gas and oil production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.
     We acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

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Our indebtedness could limit our ability to successfully operate our business
     We are leveraged and our exploration and development program will require substantial capital resources depending on the level of drilling and the expected cost of services. Our existing operations will also require ongoing capital expenditures. In addition, if we decide to pursue additional acquisitions, our capital expenditures will increase, both to complete such acquisitions and to explore and develop any newly acquired properties.
     The degree to which we are leveraged could have other important consequences, including the following:
    we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;
    a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;
    we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;
    our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;
    we are subject to numerous financial and other restrictive covenants contained in our existing credit agreements the breach of which could materially and adversely impact our financial performance;
    our debt level could limit our flexibility to grow the business and in planning for, or reacting to, changes in our business and the industry in which we operate; and
    we may have difficulties borrowing money in the future.
     Despite our current levels of indebtedness, we still may be able to incur substantially more debt. This could further increase the risks described above. In addition to those risks above, we may not be able to obtain funding on acceptable terms.
Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully covered under our insurance policies
     Natural gas and oil operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic natural gas and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:
    injury or loss of life;
    severe damage to or destruction of property, natural resources and equipment;
    pollution or other environmental damage;
    clean-up responsibilities;
    regulatory investigations and penalties; or
    suspension of operations.
     We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. We have experienced substantial increases in premiums, especially in areas affected by hurricanes and tropical storms. Insurers have imposed revised limits affecting how much the insurers will pay on actual storm claims plus the cost to re-drill wells where substantial damage has been incurred. Insurers are also requiring us to retain larger deductibles and reducing the scope of what insurable losses will include. Even with the increase in future insurance premiums, coverage will be reduced, requiring us to bear a greater potential risk if our natural gas and oil properties are damaged. We do not maintain any business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could have a material adverse affect on our financial condition and results of operations.
We are subject to financing and interest rate exposure risks
     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 our 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, at December 31, 2010, approximately 86% of our debt is at fixed interest rates with the remaining 14% subject to variable interest rates.

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     Continuing disruptions and volatility in the global finance 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 are exposed to some credit risk related to our bank credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing revolving line of credit if it experiences liquidity problems.
Difficult conditions in the global capital markets, the credit markets and the economy in general may materially adversely affect our business and results of operations
     Global financial markets have been disrupted and volatile and economic conditions remain weak. As a result of concerns about the stability of financial markets in general and the solvency of counterparties specifically, the cost of accessing the credit markets generally has increased, as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and limited the amount of funding available to borrowers. As a result, we may be unable to obtain adequate funding under our current credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) the amount we may borrow under our current credit facility could be reduced as a result of lower natural gas, natural gas liquids or oil prices, declines in reserves, stricter lending requirements or regulations, or for other reasons.
     Due to these factors, we cannot be certain that funding will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our production, revenues and results of operations.
Hedging transactions may limit our potential gains and involve other risks
     To manage our exposure to price risk, we, from time to time, enter into hedging arrangements, utilizing commodity derivatives with respect to a significant portion of our future production. The goal of these hedges is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions limit our potential gains if natural gas and oil prices rise above the price established by the hedge.
     In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
    our production is less than expected;
    the counterparties to our futures contracts fail to perform under the contracts; or
    an event materially impacts natural gas or oil prices or the relationship between the hedged price index and the natural gas or oil sales price.
     We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of natural gas or oil. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in natural gas or oil prices than our competitors who engage in hedging transactions.
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 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, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the Act, the CFTC has proposed regulations to set position limits for certain futures and options contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible at this time to predict when the CFTC will finalize these regulations. 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 new legislation and any new regulations could significantly increase the cost of derivative contracts (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of

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derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the 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 natural gas and oil prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas and oil. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
Many of our current and potential competitors have greater resources than we have and we may not be able to successfully compete in acquiring, exploring and developing new properties
     We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods, services and employees needed to operate and manage our business and marketing natural gas or oil. Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address these competitive factors more effectively than we can or weather industry downturns more easily than we can.
The demand for field services and their ability to meet that demand may limit our ability to drill and produce our oil and natural gas properties
     In a rising price environment, such as those experienced in 2007 and early 2008, well service providers and related equipment and personnel are in short supply. This caused escalating prices, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. In some cases, we are operating in areas where services and infrastructure are limited, or do not exist or in urban areas which are more restrictive.
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 (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“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 ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress.
     While our natural gas gathering operations are generally exempt from FERC regulation under the NGA, our gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has recently issued a final rule requiring certain participants in the natural gas market, including certain gathering facilities and natural gas marketers that engage in a minimum level of natural gas sales or purchases, to submit annual reports to FERC on the 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. In addition, FERC has issued a final rule requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering more than an average of 50 million MMBtu of gas over the previous three calendar years, to post daily, certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu per day.
     Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, please see “Government Regulation” in Item 1 of this report.

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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 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 operations have not been regulated as a natural gas company by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdiction facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. 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 Range to civil penalty liability. For more information regarding regulation of our operations, please see “Government Regulation” in Item 1 of this report.
The natural gas and oil industry is subject to extensive regulation
     The natural gas and oil industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and regulations binding on participants in the natural gas and oil industry. Compliance with such rules and regulations often increases our cost of doing business, delays our operations and, in turn, decreases our profitability.
     Our operations are subject to numerous and increasingly strict federal, state and local laws, regulations and enforcement policies relating to the environment. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies and may incur costs arising out of property damage or injuries to employees and other persons. These costs may result from our current and former operations and even may be caused by previous owners of property we own or lease or relate to third party sites. Any past, present or future failure by us to completely comply with environmental laws, regulations and enforcement policies could cause us to incur substantial fines, sanctions or liabilities from cleanup costs or other damages. Incurrence of those costs or damages could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.
     Climate change is receiving increasing attention from scientists, legislators and governmental agencies. There is an ongoing debate as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
     There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations to control or restrict emissions, taxes or other charges to deter emissions of greenhouse gases, energy efficiency requirements to reduce demand, or other regulatory actions. These actions could:
    result in increased costs associated with our operations;
    increase other costs to our business;
    affect the demand for natural gas; and
    impact the prices we charge our customers.
     Adoption of federal or state requirements mandating a reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows. For more information regarding the environmental regulation of our business, see “Environment and Occupational Matters” in Item 1 of this report.
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

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changes could be effective. As of December 31, 2010, we had a tax basis of $773.0 million related to prior year capitalized intangible drilling costs, which will be amortized over the next five years.
     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, Pennsylvania Governor Ed Rendell’s budget proposal for fiscal year 2011, released on February 9, 2009, proposed a new natural gas wellhead tax on both volumes and sales of natural gas extracted in Pennsylvania, where the majority of our acreage in the Marcellus Shale 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 Marcellus Shale.
Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business
     We could be subject to significant liabilities related to our acquisitions. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. However, even a detailed review of all properties and records may not reveal existing or potential problems in all of the properties, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed.
     In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are unable to obtain financing on terms acceptable to us or regulatory approvals.
     Acquisitions often pose integration risks and difficulties. In connection with recent and future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Future acquisitions could result in our incurring additional debt, contingent liabilities, expenses and diversion of resources, all of which could have a material adverse effect on our financial condition and operating results.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel
     Our success is highly dependent on our management personnel and none of them is currently subject to an employment contract. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.
Drilling is an uncertain and costly activity
     The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough natural gas and oil to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a result of other factors, including:
    high costs, shortages or delivery delays of drilling rigs, equipment, labor, or other services;
    unexpected operational events and drilling conditions;
    reductions in natural gas and oil prices;
    limitations in the market for natural gas and oil;
    adverse weather conditions;
    facility or equipment malfunctions;
    equipment failures or accidents;
    title problems;
    pipe or cement failures;

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    casing collapses;
    compliance with environmental and other governmental requirements;
    environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;
    lost or damaged oilfield drilling and service tools;
 
    unusual or unexpected geological formations;
    loss of drilling fluid circulation;
    pressure or irregularities in formations;
    fires;
    natural disasters;
    surface craterings and explosions; and
    uncontrollable flows of oil, natural gas or well fluids.
     If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
New technologies may cause our current exploration and drilling methods to become obsolete
     The natural gas and oil industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.
New legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
     Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (natural gas and oil) production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, especially shale formations such as the Barnett Shale and the Marcellus Shale. The process is typically regulated by state oil and gas commissions. However, the U.S. Environmental Protection Agency, or the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control 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, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities and a committee of the U.S. House of Representative is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and also to attendant permitting delays and potential increases in costs.
     Additionally, on December 7, 2010, the EPA issued an order to us to take certain action with regard to the existence of natural gas in two water wells located in southern Parker County, Texas that the EPA concluded resulted from two of our wells in the Barnett Shale formation, thousands of feet below the impacted aquifer. On January 18, 2011, the EPA filed an action in federal court to enforce the order and its penalty provisions of up to $16,500 per day per violation. While we are vigorously contesting this enforcement action and seeking relief from the order in federal appeals court, we cannot predict the outcome of either the enforcement action or appeal. However, we do not believe the ultimate resolution of this matter will have a material impact on our financial position, statement of operations or cash flows. Please see “Action by the United States Environmental Protection Agency” in Item 1 of this report.

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Our business depends on natural gas and oil transportation and processing facilities, most of which are owned by others
     The marketability of our natural gas and oil production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties. The lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. We generally do not purchase firm transportation on third party facilities and therefore, our production transportation can be interrupted by those having firm arrangements. We have recently entered into some firm arrangements in certain of our production areas. We have also entered into long-term agreements with third parties to provide natural gas gathering and processing services in the Marcellus Shale. Federal and state regulation of natural gas and oil production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport natural gas and oil. If any of these third party pipelines and other facilities become partially or fully unavailable to transport or process our product, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected.
     The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. In particular, the disruption of certain third-party natural gas processing facilities in the Marcellus Shale could materially affect our ability to market and deliver natural gas production in that area. We have no control over when or if such facilities are restored and generally have no control over what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.
Any failure to meet our debt obligations could harm our business, financial condition and results of operations
     If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or restructure our debt. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.
We exist in a litigious environment
     Any constituent could bring suit regarding our existing or planned operations or allege a violation of an existing contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations could impact our future operations and financial condition. Such legal disputes could also distract management and other personnel from their primary responsibilities.
Our financial statements are complex
     Due to United States generally accepted accounting principles and the nature of our business, our financial statements continue to be complex, particularly with reference to hedging, asset retirement obligations, equity awards, deferred taxes and the accounting for our deferred compensation plans. We expect such complexity to continue and possibly increase.
Risks Related to Our Common Stock
Common stockholders will be diluted if additional shares are issued
     In 2004, 2005 and 2006, we sold 40.2 million shares of common stock to finance acquisitions. In 2007, we sold 8.1 million shares of common stock to finance acquisitions. In 2008, we sold 4.4 million shares of common stock with the proceeds used to pay down a portion of the outstanding balance of our bank credit facility. In 2009, we issued 744,000 shares of common stock to purchase acreage in the Marcellus Shale. In 2010, we issued 380,000 shares of common stock to purchase acreage in the Marcellus Shale. Our ability to repurchase securities for cash is limited by our bank credit facility and our senior subordinated note agreements. We also issue restricted stock and stock appreciation rights to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional subordinated notes or other securities or debt convertible into common stock, to extend maturities or fund capital expenditures, including acquisitions. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.

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Dividend limitations
     Limits on the payment of dividends and other restricted payments, as defined, are imposed under our bank credit facility and under our senior subordinated note agreements. These limitations may, in certain circumstances, limit or prevent the payment of dividends independent of our dividend policy.
Our stock price may be volatile and you may not be able to resell shares of our common stock at or above the price you paid
     The price of our common stock fluctuates significantly, which may result in losses for investors. The market price of our common stock has been volatile. From January 1, 2008 to December 31, 2010, the price of our common stock reported by the New York Stock Exchange ranged from a low of $23.77 per share to a high of $76.81 per share. We expect our stock to continue to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These factors include:
    changes in natural gas and oil prices;
    variations in quarterly drilling, recompletions, acquisitions and operating results;
    changes in governmental regulation;
    changes in financial estimates by securities analysts;
    changes in market valuations of comparable companies;
    additions or departures of key personnel; or
    future sales of our stock.
     We may fail to meet expectations of our stockholders or of securities analysts at some time in the future and our stock price could decline as a result.
ITEM 1B. UNRESOLVED STAFF COMMENTS
     None.
ITEM 2. PROPERTIES
Property Overview
     Our natural gas and oil operations are concentrated in the Appalachian and Southwestern regions of the United States. Our properties consist of interests in developed and undeveloped natural gas and oil leases in these regions. These interests entitle us to drill for and produce natural gas, natural gas liquids and oil from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, royalty and overriding royalty interests. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments; therefore, segment reporting is not applicable to us. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.
     The table below summarizes data for our operating regions for the year ended December 31, 2010.
                                         
    Average                        
    Daily                        
    Production                   Proved   Percentage of
    (Mcfe   Production   Percentage of   Reserves   Proved
Region   per day)   (Mcfe)   Production   (Mmcfe)   Reserves
Southwestern
    238,806       87,164,172       48 %     1,605,435       36 %
Appalachian
    256,507       93,625,080       52 %     2,836,855       64 %
 
                                       
 
    495,313       180,789,252       100 %     4,442,290       100 %
 
                                       
     Approximately 81% of our proved reserves at December 31, 2010 are located in the Marcellus Shale and Nora Area in our Appalachia region and the Barnett Shale in our Southwestern region. Each of these plays has a large portfolio of drilling opportunities. Our reserve estimates do not include any probable or possible reserves.

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     The following table below sets forth annual production volumes, sales price and cost data for our largest fields (those whose reserves are greater than 15% of our total proved reserves).
                         
    Year Ended December 31, 2010
    Marcellus
(Independence)
  Barnett
(Newark East)
  Nora
Production information:
                       
Natural gas (Mmcf)
    39,577       35,886       21,269  
Natural gas liquids (Mbbls)
    2,209       890        
Crude oil (Mbbls)
    496       35        
Total Mmcfe (a)
    55,802       41,432       21,269  
 
                       
Average sales prices (wellhead): (b)
                       
Natural gas (per mcf)
  $ 3.56     $ 3.19     $ 3.03  
Natural gas liquids (per bbl)
    41.44       36.08        
Crude oil (per bbl)
    48.98       75.62        
Total (per mcfe)
    4.60       3.60       3.03  
 
                       
Production costs:
                       
Lease operating (per mcfe)
  $ 0.37     $ 0.85     $ 0.48  
Production and ad valorem tax (per mcfe)
          0.18       0.13  
 
(a)   Oil and NGLs are converted at the rate of one barrel equal six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
 
(b)   We do not record the result of hedging at the field level.
                         
    Year Ended December 31, 2009
    Marcellus
(Independence)
  Barnett
(Newark East)
  Nora
Production information:
                       
Natural gas (Mmcf)
    15,336       40,078       19,133  
Natural gas liquids (Mbbls)
    721       602        
Crude oil (Mbbls)
    218       34        
Total Mmcfe (a)
    20,969       43,893       19,133  
 
                       
Average sales prices (wellhead): (b)
                       
Natural gas (per mcf)
  $ 2.69     $ 2.51     $ 3.17  
Natural gas liquids (per bbl)
    33.84       25.45        
Crude oil (per bbl)
    49.93       58.05        
Total (per mcfe)
    3.65       2.68       3.17  
 
                       
Production costs:
                       
Lease operating (per mcfe)
  $ 0.36     $ 0.80     $ 0.53  
Production and ad valorem tax (per mcfe)
          0.15       0.17  
 
(a)   Oil and NGLs are converted at the rate of one barrel equal six mcf based upon the approximate relative energy content of oil to gas, which is not necessarily indicative of the relationship of oil and gas prices.
 
(b)   We do not record the result of hedging at the field level.

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    Year Ended December 31, 2008
    Marcellus
(Independence)
  Barnett
(Newark East)
  Nora
Production information:
                       
Natural gas (Mmcf)
    4,217       32,165       17,126  
Natural gas liquids (Mbbls)
    94       354        
Crude oil (Mbbls)
    73       39        
Total Mmcfe (a)
    5,215       34,520       17,126  
 
                       
Average sales prices (wellhead): (b)
                       
Natural gas (per mcf)
  $ 9.83     $ 6.79     $ 8.54  
Natural gas liquids (per bbl)
    51.42       45.64        
Crude oil (per bbl)
    90.83       99.78        
Total (per mcfe)
    10.14       6.91       8.54  
 
                       
Production costs:
                       
Lease operating (per mcfe)
  $ 0.73     $ 0.86     $ 0.49  
Production and ad valorem tax (per mcfe)
          0.17       0.32  
 
(a)   Oil and NGLs are converted at the rate of one barrel equal six mcf based upon the approximate relative energy content of oil to gas, which is not necessarily indicative of the relationship of oil and gas prices.
 
(b)   We do not record the result of hedging at the field level.
Appalachian Region
     Our properties in this area are located in the Appalachian Basin in the northeastern United States, principally in Pennsylvania, West Virginia and Virginia. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Huron Shale, Big Lime and Marcellus Shale formations at depths ranging from 2,500 to 9,000 feet. We own 4,969 net producing wells, 78% of which we operate, and approximately 2,750 miles of gas gathering lines. Our average working interest is 71%. We have approximately 1.8 million gross (1.5 million net) acres under lease, which include 340,000 acres where we also own a royalty interest.
     Reserves at December 31, 2010 were 2.8 Tcfe, an increase of 1.0 Tcfe, or 56%, from 2009 with drilling additions partially offset by asset sales (189.6 Bcfe) and production. Annual production increased 43% over 2009. During 2010, this region spent $735.5 million to drill 285.0 (196.7 net) development wells, of which 284.0 (195.7 net) were productive, and 7.0 (5.4 net) exploratory wells, of which 5.0 (3.4 net) were productive. At December 31, 2010, the Appalachian region had an inventory of 2,060 proven drilling locations and 655 proven recompletions. During the year, the Appalachian region drilled 168 proven locations, added 522 new proven locations and deleted 1,400 proven locations due to asset sales.
Marcellus Shale
     We began operations in the Marcellus Shale in Pennsylvania during 2004. The Marcellus Shale is a non-conventional reservoir which produces natural gas and NGLs. This has been our largest investment area over the last three years. We had 422 proven drilling locations at December 31, 2010. Our 2010 production was 166% greater than 2009. During 2010, we drilled 113.6 net development wells and 3.9 net exploratory wells in the Marcellus Shale, of which 114.4 net wells were successful. In 2011, we plan to drill 196 wells. During 2010, we had approximately 12 drilling rigs in the field and expect to run 12 to 16 rigs throughout 2011.
     We have long-term agreements with third parties to provide gathering and processing services and infrastructure assets in the Marcellus Shale. In fourth quarter 2009, MarkWest Liberty Midstream, L.L.C. completed a phase two expansion, pursuant to these agreements. This expansion included an additional 120,000 mcf per day of cryogenic natural gas processing, 20 additional miles of gathering and residue gas pipelines and 21,000 horsepower of additional compression. MarkWest expects additional cryogenic processing capacity to be completed in the first half of 2011.
Nora Area
     In 2004, we acquired natural gas properties in the Nora Area. In 2007, through an acquisition, we equalized our working interests in a portion of the field with EQT Corporation and entered into a joint development plan. We have over 1,600 proven drilling locations in the Nora Area. Production in the Nora Area increased from 52,400 Mcfe per day in 2009 to 58,300 Mcfe per day net in 2010. During

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2010, we drilled 83.1 net development wells and 1.5 net exploratory wells and achieved a 100% drilling success rate. During 2010, we spent $134.5 million to purchase proved and unproved natural gas properties in this area. In 2011, we plan to drill 83 wells.
Southwestern Region
     The Southwestern region includes drilling, production and field operations in the Barnett Shale of North Central Texas, the Permian Basin of West Texas and eastern New Mexico, and the East Texas Basin, as well as in the Texas Panhandle, Anadarko Basin of western Oklahoma and Louisiana and Mississippi. In the Southwestern region, we own 1,954 net producing wells, 96% of which we operate. Our average working interest is 80%. We have approximately 886,000 gross (569,000 net) acres under lease.
     Total proved reserves in the Southwestern region increased 290.9 Bcfe, or 22%, at December 31, 2010, when compared to year-end 2009. Drilling additions (268.2 Bcfe) and a favorable reserve revision for higher prices and performance were partially offset by production. Annual production volumes decreased 7% from 2009. During 2010, this region spent $160.5 million to drill 71 (59.8 net) development wells, of which 69.0 (57.8 net) were productive, and 4.0 (4.0 net) exploratory wells, of which 3.0 (3.0 net) were productive. During the year, the region achieved a 96% drilling success rate.
     At December 31, 2010, the Southwestern region had a development inventory of 338 proven drilling locations and 426 proven recompletions. During the year, the Southwestern region drilled 27 proven locations and added 110 new proven locations. Development projects include recompletions, infill drilling and to a lesser extent, installation of secondary recovery projects. These activities also include increasing reserves and production through cost control, upgrading lifting equipment, improving gathering systems and surface facilities, and performing restimulations and refracturing operations.
Barnett Shale
     Our operations in the Barnett Shale of North Texas began with the 2006 acquisition of Stroud Energy. We added additional properties from various acquisitions during 2007 and 2008. We now own approximately 52,000 net proved and unproved acres. At December 31, 2010, we have 210 proven drilling locations in this area, and 30 proven recompletions. Our production in the Barnett Shale decreased from 120,255 mcfe per day in 2009 to 113,512 mcfe per day in 2010. The Barnett Shale is a non-conventional reservoir and it produces natural gas and NGLs. During 2010, we drilled 24.7 net development wells, of which 22.7 wells were successful.
     In October 2010, we announced our plans to offer for sale our Barnett properties. The properties include approximately 350 producing wells and 700 proven and unproven drilling locations. Parties began conducting evaluations in December 2010 and on February 28, 2011, we announced we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to typical post-closing adjustments. However, the completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.

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Proved Reserves
     In December 2008, the SEC announced that it had approved revisions to modernize its oil and natural gas company reserve reporting requirements. We adopted the new rules as of December 31, 2009. The following table sets forth our estimated proved reserves based on the new SEC rules as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K:
                                         
    Summary of Oil and Gas Reserves as of Fiscal
    Year-End Based on Average Fiscal Year Prices
    Natural                
    Gas   NGLs   Oil   Total    
Reserve Category   (Mmcf)   (Mbbls)   (Mbbls)   (Mmcfe)(a)   %
2010:
                                       
Proved
                                       
Developed
    1,762,766       53,071       17,050       2,183,488       49 %
Undeveloped
    1,803,760       69,651       6,189       2,258,802       51 %
 
                                       
Total Proved
    3,566,526       122,722       23,239       4,442,290          
 
                                       
 
                                       
2009:
                                       
Proved
                                       
Developed
    1,445,705       26,205       20,626       1,726,696       55 %
Undeveloped
    1,169,012       25,382       13,457       1,402,043       45 %
 
                                       
Total Proved
    2,614,717       51,587       34,083       3,128,739          
 
                                       
 
a)   Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
     The following table sets forth our estimated proved reserves for 2008, 2007 and 2006 based on end of year prices:
                                         
    Natural Gas   NGLs   Oil   Total    
    (Mmcf)   (Mbbls)   (Mbbls)   (Mmcfe) (a)   %
2008:
                                       
Proved
                                       
Developed
    1,337,978       16,398       32,611       1,632,032       62 %
Undeveloped
    875,568       7,451       16,876       1,021,531       38 %
 
                                       
Total proved
    2,213,546       23,849       49,487       2,653,563          
 
                                       
 
                                       
2007:
                                       
Proved
                                       
Developed
    1,144,709       13,487       33,528       1,426,801       64 %
Undeveloped
    688,088       4,261       15,384       805,961       36 %
 
                                       
Total proved
    1,832,797       17,748       48,912       2,232,762          
 
                                       
 
                                       
2006:
                                       
Proved
                                       
Developed
    875,395       10,590       27,160       1,101,895       63 %
Undeveloped
    560,583       3,051       12,906       656,331       37 %
 
                                       
Total proved
    1,435,978       13,641       40,066       1,758,226          
 
                                       
 
(a)   Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

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     The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2010:
                                                         
    Reserve Volumes     PV-10 (a)  
                                            Amount        
    Natural Gas     NGL     Oil     Total             (In        
    (Mmcf)     (Mbbls)     (Mbbls)     (Mmcfe)     %     thousands)     %  
Appalachian Region
    2,371,683       72,872       4,657       2,836,855       64 %   $ 2,657,056       57 %
Southwestern Region
    1,194,843       49,850       18,582       1,605,435       36 %     1,990,296       43 %
 
                                         
Total
    3,566,526       122,722       23,239       4,442,290       100 %   $ 4,647,352       100 %
 
                                         
 
(a)   PV-10 was prepared using the twelve-month average prices for 2010, discounted at 10% per annum. Year-end PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, 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 prices 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 of $1.2 billion at December 31, 2010. Included in the $4.6 billion PV-10 is $3.2 billion (pre-tax) related to proved developed reserves.
Reserve Estimation
     The following independent petroleum consultants conducted a review of our year-end 2010 reserves: DeGolyer and MacNaughton (Southwestern), H.J. Gruy and Associates, Inc. (Southwestern) and Wright and Company, Inc. (Appalachian). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2010, these consultants collectively reviewed approximately 90% of our proved reserves. A copy of the summary reserve report of each of these independent petroleum consultants is included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing 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. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their review process. Throughout the year, our technical team meets periodically with representatives of each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest, natural gas and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering. In some cases, additional meetings are held to review additional reserve work performed by the technical teams related to any identified reserve differences.
     Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report on Form 10-K are those reserves estimated by our employees. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering, who reports directly to our President and Chief Operating Officer. Our Senior Vice President of Reservoir Engineering holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has thirty years of experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operation conditions. We did not file any reports during the year ended December 31, 2010 with any federal authority or agency with respect to our estimate of natural gas and oil reserves.
Reserve Technologies
     Proved reserves are those quantities of oil and natural gas, 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, our internal technical staff employed technologies that have been demonstrated to yield results

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with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, seismic data, well test data and reservoir simulation modeling.
Reporting of Natural Gas Liquids and Oil
     We produce natural gas liquids as part of the processing of our natural gas. The extraction of natural gas liquids in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2010, natural gas liquids represented approximately 17% of our total proved reserves on an mcf equivalent basis. Natural gas liquids are products sold by the gallon. In reporting proved reserves and production of natural gas liquids, we have included production and reserves in barrels. Prices for a barrel of natural gas liquids in 2010 averaged approximately 56% lower than the average prices for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of natural gas liquids.
Proved Undeveloped Reserves (PUDs)
     As of December 31, 2010, our PUDs totaled 6.2 Mmbbls of crude oil, 69.7 Mmbbls of natural gas liquids and 1.8 Tcf of natural gas, for a total of 2.3 Tcfe. Costs incurred relating to the development of PUDs were approximately $192.0 million in 2010. Approximately 93% of our PUDs at year-end 2010 were associated with our major development areas in our Marcellus, Nora and Barnett properties. All PUD drilling locations are scheduled to be drilled prior to the end of 2015 with more than 80% of the future development costs to be spent in the next three years. Changes in PUDs that occurred during the year were due to:
    conversion of approximately 191.2 Bcfe PUDs into proved developed reserves;
    new PUDs added of 1.1 Tcfe; and
    reductions of approximately 230.0 Bcfe in PUDs due to the removal of reserves to comply with SEC five year guidance somewhat offset by 154.0 Bcfe positive revision.
Proved Reserves (PV-10)
     The following table sets forth the estimated future net cash flows, excluding open hedging contracts, from proved reserves, the present value of those net cash flows (PV-10), and the expected benchmark prices and average field prices used in projecting net cash flows over the past five years (in millions, except prices):
                                         
    Year Ended December 31,
    2010   2009   2008   2007   2006
Future net cash flows
  $ 12,516     $ 6,721     $ 8,441     $ 11,908     $ 6,391  
Present value
                                       
Before income tax
    4,647       2,593       3,479       5,205       2,771  
After income tax (Standardized Measure)
    3,479       2,091       2,581       3,666       2,002  
Benchmark prices (NYMEX)
                                       
Gas price (per mcf)
    4.38       3.87       5.71       6.80       5.64  
Oil price (per barrel)
    79.81       60.85       44.60       95.98       61.05  
Wellhead prices
                                       
Gas price (per mcf)
    3.70       3.19       5.23       6.44       5.24  
Oil price (per barrel)
    72.51       54.65       42.76       91.88       57.66  
NGL price (per barrel)
    39.14       34.05       25.00       52.64       25.98  
     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). Based on SEC guidance, prices for 2009 and 2010 were based on a twelve-month average, without escalation. Prices for 2006, 2007 and 2008 were based on prices in effect at December 31 of each year, without escalation. Such calculations are also based on costs in effect at December 31 of each year, without escalation. There can be no assurance that the proved reserves will be produced in the future or that 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.

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Producing Wells
     The following table sets forth information relating to productive wells at December 31, 2010. We also own royalty interests in an additional 2,600 wells in which we do not own a working interest. If we own both a royalty and a working interest in a well, such interests are included in the table below. Wells are classified as natural gas or crude oil according to their predominant production stream. We do not have a significant number of dual completions.
                         
                    Average
    Total Wells   Working
    Gross   Net   Interest
Natural gas
    8,681       6,267       72 %
Crude oil
    767       656       86 %
 
                       
Total
    9,448       6,923       73 %
 
                       
     The day-to-day operations of natural gas and oil properties are the responsibility of the operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.
Drilling Activity
     The following table summarizes drilling activity for the past three years. 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. As of December 31, 2010, we were in the process of drilling 106 gross (101 net) wells.
                                                 
    2010   2009   2008
    Gross   Net   Gross   Net   Gross   Net
Development wells
                                               
Productive
    353.0       253.4       441.0       270.4       602.0       466.0  
Dry
    3.0       3.0       1.0       0.6       6.0       4.9  
Exploratory wells
                                               
Productive
    8.0       6.4       20.0       13.7       20.0       16.1  
Dry
    3.0       3.0       1.0       0.7       6.0       3.2  
Total wells
                                               
Productive
    361.0       259.8       461.0       284.1       622.0       482.1  
Dry
    6.0       6.00       2.0       1.3       12.0       8.1  
 
                                               
Total
    367.0       265.8       463.0       285.4       634.0       490.2  
 
                                               
 
                                               
Success ratio
    98.4 %     97.7 %     99.6 %     99.6 %     98.1 %     98.3 %
Gross and Net Acreage
     We own interests in developed and undeveloped natural gas and oil acreage. These ownership interests generally take the form of working interests in oil and natural gas leases that have varying terms. Developed acreage includes leased acreage that is allocated or assignable to producing wells or wells capable of production even though shallower or deeper horizons may not have been fully explored. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not the acreage contains proved reserves.
     The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2010. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary:

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    Developed Acres   Undeveloped Acres   Total Acres
    Gross   Net   Gross   Net   Gross   Net
Alabama
                67,321       61,047       67,321       61,047  
Louisiana
    8,330       3,068       1,058       505       9,388       3,573  
Mississippi
    4,909       2,912       24,720       10,430       29,629       13,342  
New Mexico
    6,890       4,967       1,200       912       8,090       5,879  
New York
                19,918       10,488       19,918       10,488  
Ohio
    10,113       9,150       37,985       37,621       48,098       46,771  
Oklahoma
    179,376       108,299       93,419       49,660       272,795       157,959  
Pennsylvania
    650,299       586,142       592,542       547,506       1,242,841       1,133,648  
Texas
    248,887       172,159       249,498       154,575       498,385       326,734  
Virginia
    125,813       78,934       260,208       185,256       386,021       264,190  
West Virginia
    65,374       64,145       58,386       57,369       123,760       121,514  
 
                                               
 
    1,299,991       1,029,776       1,406,255       1,115,369       2,706,246       2,145,145  
 
                                               
Average working interest
            79 %             79 %             79 %
 
                                               
Undeveloped Acreage Expirations
     The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years.
                         
    Acres   % of Total
As of December 31,   Gross   Net   Undeveloped
2011
    328,872       275,041       26 %
2012
    268,965       231,690       22 %
2013
    191,791       165,494       16 %
2014
    64,344       59,695       6 %
2015
    50,831       43,815       4 %
     We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. However, we have in the past and expect in the future, to be able to extend the lease terms of some of these leases and exchange or sell some of these leases with other companies. The expirations included in the table above do not take into account the fact that we may be able to extend the lease terms. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future.
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 minimal 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 oil and gas leases; or
    net profit interests.

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ITEM 3. LEGAL PROCEEDINGS
     We have been named as a defendant in a number of legal actions arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without a material adverse effect on our financial position or liquidity, although an unfavorable outcome could have a material adverse effect on the operations of a given interim period or year. See also Note 14 to our consolidated financial statements included in this report.
ITEM 4. (REMOVED AND RESERVED)

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PART II
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
     Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC.” During 2010, trading volume averaged 3.3 million shares per day. The following table shows the quarterly high and low sale prices and cash dividends declared as reported on the NYSE composite tape for the past two years.
                         
                    Cash
                    Dividends
    High   Low   Declared
2009
                       
First quarter
  $ 45.86     $ 30.90     $ 0.04  
Second quarter
    48.78       38.75       0.04  
Third quarter
    52.86       35.48       0.04  
Fourth quarter
    60.13       41.99       0.04  
 
                       
2010
                       
First quarter
  $ 54.65     $ 44.68     $ 0.04  
Second quarter
    53.64       40.00       0.04  
Third quarter
    43.12       32.25       0.04  
Fourth quarter
    46.25       35.11       0.04  
     Between January 1, 2011 and February 25, 2011, the common stock traded at prices between $44.74 and $52.25 per share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.
Holders of Record
     On February 25, 2011, there were approximately 1,467 holders of record of our common stock.
Dividends
     The payment of dividends is subject to declaration by the Board of Directors and depends on earnings, capital expenditures and various other factors. The bank credit facility and our senior subordinated notes allow for the payment of common and preferred dividends, with certain limitations. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of our board and will depend upon our level of earnings and capital expenditures and other matters that the board deems relevant. Dividends on Range common stock are limited to our legally available funds. For more information, see information set forth in Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Issuer Purchases of Equity Securities
     We have a repurchase program approved by the Board of Directors in 2008 for the repurchase of up to $10.0 million of common stock based on market conditions and opportunities. There were no repurchases during 2009 or 2010. As of December 31, 2010, we have $6.8 million remaining under this authorization.

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Stockholder Return Performance Presentation*
     The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of Range’s common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for the five years ended December 31, 2010. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2005, and that dividends were reinvested.
(PERFORMACE GRAPH)
                                                 
    2005   2006   2007   2008   2009   2010
Range Resources Corporation
  $ 100     $ 105     $ 196     $ 132     $ 192     $ 174  
S&P 500 Index
    100       116       122       77       97       112  
DJ U.S. Expl. & Prod. Index
    100       105       151       91       127       149  
 
*   The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.

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ITEM 6. SELECTED FINANCIAL DATA
     The following table shows selected financial information for the five years ended December 31, 2010. Significant producing property acquisitions and dispositions may affect the comparability of year-to-year financial and operating data. In the first half of 2010, we sold our Ohio properties for proceeds of $323.0 million. The financial and statistical data contained in the following discussion reflect our Gulf of Mexico operations, which were sold in 2007, as discontinued operations. This information should be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this report.
                                         
    Year Ended December 31,
    2010   2009   2008   2007   2006
    (in thousands, except per share data)
Balance Sheet Data:
                                       
Current assets (a)
  $ 261,714     $ 175,280     $ 404,311     $ 261,814     $ 388,925  
Current liabilities (b)
    430,562       314,104       353,514       305,433       251,685  
Oil and gas properties, net
    4,922,057       4,898,819       4,842,046       3,492,593       2,603,796  
Total assets
    5,498,586       5,395,881       5,551,879       4,005,293       3,183,382  
Bank debt
    274,000       324,000       693,000       303,500       452,000  
Subordinated notes
    1,686,536       1,383,833       1,097,562       847,158       596,782  
Stockholders’ equity (c)
    2,223,761       2,378,589       2,451,342       1,717,736       1,258,089  
Weighted average diluted shares outstanding
    156,874       154,514       155,943       149,911       138,711  
Cash dividends declared per common share
    0.16       0.16       0.16       0.13       0.09  
 
                                       
Statement of Cash Flow Data:
                                       
Net cash provided from operating activities
  $ 513,322     $ 591,675     $ 824,767     $ 642,291     $ 479,875  
Net cash used in investing activities
    (798,858 )     (473,807 )     (1,731,777 )     (1,020,572 )     (911,659 )
Net cash provided from (used in) financing activities
    287,617       (117,854 )     903,745       379,917       429,416  
 
(a)   2009 includes $8.1 million deferred tax assets compared to $26.9 million in 2007. 2010 includes $131.5 million of unrealized derivative assets compared to $21.5 million in 2009, $221.4 million in 2008, $53.0 million in 2007 and $93.6 million in 2006.
 
(b)   2010 includes $352,000 of unrealized derivative liabilities compared to $14.5 million in 2009, $10,000 in 2008, $30.5 million in 2007 and $4.6 million in 2006. 2010 includes an $11.8 million deferred tax liability compared to $33.0 million in 2008.
 
(c)   Stockholders’ equity includes other comprehensive income (loss) of $67.5 million in 2010 compared to $6.4 million in 2009, $77.5 million in 2008, ($26.8 million) in 2007 and $36.5 million in 2006.

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Statement of Operations Data:
                                         
    Year Ended December 31,  
    2010     2009     2008     2007     2006  
    (in thousands, except per share data)  
Revenues and other income:
                                       
Natural gas, NGL and oil sales
  $ 909,607     $ 839,921     $ 1,226,560     $ 862,537     $ 599,139  
Transportation and gathering
    1,068       486       4,577       2,290       2,422  
Derivative fair value income (loss)
    51,634       66,446       71,861       (9,493 )     142,395  
Gain on the sale of assets
    77,597       10,413       20,166       20       21  
Other
    (931 )     (9,925 )     1,509       5,011       835  
 
                             
Total revenues and other income
    1,038,975       907,341       1,324,673       860,365       744,812  
 
                             
 
                                       
Costs and expenses:
                                       
Direct operating
    131,602       133,211       142,387       107,499       81,261  
Production and ad valorem taxes
    33,652       32,169       55,172       42,443       36,415  
Exploration
    61,087       46,485       67,690       45,782       44,088  
Abandonment and impairment of unproved properties
    69,971       113,538       47,355       11,236       4,549  
General and administrative
    140,571       115,319       92,308       69,670       49,886  
Termination costs
    8,452       2,479                    
Deferred compensation plan
    (10,216 )     31,073       (24,689 )     35,438       (233 )
Interest expense
    131,192       117,367       99,748       77,737       55,849  
Loss on early extinguishment of debt
    5,351                          
Depletion, depreciation and amortization
    363,507       373,502       299,831       220,578       154,482  
Impairment of proved properties
    469,749       930                    
 
                             
Total costs and expenses
    1,404,918       966,073       779,802       610,383       426,297  
 
                             
 
                                       
(Loss) income from continuing operations before income taxes
    (365,943 )     (58,732 )     544,871       249,982       318,515  
 
                                       
Income tax (benefit) expense
                                       
Current
    (836 )     (636 )     4,268       320       1,912  
Deferred
    (125,851 )     (4,226 )     189,563       95,987       120,726  
 
                             
 
    (126,687 )     (4,862 )     193,831       96,307       122,638  
 
                             
 
                                       
(Loss) income from continuing operations
    (239,256 )     (53,870 )     351,040       153,675       195,877  
 
                                       
Discontinued operations, net of taxes
                      63,593       (35,247 )
 
                             
 
                                       
Net (loss) income
  $ (239,256 )   $ (53,870 )   $ 351,040     $ 217,268     $ 160,630  
 
                             
 
                                       
(Loss) income  per common share:
                                       
Basic— (loss) income from continuing operations
  $ (1.53 )   $ (0.35 )   $ 2.32     $ 1.07     $ 1.46  
—discontinued operations
                      0.44       (0.26 )
 
                             
—net (loss) income
  $ (1.53 )   $ (0.35 )   $ 2.32     $ 1.51     $ 1.20  
 
                             
 
                                       
Diluted—(loss) income from continuing operations
  $ (1.53 )   $ (0.35 )   $ 2.25     $ 1.02     $ 1.41  
—discontinued operations
                      0.43       (0.25 )
 
                             
—net (loss) income
  $ (1.53 )   $ (0.35 )   $ 2.25     $ 1.45     $ 1.16  
 
                             

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ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
     The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions for the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements Data in this report.
Overview of Our Business
     We are an independent natural gas and oil company engaged in the exploration, development and acquisition of primarily natural gas and oil properties, mostly in the Appalachian and Southwestern regions of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.
     Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to economically find, develop, acquire and produce natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas, natural gas liquids and oil activities. Our corporate headquarters is located in Fort Worth, Texas.
Industry Environment
     We operate entirely within the United States. As traditional basins in the U.S. have matured, exploration and production has shifted to unconventional “resource” plays, typically shale reservoirs that historically were not thought to be productive for natural gas and oil. These plays cover large areas, provide multi-year inventories of drilling opportunities and, with modern oil and gas technology, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. These advancements make these plays more resilient to lower commodity prices while increasing the domestic supply of natural gas and, with increased supply, an expected reduction in the volatility of natural gas prices. Examples of such technological advancements include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation using almost one hundred percent sand and water, advances in well logging and analysis, horizontal drilling and completion technologies and automated remote well monitoring and control devices.
     Natural gas and oil are commodities. The price that we receive for the natural gas we produce is largely a function of market supply and demand in the United States. 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 price volatility. Factors impacting the future supply balance are the growth in domestic gas production and the increase in the United States’ LNG import capacity. Gas supplies in the United States have increased as a result of recent expansion in domestic unconventional gas production. Existing LNG import capacity may result in lower natural gas prices. Crude oil prices are generally determined by global supply and demand.
     The reduced liquidity provided by the worldwide financial markets and other factors that resulted in an economic slowdown in the United States and other industrialized countries in 2008 also resulted in reductions in worldwide energy demand. At the same time, North American gas supply increased as a result of the expansion in domestic unconventional natural gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply resulted in declines in natural gas prices from their highs in mid-2008. Prices in 2010 and 2009 were more stable than in 2008. However, natural gas prices continue to be under pressure as a result of lower domestic demand and concerns over excess supply of natural gas due to high productivity of several emerging plays in the United States.

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     Natural gas and oil gas prices affect:
    the amount of cash flow available to us for capital expenditures;
 
    our ability to borrow and raise additional capital;
 
    the quantity of natural gas and oil that we can economically produce;
 
    revenues and profitability; and
 
    the accounting for our natural gas and oil activities.
     Any continued or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital.
Capital Budget for 2011
     Our capital budget for 2011 is currently set at $1.38 billion, excluding acquisitions. The 2011 capital budget is more than the 2010 capital spending levels with higher expected operating cash flows resulting from higher production. For 2011, we expect our operating cash flow and proceeds from asset sales to fund our capital budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices, drilling success and other factors.
Source of Our Revenues
     We derive our revenues from the sale of natural gas, natural gas liquids (“NGLs”) and oil that is produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, quality, Btu content and transportation costs to market. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our natural gas and oil production. The use of derivative instruments has in the past and may in the future, prevent us from realizing the full benefit of upward price movements but also protects us from declining price movements. Our average realized price calculations (including all derivative settlements) include the effects of the settlement of all derivative contracts regardless of the accounting treatment.
Principal Components of Our Cost Structure
    Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workovers expenses related to our natural gas and oil properties. These costs are expected to remain a function of supply and demand. Direct operating expenses also include stock-based compensation expense (non-cash) associated with grants of stock appreciation rights (SARs) and the amortization of restricted stock grants as part of employee compensation.
 
    Production and Ad Valorem Taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.
 
    Exploration Expenses. These are geological and geophysical costs, including payroll and benefits for the geological and geophysical staff, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. Exploration expense also includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
 
    Abandonment and impairment of unproved properties. This category includes unproved property impairment and costs associated with lease expirations.
 
    General and Administrative Expenses. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. Included in this category are overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. General and administrative expense also includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
 
    Deferred Compensation Plan Expense. These costs relate to the increase or decrease in the value of the liability associated with our deferred compensation plan. Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion.

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    Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility and with longer-term debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.
 
    Depreciation, Depletion and Amortization Expense. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This expense also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.
 
    Income Taxes. We are subject to state and federal income taxes but are currently not in a cash tax paying position for federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on a basis other than federal taxable income. Currently, substantially all of our federal taxes are deferred and we anticipate using all of our net operating loss carryforwards. For additional information, see “Risk Factors-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,” in Item 1A of this report.
Management’s Discussion and Analysis of Income and Operations
Market Conditions
     Prices for various quantities of natural gas, natural gas liquids (“NGLs”) and oil that we produce significantly impact our revenues and cash flows. Commodity prices have been volatile in recent years. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil for the year ended December 31, 2010, 2009 and 2008. There is no similar published benchmark for NGL prices.
                         
    Year Ended
    December 31,
    2010   2009   2008
Average NYMEX prices (a)
                       
Natural gas (per mcf)
  $ 4.40     $ 4.02     $ 8.91  
Oil (per bbl)
  $ 79.59     $ 60.49     $ 100.47  
 
(a)   Based on average of bid week prompt month prices.

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Overview of 2010 Results
     During 2010, we achieved the following financial and operating results :
    achieved 14% production growth;
 
    achieved 42% proved reserve growth;
 
    drilled 266 net wells with a 98% success rate;
 
    continued expansion of our activities in the Marcellus Shale by growing production, proving up acreage and acquiring additional unproved acreage;
 
    reduced direct operating expenses per mcfe 13%;
 
    reduced DD&A rate 14%;
 
    maintained a strong balance sheet by retaining a debt to capitalization ratio of 47% and issuing $500.0 million of new senior subordinated notes;
 
    used a portion of the proceeds from the issuance of $500.0 million of our 6.75% senior subordinated notes due 2020 to redeem all $200.0 million aggregate principal amount of our 7.375% senior subordinated notes due 2013;
 
    entered into additional derivative contracts for 2011 and 2012;
 
    received proceeds of $327.8 million from asset sales;
 
    realized $513.3 million of cash flow from operating activities; and
 
    ended the year with stockholders’ equity of $2.2 billion.
     Operationally, our 2010 performance reflects another year of successfully executing our strategy of growth through drilling. Our success enabled us to increase proved reserves by 1.3 Tcf, which is more than seven times 2010 production. During 2010, we also purchased 125.0 Bcfe of proved reserves through acquisitions. As evidenced by history, commodity prices are inherently volatile. To maintain our competitive advantage, we have focused our efforts on improving operating efficiency. As reservoirs are depleted and production rates decline, per unit production costs will generally increase. Our production is focused in core areas where we can achieve economies of scale to help manage our operating costs. Our efforts resulted in lower direct operating expense on an absolute dollar basis and on a per mcfe basis for 2010 when compared to 2009 and 2008. We also have continued to expand and develop our natural gas shale plays with most of our focus on the Marcellus Shale. We exited the year producing approximately 212.0 Mmcfe per day in the Marcellus Shale. We drilled 117 net wells, increasing our Marcellus reserves to over 1.9 Tcfe. We will continue to evaluate our Marcellus Shale leases and formulate our development plans for this area.
     Total revenues increased 15% in 2010 over the same period of 2009. This increase was due to higher production and a gain on the sale of assets somewhat offset by lower realized natural gas and oil prices. Our 2010 production growth was due to the continued success of our drilling program. Average realized prices (including all derivative settlements) were 19% lower in 2010. As discussed in Item 1A of this report, significant changes in natural gas and oil prices can have a material impact on our results of operations and our balance sheet including the fair value of our derivatives.
2011 Outlook
     For 2011, the Board has approved a $1.38 billion capital budget for natural gas and oil related activities, excluding proved property acquisitions. We expect to fund our 2011 capital budget expenditures with cash flows from operations and proceeds from asset sales. The price risk on a portion of our forecasted natural gas and oil production for 2011 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions. The prices we receive for our natural gas and oil production are largely based on current market prices, which are beyond our control. In October 2010, we announced our plan to offer for sale our Barnett Shale properties in North Texas and the data room opened in December 2010. These properties include approximately 360 producing wells and 700 proven and unproven drilling locations. On February 28, 2011, we announced that we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, including certain derivative contracts, subject to typical post-closing adjustments. The approximate net book value of these assets at December 31, 2010 was $835.9 million which exclude the derivative contracts being sold. The completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed. For additional information related to this sale, see Note 11 to the consolidated financial statements.
Natural Gas, NGL and Oil Sales, Production and Realized Price Calculations
     Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. Hedges included in natural gas, NGL and oil sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying statements of operations. In 2010, natural gas, NGL and oil sales increased 8% from 2009 with a 14% increase in production partially offset by a 5% decrease in realized prices. In 2009, natural gas, NGL and oil sales decreased 32% from

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2008 due to a 39% decrease in realized prices, partially offset by a 13% increase in production. The following table illustrates the primary components of natural gas, NGL and oil sales for each of the last three years (in thousands):
                         
    2010     2009     2008  
Natural gas, NGL and oil sales
                       
 
Gas wellhead
  $ 533,157     $ 432,821     $ 923,160  
Gas hedges realized
    64,749       190,934       8,561  
 
                 
Total gas revenue
  $ 597,906     $ 623,755     $ 931,721  
 
                 
 
                       
Total NGL revenue
  $ 175,236     $ 63,405     $ 68,492  
 
                 
 
                       
Oil wellhead
  $ 136,442     $ 140,577     $ 298,482  
Oil hedges realized
    23       12,184       (72,135 )
 
                 
Total oil revenue
  $ 136,465     $ 152,761     $ 226,347  
 
                 
Combined wellhead
  $ 844,835     $ 636,803     $ 1,290,134  
Combined hedges
    64,772       203,118       (63,574 )
 
                 
Total natural gas, NGL and oil sales
  $ 909,607     $ 839,921     $ 1,226,560  
 
                 
     Our production continues to grow through drilling success as we place new wells into production and through additions from acquisitions partially offset by the natural decline of our natural gas and oil wells and asset sales. For 2010, our production volumes increased 43% in the Appalachian region and declined 7% in our Southwestern region. Included in the 2010 increase in our Appalachian region is the effect of the sale of our Ohio tight gas sand properties. For 2009, our production volumes increased 28% in the Appalachian region and 4% in the Southwestern region. Crude oil production declined from 2008 primarily due to the sale of certain oil properties in West Texas. Our production for each of the last three years is set forth in the following table:
                         
    2010   2009   2008
Production (a)
                       
Natural gas (mcf)
    142,033,758       130,648,694       114,323,436  
NGLs (bbls)
    4,490,199       2,186,999       1,385,701  
Crude oil (bbls)
    1,969,050       2,556,879       3,084,529  
Total (mcfe) (b)
    180,789,252       159,111,962       141,144,816  
 
                       
Average daily production (a)
                       
Natural gas (mcf)
    389,134       357,942       312,359  
NGLs (bbls)
    12,302       5,992       3,786  
Crude oil (bbls)
    5,395       7,005       8,428  
Total (mcfe) (b)
    495,313       435,923       385,642  
 
(a)   Represents volumes sold regardless of when produced.
 
(b)   Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

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     Our average realized price (including all derivative settlements) received during 2010 was $5.23 per mcfe compared to $6.44 per mcfe in 2009 and $8.58 per mcfe in 2008. Our average realized price (including all derivative settlements) calculation includes all cash settlements for derivatives, whether or not they qualify for hedge accounting, except for the year ended December 31, 2010, we have excluded from average realized price calculations a $15.7 million gain related to an early settlement of oil collars. Average price calculations for each of the last three years are shown below:
                         
    2010   2009   2008
Average Prices
                       
Average sales prices (wellhead):
                       
Natural gas (per mcf)
  $ 3.75     $ 3.32     $ 8.07  
NGLs (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.29       54.98       96.77  
Total (per mcfe) (a)
    4.67       4.00       9.14  
 
                       
Average realized prices (including derivatives that qualify for hedge accounting):
                       
Natural gas (per mcf)
    4.21       4.77       8.15  
NGLs (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.30       59.75       73.38  
Total (per mcfe) (a)
    5.03       5.28       8.69  
 
                       
Average realized prices (including all derivative settlements):
                       
Natural gas (per mcf)
    4.46       6.13       8.15  
NGLs (per bbl)
    39.03       28.99       49.43  
Crude oil (per bbl)
    69.31       62.58       68.20  
Total (per mcfe) (a)
    5.23       6.44       8.58  
 
(a)   Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.
     Derivative fair value income was $51.6 million in 2010 compared to $66.4 million in 2009 and to $71.9 million in 2008. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income in the accompanying consolidated statements of operations. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives will be offset by lower wellhead revenues in the future or any losses will be offset by higher future wellhead revenues based on the value at the settlement date. At December 31, 2010, all of our derivative contracts are recorded at their fair value, which was a net asset of $117.7 million, an increase of $106.8 million from the $10.9 million net asset recorded as of December 31, 2009. We have also entered into basis swap agreements to limit volatility caused by changing differentials between index and regional prices received. These basis swaps do not qualify for hedge accounting and are marked to market. Hedge ineffectiveness, also included in derivative fair value income, is associated with contracts that qualify for hedge accounting. The ineffective portion is calculated as the difference between the change in the fair value of the derivative and the estimated change in future cash flows from the item being hedged.

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     The following table presents information about the components of derivative fair value income for each of the years in the three-year period ended December 31, 2010 (in thousands):
                         
    2010     2009     2008  
Change in fair value of derivatives that do not qualify for hedge accounting (a)
  $ (2,086 )   $ (115,909 )   $ 85,594  
Realized gain (loss) on settlements — natural gas (b) (c)
    35,988       171,998       (1,383 )
Realized gain (loss) on settlements — oil (b) (c)
          7,304       (15,431 )
Realized gain on early settlement of oil derivatives (d)
    15,697              
Hedge ineffectiveness — realized (c)
    (352 )     4,749       1,386  
— unrealized (a)
    2,387       (1,696 )     1,695  
 
                 
Derivative fair value income
  $ 51,634     $ 66,446     $ 71,861  
 
                 
 
(a)   These amounts are unrealized and are not included in average sales price calculations.
 
(b)   These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.
 
(c)   These settlements are included in average realized price calculations (including all derivative settlements).
 
(d)   This early settlement is not included in average realized price calculations.
     Gain on the sale of assets was $77.6 million in 2010 compared to $10.4 million in 2009 and $20.2 million in 2008. During 2010, we sold our tight gas sand properties in Ohio for proceeds of approximately $323.0 million and recorded a gain of $77.6 million. The 2009 period includes a $10.4 million gain on the sale of Marcellus acreage. The 2008 period includes the sale of East Texas properties for proceeds of $64.0 million and a gain of $20.2 million was recorded.
     Other revenue in 2010 was a loss of $931,000 compared to a loss of $9.9 million in 2009 and income of $1.5 million in 2008. The 2010 period includes a loss from equity method investments of $1.5 million partially offset by proceeds of $486,000 from a lawsuit settlement. The 2009 period includes a loss from equity method investments of $13.7 million partially offset by proceeds of $3.8 million from a lawsuit settlement. The 2008 period includes a loss from equity method investments of $218,000.
     We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for 2010, 2009 and 2008.
                                                                 
    Year Ended December 31,   Year Ended December 31,
                            %                           %
    2010   2009   Change   Change   2009   2008   Change   Change
Direct operating expense
  $ 0.73     $ 0.84     $ (0.11 )     (13 %)   $ 0.84     $ 1.01     $ (0.17 )     (17 %)
Production and ad valorem tax expense
    0.19       0.20       (0.01 )     (5 %)     0.20       0.39       (0.19 )     (49 %)
General and administrative expense
    0.78       0.72       0.06       8 %     0.72       0.65       0.07       11 %
Interest expense
    0.73       0.74       (0.01 )     (1 %)     0.74       0.71       0.03       4 %
Depletion, depreciation and amortization expense
    2.01       2.35       (0.34 )     (14 %)     2.35       2.12       0.23       11 %
     Direct operating expense was $131.6 million in 2010 compared to $133.2 million in 2009 and $142.4 million in 2008. We experience increases in operating expenses as we add new wells and maintain production from existing properties. In 2010 and 2009, this effect was more than offset by asset sales, lower overall industry costs and lower workover expenses. On an absolute dollar basis, our spending for direct operating expenses for 2010 was lower when compared to 2009 despite higher production levels reflecting our asset sales and lower overall industry costs. The sale of our Ohio properties in 2010 and the sale of our New York and West Texas properties in 2009 make comparisons of 2010 to 2009 difficult. On a pro forma basis, excluding our sold properties, 2009 direct operating expenses would have been $110.7 million and 2010 direct operating expense would have been $129.0 million. On an absolute dollar basis, our spending for direct operating expenses for 2009 was lower when compared to 2008 despite higher production levels reflecting cost containment measures and lower overall industry costs. We incurred $5.0 million of workover costs in 2010 compared to $6.5 million in 2009 and $9.9 million in 2008.
     On a per mcfe basis, direct operating expense for 2010 decreased $0.11 or 13% from the same period of 2009, with the decrease consisting of primarily lower workover costs ($0.01 per mcfe), lower water disposal costs ($0.02 per mcfe), lower overall well service costs and asset sales. On a pro forma basis, excluding the sale of our Ohio properties in 2010 and the sale of our New York and West Texas properties in 2009, 2009 direct operating expense would have been $0.76 per mcfe and 2010 direct operating expense would have been $0.72 per mcfe. On a per mcfe basis, direct operating expense for 2009 decreased $0.17 or 17% from the same period of 2008 with the decrease consisting primarily of lower workover costs ($0.03 per mcfe),

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lower utility costs ($0.02 per mcfe), lower well service costs, asset sales and our focus on cost containment. We expect to continue to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operating cost relative to our other operating areas. Stock-based compensation expense represents the amortization of restricted stock grants and SARs as part of employee compensation. The following table summarizes direct operating expenses per mcfe for 2010, 2009 and 2008:
                                                                 
    Year Ended December 31,   Year Ended December 31,
                            %                           %
    2010     2009     Change     Change   2009     2008     Change     Change
Lease operating expense
  $ 0.69     $ 0.78     $ (0.09 )     (12 %)   $ 0.78     $ 0.92     $ (0.14 )     (15 %)
Workovers
    0.03       0.04       (0.01 )     (25 %)     0.04       0.07       (0.03 )     (43 %)
Stock-based compensation (non-cash)
    0.01       0.02       (0.01 )     (50 %)     0.02       0.02             %
 
                                                   
Total direct operating expenses
  $ 0.73     $ 0.84     $ (0.11 )     (13 %)   $ 0.84     $ 1.01     $ (0.17 )     (17 %)
 
                                                   
     Production and ad valorem taxes are paid based on market prices, not hedged prices. These costs were $33.7 million in 2010 compared to $32.2 million in 2009 and $55.2 million in 2008. On a per mcfe basis, production and ad valorem taxes decreased to $0.19 in 2010 compared to $0.20 in 2009 due to an increase in production volumes not subject to production or ad valorem taxes. On a per mcfe basis, production and ad valorem taxes decreased to $0.20 in 2009 from $0.39 in 2008 due to a 56% decrease in pre-hedge prices.
     General and administrative expense was $140.6 million for 2010 compared to $115.3 million for 2009 and $92.3 million in 2008. The 2010 increase of $25.3 million when compared to 2009 is due to higher salaries and benefits ($4.6 million), an increase in legal fees and legal settlements ($4.2 million), an increase in community relations costs ($6.5 million), higher bad debt expense ($2.3 million), higher office expenses, including information technology ($1.8 million), and higher industry trade association dues and inventory adjustments. While our number of employees declined 9% during 2010 due to our asset sales, we continue to incur higher wages which we consider necessary to remain competitive in the industry. The 2009 increase of $23.0 million when compared to 2008 is due primarily to higher salaries and benefits ($11.7 million) due to an increase in the number of employees (4%) and salary increases, higher stock based compensation ($9.7 million), higher legal fees and office expenses, including rent and information technology and higher bad debt expense ($1.4 million). Our personnel costs continue to increase as we invest in our technical teams and other staffing to support our expansion into the Marcellus Shale in Appalachia. Stock-based compensation expense represents the amortization of restricted stock grants and SARs granted to our employees and directors as part of compensation. The following table summarizes general and administrative expenses per mcfe for 2010, 2009 and 2008:
                                                                 
    Year Ended December 31,   Year Ended December 31,
                            %                           %
    2010     2009     Change     Change   2009     2008     Change     Change
General and administrative
  $ 0.59     $ 0.51     $ 0.08       16 %   $ 0.51     $ 0.48     $ 0.03       6 %
Stock-based compensation (non-cash)
    0.19       0.21       (0.02 )     (10 %)     0.21       0.17       0.04       24 %
 
                                                   
Total general and administrative expenses
  $ 0.78     $ 0.72     $ 0.06       8 %   $ 0.72     $ 0.65     $ 0.07       11 %
 
                                                   
     Interest expense was $131.2 million for 2010 compared to $117.4 million for 2009 and $99.7 million in 2008. Interest expense for 2010 increased $13.8 million from the same period of 2009 due to the refinancing of certain debt from floating rates to higher fixed rates. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $13.0 million of interest costs in 2010. The proceeds from this issuance was used to retire bank debt which carried a lower interest rate and to redeem all $200.0 million of our 7.375% senior subordinated notes due 2013. Interest expense for 2009 increased $17.7 million from the same period of 2008 due to the refinancing of certain debt from floating rates to higher fixed rates and higher average debt balances. In May 2009, we issued $300.0 million of 8% senior subordinated notes due 2019, which added $15.1 million of interest costs in 2009. In May 2008, we issued $250.0 million of 7.25% senior subordinated notes due 2018, which added $11.8 million of interest costs in 2008. The 2010, 2009 and 2008 note issuances were undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for 2010 was $351.1 million compared to $584.5 million for 2009 and $494.2 million for 2008 and the weighted average interest rate was 2.2% in 2010 compared to 2.4% in 2009 and 4.4% in 2008.
     Depletion, depreciation and amortization (“DD&A”) was $363.5 million in 2010 compared to $373.5 million in 2009 and $299.8 million in 2008. The decrease in 2010 compared to 2009 is due to a 11% decrease in depletion rates and lower depreciation expense partially offset by a 14% increase in production. 2009 included accelerated depreciation expense of $10.3 million on an interim processing plant in Appalachia that was dismantled in the first quarter of 2010 and replaced with permanent facilities. The increase in DD&A for 2009 compared to 2008 is due to a 13% increase in production, a 6% increase

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in depletion rates and accelerated depreciation expense of $10.3 million on an interim processing plant in Appalachia. On a per mcfe basis, DD&A decreased to $2.01 in 2010 compared to $2.35 in 2009 and $2.12 in 2008. Depletion expense, the largest component of DD&A, was $1.89 per mcfe in 2010 compared to $2.11 per mcfe in 2009 and $1.99 per mcfe in 2008. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. In areas where we are actively drilling, such as the Marcellus and Barnett Shale areas, fourth quarter 2010 depletion rates were lower than 2009. Depletion rates in new plays tend to be higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations. The decrease in the DD&A per mcfe in 2010 when compared to 2009 is related to lower depreciation expense and the mix of our production. The increase in DD&A per mcfe in 2009 when compared to 2008 was related to the accelerated depreciation expense on an interim processing plant ($0.06) and the mix of our production. The following table summarizes DD&A expense per mcfe for 2010, 2009 and 2008:
                                                                 
    Year Ended December 31,   Year Ended December 31,
                            %                           %
    2010     2009     Change     Change   2009     2008     Change     Change
Depletion and amortization
  $ 1.89     $ 2.11     $ (0.22 )     (10 %)   $ 2.11     $ 1.99     $ 0.12       6 %
Depreciation
    0.09       0.20       (0.11 )     (55 %)     0.20       0.09       0.11       122 %
Accretion and other
    0.03       0.04       (0.01 )     (25 %)     0.04       0.04             %
 
                                                   
Total DD&A expense
  $ 2.01     $ 2.35     $ (0.34 )     (14 %)   $ 2.35     $ 2.12     $ 0.23       11 %
 
                                                   
Other Operating Expenses
     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In 2010, stock-based compensation was a component of direct operating expense ($2.3 million), exploration expense ($4.2 million), general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.7 million. In 2009, stock-based compensation was a component of direct operating expense ($2.6 million), exploration expense ($4.8 million) and general and administrative expense ($33.5 million) for a total of $41.8 million. In 2008, stock-based compensation was a component of direct operating expense ($2.8 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.2 million. Stock-based compensation includes the amortization of restricted stock grants and SARs grants.
     Exploration expense was $61.1 million in 2010 compared to $46.5 million in 2009 and $67.7 million in 2008. The following table details our exploration-related expenses for 2010, 2009 and 2008. Exploration expense was significantly higher in 2010 when compared to 2009 due to higher delay rental costs, or the costs we incur to defer the commencement of drilling, primarily in our Marcellus Shale operations. Exploration expense was significantly lower in 2009 when compared to 2008 due to our focus on development of our large shale and coal bed methane projects and the closure of our Gulf Coast office. The following table details our exploration related expenses for 2010, 2009 and 2008 (in thousands):
                                                                 
    Year Ended December 31,   Year Ended December 31,
                            %                           %
    2010     2009     Change     Change   2009     2008     Change     Change
Seismic
  $ 22,911     $ 21,995     $ 916       4 %   $ 21,995     $ 30,645     $ (8,650 )     (28 %)
Delay rentals and other
    19,138       6,884       12,254       178 %     6,884       7,740       (856 )     (11 %)
Personnel expense
    11,129       10,743       386       4 %     10,743       11,804       (1,061 )     (9 %)
Stock-based compensation expense
    4,209       4,703       (494 )     (11 %)     4,703       4,130       573       14 %
Dry hole expense
  3,700     2,160     1,540       71 %   2,160     13,371     (11,211 )     (84 %)
 
                                                   
Total exploration expense
  $ 61,087     $ 46,485     $ 14,602       31 %   $ 46,485     $ 67,690     $ (21,205 )     (31 %)
 
                                                   
     Abandonment and impairment of unproved properties was $70.0 million in 2010 compared to $113.5 million in 2009 and $47.4 million in 2008. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate an impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Abandonment and impairment of unproved properties in 2009 was higher due to expirations in the Barnett Shale, which included the expiration of $27.1 million of individually significant leases. As we continue to review our acreage positions and

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high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments will likely be recorded.
     Termination costs in 2010 includes severance costs of $5.1 million related to the sale of our Ohio properties and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel. Termination costs in 2009 represent severance costs related to the closing of our Houston office ($1.6 million), $332,000 of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Houston personnel and $635,000 of severance costs related to the sale of our New York properties.
     Deferred compensation plan expense was a gain of $10.2 million in 2010 compared to a loss of $31.1 million in 2009 and a gain of $24.7 million in 2008. Our stock price decreased to $44.98 at December 31, 2010 compared to $49.85 at December 31, 2009. Our stock price increased to $49.85 at December 31, 2009 compared to $34.39 at December 31, 2008. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.
     Loss on early extinguishment of debt expense for 2010 was $5.4 million. In August 2010 we redeemed our 7.375% senior subordinated notes due 2013 at a redemption price equal to 101.229%. We recorded a loss on extinguishment of debt of $5.4 million which includes call premium costs of $2.5 million and expensing of related deferred financing costs on the repurchased debt.
     Impairment of proved properties increased to $469.7 million compared to $930,000 in 2009. While our Barnett properties did not meet held for sale criteria as of December 31, 2010, our analysis reflected undiscounted cash flows for these properties were less than their carrying value. We therefore compared the carrying value of the Barnett properties to the estimated fair value of the properties and recognized an impairment charge of $463.2 million in fourth quarter of 2010. The year ended 2010 also includes a $6.5 million impairment related to our onshore Gulf Coast properties. In 2009 we recognized $930,000 impairment related to our Michigan properties. These assets were reviewed for impairment due to declining reserves and natural gas prices.
     Income tax (benefit) expense was a benefit of $126.7 million compared to a benefit of $4.9 million in 2009 and expense of $193.8 million in 2008. The 2010 increase in income tax benefit reflects a 523% decrease in loss before income taxes when compared to the same period of 2009. The effective tax rate in 2010 was 34.6% compared to an effective tax rate of 8.3% in 2009. For the year ended December 31, 2010, the current income tax benefit of $836,000 is related to state income taxes. The effective tax rate was different than the statutory rate of 35% due to an increase in state deferred tax expense related to an increase in our estimated apportionment in states with higher tax rates and an increase in our valuation allowances. The 2009 decrease reflects a 111% decrease in income before income taxes compared to the same period of 2008. The year ended December 31, 2009 also includes an unfavorable $16.3 million charge to reflect updated state tax rates used to establish deferred taxes due to a change in our state apportionment factors to states with higher rates, particularly in Pennsylvania, with our increased focus on development of the Marcellus Shale, along with increased proved reserves and acreage in Pennsylvania. The 2009 effective tax rate was 8.3% compared to an effective tax rate in 2008 of 35.6%. For the year ended December 31, 2009, the current income tax benefit of $636,000 includes state income taxes of $364,000 and a federal income tax benefit of $1.0 million. The effective tax rate was different than the statutory rate of 35% due to an increase in our state apportionment factors in certain higher-rate states, offset by a benefit related to a partial release of valuation allowance on our capital loss carryforward. 2008 provided for tax expenses at an effective rate of 35.6%. 2008 current income taxes of $4.3 million include state income taxes of $3.3 million and $1.0 million of federal income taxes and the effective tax rate was different than the statutory rate of 35% due to state income taxes. We expect our effective tax rate to be approximately 38–39% for 2011.
Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity
     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, asset sales and access to the debt and equity capital markets. We continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. During 2010, we sold our shallow tight gas sand Ohio properties for proceeds of approximately $323.0 million. We used a portion of these proceeds to purchase proved and unproved properties primarily in Virginia. The remainder of these proceeds was used to repay amounts under our bank credit facility. In 2010, we entered into additional commodity derivative contracts for 2011 and 2012 to protect future cash flows. As part of our semi-annual bank review completed October 8, 2010, our borrowing base and facility amounts were reaffirmed at $1.5 billion and $1.25 billion. On February 18, 2011, we announced we have entered into an amended and restated revolving bank facility, which replaced our previous bank credit facility. The new facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. At closing, the borrowing base amount was $2.0 billion and the facility amount was $1.5 billion.
     During 2010, our net cash provided from continuing operations of $513.3 million, proceeds from the sale of assets of $327.8 million and borrowings under our bank credit facility were used to fund $1.1 billion of capital expenditures (including acquisitions and equity investments). At December 31, 2010, we had $2.8 million in cash and total assets of $5.5 billion. Our debt to capitalization ratio was 47%. As of December 31, 2010 and 2009, our total debt and capitalization were as follows (in thousands):

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    2010     2009  
Bank debt
  $ 274,000     $ 324,000  
Senior subordinated notes
    1,686,536       1,383,833  
 
           
Total debt
    1,960,536       1,707,833  
Stockholders’ equity
    2,223,761       2,378,589  
 
           
Total capitalization
  $ 4,184,297     $ 4,086,422  
 
           
Debt to capitalization ratio
    46.9 %     41.8 %
     Long-term debt at December 31, 2010 totaled $2.0 billion, including $274.0 million of bank credit facility debt and $1.7 billion of senior subordinated notes. Our available committed borrowing capacity at December 31, 2010 was $970.6 million. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas and oil hedges currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A material drop in natural gas and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of natural gas and oil, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.
     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies. For additional information, see “Risk Factors-Difficult Conditions in the global capital markets, the credit markets and the economy generally may materially adversely affect our business and results of operations” in Item 1A of this report.
Credit Arrangements
     As of December 31, 2010, we maintained a $1.25 billion revolving credit facility, which we refer to as our bank credit facility. The bank credit facility was secured by substantially all of our assets with a maturity of October 25, 2012. Availability under the bank credit facility was subject to a borrowing base set by the lenders semi-annually with an option to set more often in certain circumstances. The borrowing base was dependent on a number of factors but primarily the lenders’ assessment of future cash flows. Redeterminations of the borrowing base required approval of 2/3rds of the lenders; increases required unanimous approval.
     On February 18, 2011, we entered into an amended and restated revolving credit facility, which replaced our previous bank credit facility. The new bank credit facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. The new bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. At February 25, 2011, the bank credit facility had a $2.0 billion borrowing base and a $1.5 billion facility amount. Borrowings under the new credit facility can either be, at our election: (i) at the Alternate Base Rate (as defined in the credit agreement) plus a spread ranging from 0.5% to 1.5% or (ii) LIBOR borrowings at the adjusted LIBO Rate (as defined in the credit agreement) plus a spread ranging from 1.5% to 2.5%. Remaining credit availability was $1.1 billion on February 25, 2011. Our new bank group is comprised of twenty-seven commercial banks, with no one bank holding more than 7.0% of the bank credit facility. The new credit facility matures on February 18, 2016. For additional information, see Note 7 to our consolidated financial statements.
     Our bank debt and our subordinated notes impose limitations on the payment of dividends and other restricted payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2010.

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Capital Requirements
     Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties, repayment of principal and interest on outstanding debt and payment of dividends. During 2010, $896.0 million of capital was expended on drilling projects. Also in 2010, $166.7 million was expended on acquisitions of unproved acreage, primarily in the Marcellus Shale and $134.5 million was expended to purchase proved and unproved properties in Virginia. Our 2010 capital program, excluding acquisitions, was funded by net cash flow from operations, proceeds from asset sales and borrowings under our credit facility. Our capital expenditure budget for 2011 is currently set at $1.38 billion, excluding acquisitions. Development and exploration activities are highly discretionary, and, for the near term, we expect such activities to be maintained at levels equal to internal cash flow and asset sales. To the extent capital requirements exceed internal cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.
     The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for natural gas and oil, actions of competitors, disruptions or interruptions of our production and unforeseen hazards such as weather conditions, acts of war or terrorists acts and the government or military response, and other operating and economic considerations.
Cash Flow
     Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and since our principal source of operating cash flows (or proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell substantially all of our production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying portion of our anticipated future natural gas and oil production for the next 12 to 24 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowings under the credit facility. As of December 31, 2010, we have entered into hedging agreements covering 161.0 Bcfe for 2011 and 58.5 Bcfe for 2012.
     Net cash provided from operating activities in 2010 was $513.3 million compared to $591.7 million in 2009 and $824.8 million in 2008. Cash provided from operating activities is largely dependent upon commodity prices and production, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2009 to 2010 reflects lower price realization (a decline of 19%) somewhat offset by a 14% increase in production. The decrease in cash provided from operating activities from 2008 to 2009 reflects lower price realizations (a decline of 25%) somewhat offset by a 13% increase in production. As of December 31, 2010, we have hedged approximately 81% of our projected 2011 production and 24% of our projected 2012 production. Net cash provided from operating activities is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for 2010 was a negative $726,000 compared to a negative $44.8 million for 2009 and positive $20.2 million in 2008.
     Net cash used in investing activities in 2010 was $798.9 million compared to $473.8 million in 2009 and $1.7 billion in 2008.
     During 2010, we:
    spent $817.0 million on natural gas and oil property additions;
 
    spent $296.5 million on acquisitions, including purchasing unproved and proved properties in Virginia for $134.5 million and Marcellus Shale leaseholds; and
 
    received proceeds of $327.8 million primarily from the sale of our Ohio tight gas sand properties.

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     During 2009, we:
    spent $541.2 million on natural gas and oil property additions;
 
    spent $139.3 million on acreage primarily in the Marcellus Shale;
 
    received proceeds of $234.1 million primarily from the sale of West Texas and New York natural gas and oil properties; and
 
    contributed $6.4 million of capital to Nora Gathering, LLC, an equity method investment.
     During 2008, we:
    spent $881.9 million on natural gas and oil property additions;
 
    spent $834.8 million on acquisitions, including the purchase of producing and unproved Barnett Shale properties and Marcellus Shale leasehold;
 
    contributed $29.0 million of capital to Nora Gathering, LLC, an equity method investment; and
 
    received proceeds of $68.2 million primarily from the sale of East Texas oil and gas properties.
     Net cash (used in) provided from financing activities in 2010 was an increase of $287.6 million compared to a decrease of $117.9 million in 2009 and an increase of $903.7 million in 2008. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.
     During 2010, we:
    borrowed $1.0 billion and repaid $1.1 billion under our bank credit facility, ending the year with $50.0 million lower bank debt;
 
    issued $500.0 million aggregate principal amounts of our 6.75% senior subordinated notes due 2020; and
 
    used some of the proceeds from the sale of 6.75% senior subordinated notes to redeem all $200.0 million aggregate principal amount of our 7.375% senior subordinated notes due 2013.
     During 2009, we:
    borrowed $707.0 million and repaid $1.1 billion under our bank credit facility, ending the year with $369 million lower bank debt; and
 
    issued $300.0 million aggregate principal amounts of our 8% senior subordinated notes due 2019, at a discount.
     During 2008, we:
    borrowed $1.5 billion and repaid $1.1 billion under our bank credit facility, ending the year with $390 million higher bank debt; and
 
    issued $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018; and
 
    received proceeds of $282.2 million from a common stock offering.
Cash Dividend Payments
     The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures and various other factors. In 2010, we paid $25.6 million in dividends to our common shareholders ($0.04 per share each quarter). In 2009, we paid $25.2 million in dividends to our common shareholders ($0.04 per share in each quarter). In 2008, we paid $24.6 million in dividends to our common shareholders ($0.04 per share in each quarter).
Cash Contractual Obligations
     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation commitments. As of December 31, 2010, we do not have any capital leases. As of December 31, 2010, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any material debt of any unrelated party. As of December 31, 2010, we had a total of $5.4 million of letters of credit outstanding under our bank credit facility. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2010. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2010 reflects accrued interest payable on our bank debt of $1.3 million which is payable in first quarter 2011. We expect to

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make interest payments of $9.6 million per year on our 6.375% senior subordinated notes, $18.8 million per year on our 7.5% senior subordinated notes due 2016, $18.8 million per year on our 7.5% senior subordinated notes due 2017, $18.1 million per year on our 7.25% senior subordinated notes, $24.0 million per year on our 8% senior subordinated notes and $33.8 million per year on our 6.75% senior subordinated notes.
     The following summarizes our contractual financial obligations at December 31, 2010 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under our bank credit facility, additional debt issuances and proceeds from asset sales (in thousands).
                                                 
    Payment due by period  
                            2014              
    2011     2012     2013     and 2015     Thereafter     Total  
Bank debt due 2012
  $     $ 274,000 (a)   $     $     $     $ 274,000  
6.375% senior subordinated notes due 2015
                      150,000             150,000  
7.5% senior subordinated notes due 2016
                            250,000       250,000  
7.5% senior subordinated notes due 2017
                            250,000       250,000  
7.25% senior subordinated notes due 2018
                            250,000       250,000  
8.0% senior subordinated notes due 2019
                            300,000       300,000  
6.75% senior subordinated notes due 2020
                            500,000       500,000  
Operating leases
    9,676       9,826       6,917       12,763       27,833       67,015  
Drilling rig commitments
    72,927       53,730       14,673       896             142,226  
Transportation commitments
    68,587       65,824       64,794       121,221       381,697       702,123  
Other purchase obligations
    50,975       42,975       2,727                   96,677  
Seismic agreements
    11,838       6,042       645                   18,525  
Derivative obligations (b)
    352       13,412                         13,764  
Asset retirement obligation liability (c)
    4,020       8,801       522       3,255       46,075       62,673  
 
                                   
Total contractual obligations (d)
  $ 218,375     $ 474,610     $ 90,278     $ 288,135     $ 2,005,605     $ 3,077,003  
 
                                   
 
(a)   Due at termination date of our bank credit facility. Interest paid on our bank credit facility would be approximately $7.4 million each year assuming no change in the interest rate or outstanding balance. On February 18, 2011 we entered into an amended and restated bank credit agreement which replaced our previous bank credit facility and will mature in 2016.
 
(b)   Derivative obligations represent net open derivative contracts valued as of December 31, 2010. While such payments will be funded by higher prices received from the sale of our production, production receipts may be received after our payments to counterparties, which can result in borrowings under our bank credit facility.
 
(c)   The ultimate settlement amount and timing cannot be precisely determined in advance. See Note 8 to our Consolidated financial statements.
 
(d)   This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.
     In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2030 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 683,000 Mmbtu per day over the 284,905 Mmbtu per day at December 31, 2010. These increases, which are contingent on certain pipeline modifications are for 350,000 Mmbtu per day in February 2011, 150,000 Mmbtu per day in September 2011, 108,000 Mmbtu per day in November 2012 and 75,000 Mmbtu per day for November 2013.
Delivery Commitments
     Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2010, remaining volumes to be delivered under this commitment are approximately 24.6 Bcf. Our proved reserves in the Barnett Shale are sufficient to fulfill these delivery commitments.
Other
     We have agreements in place to purchase seismic data. These agreements total $11.8 million in 2011, $6.0 million in 2012 and $645,000 in 2013. We also have a two-year agreement to lease equipment, material and labor for hydraulic fracturing services for $48.0 million in 2011 and $40.0 million in 2012. We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been significant and are not

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expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
Hedging — Oil and Gas Prices
     We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. In third quarter 2010, we also entered into call option derivative contracts. While there is a risk that the financial benefit of rising natural gas and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets.
     At December 31, 2010, we had collars covering 192.8 Bcf of gas at weighted average floor and cap prices of $5.54 to $6.43 and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 to $80.00. We also have sold call options covering 3.7 millions of barrels of oil at a weighted average price of $82.31. The fair value, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a pretax gain of $118.0 million at December 31, 2010. The contracts expire monthly through December 2012.
     At December 31, 2010, the following commodity derivative contracts were outstanding:
                         
Period   Contract Type     Volume Hedged       Average Hedge Price  
Natural Gas                        
2011   Collars   408,200 Mmbtu/day   $5.56– $6.48  
2012   Collars   119,641 Mmbtu/day   $5.50– $6.25  
 
                       
Crude Oil                        
2012   Collars   2,000 bbls/day   $70.00– $80.00  
2011   Call Options   5,500 bbls/day   $80.00  
2012   Call Options   4,700 bbls/day   $85.00  
     In addition to the collars above, we have entered into basis swap agreements. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $352,000 at December 31, 2010. These basis swaps expire in first quarter 2011.
Interest Rates
     At December 31, 2010, we had $2.0 billion of debt outstanding. Of this amount, $1.7 billion bears interest at fixed rates averaging 7.2%. Bank debt totaling $274.0 million bears interest at floating rates, which averaged 2.7% at year-end 2010. The 30-day LIBOR rate on December 31, 2010 was 0.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2010 would cost us approximately $2.7 million in additional annual interest expense.
Off-Balance Sheet Arrangements
     We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments some of which are described above under cash contractual obligations.
Inflation and Changes in Prices
     Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas and oil prices and the costs to produce our reserves. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend

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that began in 2004 and accelerated through the middle of 2008, commodity prices for natural gas and oil increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure on our operating costs and also on our capital costs. Due to the decline in commodity prices that began in the last half of 2008 and continued into 2010, costs have moderated. We expect costs in 2011 to continue to be a function of supply and demand.
The following table indicates the average natural gas and oil prices received over the last five years and quarterly for 2010, 2009 and 2008. Average price calculations exclude all derivative settlements whether or not they qualify for hedge accounting. Oil is converted to natural gas equivalent at the rate of one barrel equals six mcf.
                                         
    Average Sales Prices (Wellhead)   Average NYMEX Prices (a)
    Natural   Crude   Equivalent   Natural   Crude
    Gas   Oil   Mcf   Gas   Oil
    (Per mcf)   (Per bbl)   (Per mcfe) (b)   (Per mcf)   (Per bbl)
Annual
                                       
 
                                       
2010
  $ 3.75     $ 69.29     $ 4.67     $ 4.40     $ 79.59  
2009
    3.32       54.98       4.00       4.02       60.49  
2008
    8.07       96.77       9.14       8.91       100.47  
2007
    6.54       67.47       7.37       6.92       72.34  
2006
    6.59       62.36       7.25       7.26       66.22  
 
                                       
Quarterly
                                       
 
                                       
2010
                                       
First
  $ 4.85     $ 69.72     $ 5.63     $ 5.37     $ 78.81  
Second
    3.54       67.90       4.39       4.08       77.72  
Third
    3.62       66.84       4.41       4.42       76.18  
Fourth
    3.10       72.41       4.36       3.82       85.24  
 
                                       
2009
                                       
First
  $ 3.82     $ 38.89     $ 4.06     $ 4.86     $ 43.20  
Second
    2.72       54.62       3.53       3.59       59.77  
Third
    2.87       63.38       3.67       3.41       68.18  
Fourth
    3.84       67.96       4.71       4.26       76.12  
 
                                       
2008
                                       
First
  $ 7.85     $ 94.65     $ 8.96     $ 8.07     $ 97.90  
Second
    10.09       120.27       11.48       10.80       123.98  
Third
    9.72       113.91       10.90       10.08       117.83  
Fourth
    4.86       55.09       5.43       6.82       58.79  
 
(a)   Based on average of bid week prompt month prices.
 
(b)   Oil is converted at a rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of all oil and natural gas prices.
Management’s Discussion of Critical Accounting Estimates
     Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the

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results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.
     Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.
Natural Gas and Oil Properties
     We follow the successful efforts method of accounting for natural gas and oil producing activities. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and reviewed by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.
     Proved reserves are defined by the SEC as those volumes of natural gas, natural gas liquids, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements which we adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering who reports directly to our President. For additional discussion, see “Proved Reserves,” in Item 2 of this report. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to review our estimates of proved reserves. Independent petroleum consultants reviewed approximately 90% of our reserves in 2010 compared to 88% in 2009 and 87% in 2008. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report are those reserves estimated by our employees. Beginning December 31, 2009, reserve estimates are based on an average of prices in the prior 12-month period, using the closing prices on the first day of each month. In previous periods, reserve estimates were based upon prices at December 31. Neither of these prices should be expected to reflect future market conditions.
     Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2010, we estimate that a 1% change in proved reserves would increase or decrease 2011 depletion expense by approximately $12.0 million (assuming a 10% production increase). Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 19 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009 which was accounted for prospectively. We estimated the effect of this change in estimate was an increase to depletion, depreciation and amortization expense in fourth quarter 2009 of approximately $3.4 million primarily due to lower prices reflected in our estimated reserves.
     We monitor our long-lived assets recorded in natural gas and oil properties in our consolidated balance sheets to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying

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value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for natural gas and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. All of these factors must be considered when testing a property’s carrying value for impairment. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of future cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future. Our historical impairment of producing properties has been $469.7 million in 2010, $930,000 in 2009, $74.9 million in 2006, $3.6 million in 2004, $31.1 million in 2001, $29.9 million in 1999 and $214.7 million in 1998. In 2010, an impairment was recorded on our onshore Barnett and Gulf Coast properties and in 2009, an impairment was recorded on our Michigan properties due to lower reserves and natural gas prices. While our Barnett properties did not meet held for sale criteria as of December 31, 2010, our analysis reflected undiscounted cash flows for these properties were less than their carrying value. We therefore compared the carrying value of the Barnett properties to the estimated fair value of such properties and recognized an impairment charge of $463.2 million in fourth quarter 2010. Our estimated fair value includes an estimate of the potential sales price for these properties in the estimated future cash flows. On February 28, 2011, we announced that we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to typical post-closing adjustments. The completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance that the sale will be completed. Based on the current agreement, we expect these assets will be presented as assets held for sale in first quarter 2011. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
     We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations. See Note 3 to our consolidated financial statements for information on these acquisitions.
     We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $811.8 million at December 31, 2010 compared to $774.5 million at December 31, 2009 and $758.0 million at December 31, 2008. We have recorded abandonment and impairment expense related to unproved properties of $70.0 million in 2010 compared to $113.5 million in 2009 and $47.4 million in 2008.
Natural gas and Oil Derivatives
     All derivative instruments are recorded on our consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. Our derivatives are measured using a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. While we remain at risk for possible changes in the market value of commodity derivatives, such risk should be mitigated by price changes in the underlying physical commodity. The determination of fair values includes various factors including the impact of our nonperformance risk on our liabilities and the credit standing of our counterparties. As of December 31, 2010, our counterparties include nine financial institutions, all of which are secured lenders in our bank credit facility.

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     Through December 31, 2010, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is not probable to occur, any unrealized gains or losses are recognized immediately in derivative fair value income in our statements of operations. During 2010, there were gains of $11.6 million compared to gains of $5.4 million in 2009 and losses of $583,000 in 2008 reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives.
     We apply hedge accounting to qualifying derivatives used to manage price risk associated with our natural gas, NGL and oil production. Accordingly, we record changes in the fair value of our derivative contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the accompanying consolidated balance sheets. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into natural gas, NGL and oil sales when the underlying physical transaction occurs. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income the accompanying consolidated statements of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).
     Realized and unrealized gains and losses on derivatives that are not designated as hedges are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in derivative fair value income in the accompanying consolidated statements of operations. We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. Cash flows from our derivative contract settlements are reflected in cash flow provided from operating activities in the accompanying consolidated statements of cash flows.
Asset Retirement Obligations
     We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
     Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. During 2010, we decreased our existing estimated ARO by $8.1 million or approximately 10% of the asset retirement obligation at December 31, 2009. This decrease was due to a change in the productive lives of our wells. During 2009, we increased our existing estimated asset retirement obligation by $4.5 million or approximately 5% of the asset retirement obligation at December 31, 2008. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depletion, depreciation and amortization in the accompanying consolidated statements of operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Deferred Taxes
     We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit, which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible

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differences. We routinely evaluate deferred tax assets to determine the likelihood of realization and we must estimate our expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions and future financial conditions. The estimates are assumptions used in determining future taxable income are consistent with those used in our internal budgets and forecasts. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.
     In determining deferred tax liabilities, accounting rules require AOCI to be considered, even though such income or loss has not yet been earned. At year-end 2010, deferred tax liabilities exceeded deferred tax assets by $683.9 million, with $43.6 million of deferred tax liabilities related to unrealized hedging gains included in accumulated other comprehensive income. At year-end 2009, deferred tax liabilities exceeded deferred tax assets by $768.9 million, with $3.8 million of deferred tax liabilities related to unrealized hedging gains included in AOCI.
     We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.
Contingent Liabilities
     A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. Actual costs can differ from estimates for many reasons. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.
Revenue Recognition
     Natural gas, natural gas liquids and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of gas produced. We recognize the cost of revenues, such as transportation and compression expense, as a reduction of revenue.
Stock-based Compensation Arrangements
     The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We utilize historical data and analyze current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.
     We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period with the resulting gain or loss recognized in deferred compensation plan expense in our consolidated statement of operations.
Accounting Standards Not Yet Adopted
     In December 2010, the FASB issued ASU No. 2010-29, which updates the guidance in ASC Topic 805, Business Combinations. The objectives of ASU 2010-29 is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amendments in ASU 2010-29 specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments affect any public entity as defined by ASC 805 that enters into business combinations that are material on an individual or aggregate basis. This guidance will

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become effective for us for acquisitions occurring on or after the beginning of our 2012 fiscal year. We do not expect the adoption of this guidance will have a material impact upon our financial position or results of operations.
ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.
Market Risk
     We are exposed to market risks related to the volatility of natural gas, NGL and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. We are also exposed to market risks related to changes in interest rates.
Commodity Price Risk
     We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establishes a minimum floor price and a predetermined ceiling price. We have also entered into call option derivative contracts under which we sold call options in exchange for a premium from the counterparty. At the time of settlement of these monthly call options, if the market price exceeds the fixed price of the call option, we will pay the counterparty such excess and if the market settle below the fixed price of the call option, no payment is due from either party. At December 31, 2010, our derivatives program includes collars and call options. As of December 31, 2010, we had collars covering 192.8 Bcf of gas and 0.7 million barrels of oil. We also have sold call options covering 3.7 million barrels of oil. These contracts expire monthly through December 2012. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of December 31, 2010, approximated a net unrealized pre-tax gain of $118.0 million compared to a gain of $28.7 million at December 31, 2009. This change is primarily related to the expiration of natural gas and oil derivative contracts during 2010 and to the natural gas and oil futures prices as of December 31, 2010, in relation to the new commodity derivative contracts we entered into during 2010 for 2011 and 2012.
     At December 31, 2010, the following commodity derivative contracts were outstanding:
                     
            Average   Fair  
Period   Contract Type   Volume Hedged   Hedge Price   Market Value  
                (in thousands)  
Natural Gas
                   
2011
  Collars   408,200 Mmbtu/day   $5.56– $6.48   $ 163,355  
2012
  Collars   119,641 Mmbtu/day   $5.50– $6.25   $ 27,032  
 
                   
Crude Oil
                   
2012
  Collars   2,000 bbls/day   $70.00– $80.00   $ (12,052 )
2011
  Call options   5,500 bbls/day   $80.00   $ (31,904 )
2012
  Call options   4,700 bbls/day   $85.00   $ (28,393 )
     We expect our NGL production to continue to increase. We currently have not entered into any NGL derivative contracts. In our Marcellus Shale operations, propane is a large product component of our NGL production and we believe NGL prices are somewhat seasonal. Therefore, the percentage of NGL prices to NTMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand.
Other Commodity Risk
     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are

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frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the collars and call options above, we have entered into basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net realized pre-tax loss of $352,000 at December 31, 2010. These basis swaps expire in first quarter 2011.
     The following table shows the fair value of our collars and call options and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at December 31, 2010. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):
                                         
            Hypothetical Change   Hypothetical Change
            in Fair Value   in Fair Value
            Increase of   Decrease of
    Fair Value   10%   25%   10%   25%
Collars
  $ 178,335     $ (82,083 )   $ (199,536 )   $ 85,644     $ 219,992  
Call options
    (60,297 )     (27,711 )     (73,471 )     23,800       47,432  
     Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At December 31, 2010, our derivative counterparties include nine financial institutions, all of which are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by counterparty, which was immaterial.
Interest Rate Risk
     We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior subordinated debt and variable rate bank debt. At December 31, 2010, we had $2.0 billion of debt outstanding. Of this amount, $1.7 billion bears interest at a fixed rate averaging 7.2%. Bank debt totaling $274.0 million bears interest at floating rates, which was 2.7% on that date. On December 31, 2010, the 30-day LIBOR rate was 0.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2010 would cost us approximately $2.7 million in additional annual interest expense.

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     The fair value of our subordinated debt is based on year-end quoted market prices. The following table presents information on these fair values (in thousands):
                 
    Carrying     Fair  
    Value     Value  
Fixed rate debt:
               
Senior Subordinated Notes due 2015
       
(The interest rate is fixed at a rate of 6.375%)
  $ 150,000     $ 153,000  
 
               
Senior Subordinated Notes due 2016
           
(The interest rate is fixed at a rate of 7.5%)
    249,683       259,375  
 
               
Senior Subordinated Notes due 2017
           
(The interest rate is fixed at a rate of 7.5%)
    250,000       263,438  
 
               
Senior Subordinated Notes due 2018
           
(The interest rate is fixed at a rate of 7.25%)
    250,000       263,750  
 
               
Senior Subordinated Notes due 2019
           
(The interest rate is fixed at a rate of 8.0%)
    286,853       326,625  
 
               
Senior Subordinated Notes due 2020
           
(The interest rate is fixed at a rate of 6.75%)
    500,000       515,625  
 
           
 
  $ 1,686,536     $ 1,781,813  
 
           
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
     For financial statements required by Item 8, see Item 15 in Part IV of this report.
ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.
ITEM 9A. CONTROLS AND PROCEDURES
     Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2010.
     Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, we have included a report of management’s assessment of the design and effectiveness of its internal controls as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Ernst & Young LLP, our registered public accountants, also attested to, and reported on, the effectiveness of internal control over financial reporting. Management’s report and the independent public accounting firm’s attestation report are included in our 2010 Financial Statements in Item 15 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting,” and are incorporated herein by reference.

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     Changes in Internal Control over Financial Reporting. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during fourth quarter 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
     None.

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PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
     The officers and directors are listed below with a description of their experience and certain other information. Each director was elected for a one-year term at the 2010 annual stockholders’ meeting. Officers are appointed by our board of directors.
                     
            Office    
            Held    
    Age   Since   Position
Charles L. Blackburn
    83       2003     Director
Anthony V. Dub
    61       1995     Director
V. Richard Eales
    74       2001     Lead Independent Director
Allen Finkelson
    64       1994     Director
James M. Funk
    61       2008     Director
Jonathan S. Linker
    62       2002     Director
Kevin S. McCarthy
    51       2005     Director
John H. Pinkerton
    56       1990     Director, Chairman of the Board and Chief Executive Officer
Jeffrey L. Ventura
    53       2003     Director, President & Chief Operating Officer
Roger S. Manny
    53       2003     Executive Vice President & Chief Financial Officer
Alan W. Farquharson
    53       2007     Senior Vice President – Reservoir Engineering
David P. Poole
    48       2008     Senior Vice President – General Counsel & Corporate Secretary
Chad L. Stephens
    55       1990     Senior Vice President – Corporate Development
Ray N. Walker
    53       2010     Senior Vice President – Marcellus Shale
Rodney L. Waller
    61       1999     Senior Vice President
Mark D. Whitley
    59       2005     Senior Vice President – Southwest & Engineering Technology
Dori A. Ginn
    53       2009     Vice President, Controller and Principal Accounting Officer
     Charles L. Blackburn was first elected as a director in 2003. Mr. Blackburn has more than 40 years experience in oil and gas exploration and production serving in several executive and board positions. Previously, he served as Chairman and Chief Executive Officer of Maxus Energy Corporation from 1987 until that company’s sale to YPF Socieded Anonima in 1995. Maxus was the oil and gas producer which remained after Diamond Shamrock Corporation’s spin-off of its refining and marketing operations. Mr. Blackburn joined Diamond Shamrock in 1986 as President of their exploration and production subsidiary. From 1952 through 1986, Mr. Blackburn was with Shell Oil Company, serving as Director and Executive Vice President for exploration and production for the final ten years of that period. Mr. Blackburn has previously served on the Boards of Anderson Clayton and Co. (1978-1986), King Ranch Corp. (1987-1988), Penrod Drilling Co. (1988-1991), Landmark Graphics Corp. (1992-1996) and Lone Star Technologies, Inc. (1991-2001). Mr. Blackburn received his Bachelor of Science degree in Engineering Physics from the University of Oklahoma.
     Anthony V. Dub became a director in 1995. Mr. Dub is Chairman of Indigo Capital, LLC, a financial advisory firm based in New York. Before forming Indigo Capital in 1997, he served as an officer of Credit Suisse First Boston (“CSFB”). Mr. Dub joined CSFB in 1971 and was named a Managing Director in 1981. Mr. Dub led a number of departments during his 26 year career at CSFB including the Investment Banking Department. After leaving CSFB, Mr. Dub became Vice Chairman and a director of Capital IQ, Inc. until its sale to Standard & Poor’s in 2004. Capital IQ is a leader in helping organizations capitalize on synergistic integration of market intelligence, institutional knowledge and relationships. Mr. Dub received a Bachelor of Arts, magna cum laude, from Princeton University.
     V. Richard Eales became a director in 2001 and was selected as Lead Independent Director in 2008. Mr. Eales has over 35 years of experience in the energy, technology and financial industries. He is currently retired, having been a financial consultant serving energy and information technology businesses from 1999 through 2002. Mr. Eales was employed by Union Pacific Resources Group Inc. from 1991 to 1999 serving as Executive Vice President from 1995 through 1999. Before 1991, Mr. Eales served in various financial capacities with Butcher & Singer and Janney Montgomery Scott, investment banking

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firms, as CFO of Novell, Inc., a technology company, and in the treasury department of Mobil Oil Corporation. Mr. Eales received his Bachelor of Chemical Engineering degree from Cornell University and his Master’s degree in Business Administration from Stanford University.
     Allen Finkelson became a director in 1994. Mr. Finkelson has been a partner at Cravath, Swaine & Moore LLP since 1977, with the exception of the period 1983 through 1985, when he was a managing director of Lehman Brothers Kuhn Loeb Incorporated. Mr. Finkelson joined Cravath, Swaine & Moore, LLP in 1971. Mr. Finkelson earned a Bachelor of Arts from St. Lawrence University and a J.D. from Columbia University School of Law.
     James M. Funk became a director in December 2008. Mr. Funk is an independent consultant and producer with over 30 years of experience in the energy industry. Mr. Funk served as Sr. Vice President of Equitable Resources and President of Equitable Production Co. from June 2000 until January 2003. Previously, Mr. Funk was employed by Shell Oil Company for 23 years in senior management and technical positions. Mr. Funk has previously served on the boards of Westport Resources (2000 to 2004) and Matador Resources Company (2003 to 2008). Mr. Funk currently serves as a Director of Superior Energy Services, Inc., a public oil field services company headquartered in New Orleans, Louisiana and as a Director of Sonde Resources Corporation, a public international exploration and production company headquartered in Calgary, Canada. Mr. Funk received an A.B. degree in Geology from Wittenberg University, a M.S. in Geology from the University of Connecticut, and a PhD in Geology from the University of Kansas. Mr. Funk is a Certified Petroleum Geologist.
     Jonathan S. Linker became a director in 2002. Mr. Linker previously served as a director of Range from 1998 to 2000. He has been active in the energy industry for over 37 years. Mr. Linker joined First Reserve Corporation in 1988 and was a Managing Director of the firm from 1996 through 2001. Mr. Linker is currently Manager of Houston Energy Advisors LLC, an investment advisor providing management and investment services to two private equity funds. Mr. Linker has been President and a director of IDC Energy Corporation since 1987, a director and officer of Sunset Production Corporation since 1991 serving currently as Chairman, and Manager of Shelby Resources Inc., all small, privately-owned exploration and production companies. Mr. Linker received a Bachelor of Arts in Geology from Amherst College, a Masters in Geology from Harvard University and an MBA from Harvard Graduate School of Business Administration.
     Kevin S. McCarthy became a director in 2005. Mr. McCarthy is Chairman, Chief Executive Officer and President of Kayne Anderson MLP Investment Company, Kayne Anderson Energy Total Return Fund, Inc. and Kayne Anderson Energy Development Company, which are each NYSE listed closed-end investment companies. Mr. McCarthy joined Kayne Anderson Capital Advisors as a Senior Managing Director in 2004 from UBS Securities LLC where he was global head of energy investment banking. In this role, he had senior responsibility for all of UBS’ energy investment banking activities, including direct responsibilities for securities underwriting and mergers and acquisitions in the energy industry. From 1995 to 2000, Mr. McCarthy led the energy investment banking activities of Dean Witter Reynolds and then PaineWebber Incorporated. He began his investment banking career in 1984. He is also on the board of directors of K-Sea Transportation Partners LP (a publicly traded marine transportation company), as well as International Resource Partners, L.P., Pro Petro Services, Inc. and Direct Fuel Partners, L.P (three private energy companies). He earned a Bachelor of Arts in Economics and Geology from Amherst College and an MBA in Finance from the University of Pennsylvania’s Wharton School.
     John H. Pinkerton, Chairman & Chief Executive Officer and a director, became a director in 1988 and was elected Chairman of the Board of Directors in 2008. He joined Range as President in 1990 and was appointed Chief Executive Officer in 1992. Previously, Mr. Pinkerton was Senior Vice President of Snyder Oil Corporation (“Snyder”). Before joining Snyder in 1980, Mr. Pinkerton was with Arthur Andersen. Mr. Pinkerton currently serves on the Board of Trustees of Texas Christian University and is a member of the Executive Committee of America’s Natural Gas Alliance (ANGA). Mr. Pinkerton received his Bachelor of Arts in Business Administration from Texas Christian University and a Master’s degree from the University of Texas at Arlington.
     Jeffrey L. Ventura, President & Chief Operating Officer and a director, joined Range in 2003 and became a director in 2005. Previously, Mr. Ventura served as President and Chief Operating Officer of Matador Petroleum Corporation which he joined in 1997. Before 1997, Mr. Ventura spent eight years at Maxus Energy Corporation where he managed various engineering, exploration and development operations and was responsible for coordination of engineering technology. Previously, Mr. Ventura was with Tenneco Inc., where he held various engineering and operating positions. Mr. Ventura holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University.
     Roger S. Manny, Executive Vice President & Chief Financial Officer. Mr. Manny joined Range in 2003. Previously, Mr. Manny served as Executive Vice President and Chief Financial Officer of Matador Petroleum Corporation from 1998 until joining Range. Before 1998, Mr. Manny spent 18 years at Bank of America and its predecessors where he served as Senior Vice President in the energy group. Mr. Manny holds a Bachelor of Business Administration degree from the University of Houston and a Masters of Business Administration from Houston Baptist University.

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     Alan W. Farquharson, Senior Vice President – Reservoir Engineering, joined Range in 1998. Mr. Farquharson has held the positions of Manager and Vice President of Reservoir Engineering before being promoted to his senior position in February 2007. Previously, Mr. Farquharson held positions with Union Pacific Resources including Engineering Manager Business Development – International. Before that, Mr. Farquharson held various technical and managerial positions at Amoco and Hunt Oil. He holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University.
     David P. Poole, Senior Vice President – General Counsel & Corporate Secretary, joined Range in June 2008. Mr. Poole has over 21 years of legal experience. From May 2004 until March 2008 he was with TXU Corp., serving last as Executive Vice President – Legal, and General Counsel. Prior to joining TXU, Mr. Poole spent 16 years with Hunton & Williams LLP and its predecessor, where he was a partner and last served as the Managing Partner of the Dallas office. Mr. Poole graduated from Texas Tech University with a B.S. in Petroleum Engineering and received a J.D. magna cum laude from Texas Tech University School of Law.
     Chad L. Stephens, Senior Vice President – Corporate Development, joined Range in 1990. Before 2002, Mr. Stephens held the position of Senior Vice President – Southwest. Previously, Mr. Stephens was with Duer Wagner & Co., an independent oil and gas producer for approximately two years. Before that, Mr. Stephens was an independent oil operator in Midland, Texas for four years. From 1979 to 1984, Mr. Stephens was with Cities Service Company and HNG Oil Company. Mr. Stephens holds a Bachelor of Arts degree in Finance and Land Management from the University of Texas.
     Ray N. Walker, Jr., Senior Vice President – Marcellus Shale, joined Range in 2006 and was elected to his current position in February 2010. Previously, Mr. Walker served as Vice President – Marcellus Shale where he led the development of the Company’s Marcellus Shale division. Mr. Walker is a Registered Petroleum Engineer with more than 34 years of oil and gas operations and management experience having previously been employed by Halliburton in various technical and management roles, Union Pacific Resources and several private companies in which Mr. Walker served as an officer. Mr. Walker has a Bachelor of Science degree, in Agricultural Engineering from Texas A&M University.
     Rodney L. Waller, Senior Vice President joined Range in 1999. Mr. Waller served as Corporate Secretary from 1999 until 2008. Previously, Mr. Waller was Senior Vice President of Snyder Oil Corporation. Before joining Snyder, Mr. Waller was with Arthur Andersen. Mr. Waller is a certified public accountant and petroleum land man. Mr. Waller received a Bachelor of Arts degree in Accounting from Harding University.
     Mark D. Whitley, Senior Vice President – Southwest & Engineering Technology, joined Range in 2005. Previously, he served as Vice President – Operations with Quicksilver Resources for two years. Before joining Quicksilver, he served as Production/Operation Manager for Devon Energy, following the merger of Mitchell Energy with Devon. From 1982 to 2002, Mr. Whitley held a variety of technical and managerial roles with Mitchell Energy. Notably, he led the team of engineers at Mitchell Energy who applied new stimulation techniques to unlock the shale gas potential in the Barnett Shale formation in the Fort Worth Basin. Previous positions included serving as a production and reservoir engineer with Shell Oil. He holds a Bachelor’s degree in Chemical Engineering from Worcester Polytechnic Institute and a Master’s degree in Chemical Engineering from the University of Kentucky.
     Dori A. Ginn, Vice President, Controller and Principal Accounting Officer, joined Range in 2001. Ms. Ginn has held the positions of Financial Reporting Manager, Vice President and Controller before being elected to Principal Accounting Officer in September 2009. Prior to joining Range, she held various accounting positions with Doskocil Manufacturing Company and Texas Oil and Gas Corporation. Ms. Ginn received a Bachelor of Business Administration in Accounting degree from the University of Texas at Arlington. She is a certified public accountant.

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Section 16(a) Beneficial Ownership Reporting Compliance
     See the material appearing under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Range Proxy Statement for the 2010 Annual Meeting of stockholders which is incorporated herein by reference. Section 16(a) of the Exchange Act requires our directors, officers (including a person performing a principal policy-making function) and persons who own more than 10% of a registered class of our equity securities to file with the Commission initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Directors, officers and 10% holders are required by Commission regulations to send us copies of all of the Section 16(a) reports they file. Based solely on a review of the copies of the forms sent to us and the representations made by the reporting persons to us, we believe that, other than as described below, during the fiscal year ended December 31, 2010, our directors, officers and 10% holders complied with all filing requirements under Section 16(a) of the Exchange Act, with the following exceptions. Mr. Charles Blackburn had a delinquent Form-4 filing on June 1, 2010 for a transaction occurring on May 19, 2010. Ms. Dori Ginn had a delinquent Form-4 filing on March 3, 2010 for a transaction occurring on February 8, 2010.
Code of Ethics
     Code of Ethics. We have adopted a Code of Ethics that applies to our principal executive officers, principal financial officer, principal accounting officer, or persons performing similar functions (as well as directors and all other employees). A copy is available on our website, www.rangeresources.com and a copy in print will be provided to any person without charge, upon request. Such requests should be directed to the Corporate Secretary, 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 or by calling (817) 870-2601. We intend to disclose any amendments to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on our website, under the Corporate Governance caption, promptly following the date of such amendment or waiver.
Identifying and Evaluating Nominees for Directors
     See the material under the heading “Consideration of Director Nominees” in the Range Proxy Statement for the 2011 Annual Meeting of stockholders, which is incorporated herein by reference.
Audit Committee
     See the material under the heading “Audit Committee” in the Range Proxy Statement for the 2011 Annual Meeting of stockholders, which is incorporated herein by reference.
NYSE 303A Certification
     The Chief Executive Officer of Range Resources Corporation made an unqualified certification to the NYSE with respect to the Company’s compliance with the NYSE Corporate Governance listing standards on June 3, 2010.
ITEM 11. EXECUTIVE COMPENSATION
     Information required by this item is incorporated by reference to such information as set forth in the Range Proxy Statement for the 2011 Annual Meeting of stockholders.
ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
     Information required by this item is incorporated by reference to such information as set forth in the Range Proxy Statement for the 2011 Annual Meeting of stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
     Information required by this item is incorporated by reference to such information as set forth in the Range Proxy Statement for the 2011 Annual Meeting of stockholders.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
     Information required by this item is incorporated by reference to such information as set forth in the Range Proxy Statement for the 2011 Annual Meeting of stockholders.

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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)   Documents filed as part of the report:
  1.   Financial Statements:
         
    Page
    Number
Index to Financial Statements
    F- 1  
 
       
Management’s Report on Internal Control Over Financial Reporting
    F- 2  
 
       
Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting
    F- 3  
 
       
Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements
    F- 4  
 
       
Consolidated Balance Sheets as of December 31, 2010 and 2009
    F- 5  
 
       
Consolidated Statements of Operations for the Year Ended December 31, 2010, 2009 and 2008
    F- 6  
 
       
Consolidated Statements of Cash Flows for the Year Ended December 31, 2010, 2009 and 2008
    F- 7  
 
       
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2010, 2009 and 2008
    F- 8  
 
       
Consolidated Statements of Comprehensive (Loss) Income for the Year Ended December 31, 2010, 2009 and 2008
    F- 9  
 
       
Notes to Consolidated Financial Statements
    F- 10  
 
       
Selected Quarterly Financial Data (Unaudited)
    F- 37  
 
       
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)
    F- 39  
  2.   All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.
  3.   Exhibits:
     (a) See Index of Exhibits on page 66 for a description of the exhibits filed as a part of this report.

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GLOSSARY OF CERTAIN DEFINED TERMS
     The terms defined in this glossary are used in this report.
basis risk. The risk associated with the sales point for natural gas and oil production varying from reference (or settlement) price for a particular hedging transaction.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volumes, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGL, which reflects relative energy content.
development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole. A well found to be incapable of producing oil or natural gas in sufficient economic quantities.
exploratory well. A well drilled to find oil or gas in an unproved area, to find a new reservoir in an existing field or to extend a known reservoir.
gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcf per day. One thousand cubic feet of gas per day.
Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 mcf for each barrel of oil or NGL, which reflects relative energy content.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million British thermal units. A British thermal unit is the heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
Mmcf. One million cubic feet of gas.
Mmcfe. One million cubic feet of gas equivalents.
NGLs. Natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
NYMEX. The New York Mercantile Exchange.
present value (PV). The present value of future net cash flows, using a 10% discount rate, from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions). The after tax present value is the Standardized Measure.
productive well. A well that is producing oil or gas or that is capable of production.
proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

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proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
proved undeveloped reserves. 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.
recompletion. The completion for production an existing well bore in another formation from that in which the well has been previously completed.
reserve life. Proved reserves at a point in time divided by the then production rate (annual or quarterly).
royalty acreage. Acreage represented by a fee mineral or royalty interest which entitles the owner to receive free and clear of all production costs a specified portion of the oil and gas produced or a specified portion of the value of such production.
royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production.
Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission’s rules for inclusion of oil and gas reserve information in financial statements filed with the Commission.
Tcfe. One trillion cubic feet equivalent, determined using the ratio of six mcf of natural gas to one barrel of crude oil.
unconventional “resources” plays. Plays targeting coal bed or gas shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economically.
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.
working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens, and to all costs of exploration, development and operations, and all risks in connection therewith.
workover. Maintenance on a producing well to restore or increase production.

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SIGNATURES
     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  RANGE RESOURCES CORPORATION
 
 
  By:   /s/ JOHN H. PINKERTON    
    John H. Pinkerton   
    Chairman of the Board and
Chief Executive Officer
 
 
 
Dated: March 1, 2011
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated.
         
Signature   Capacity   Date
 
       
/s/ JOHN H. PINKERTON
 
John H. Pinkerton
  Chairman of the Board and Chief Executive Officer    March 1, 2011
 
       
/s/ JEFFREY L. VENTURA
 
Jeffrey L. Ventura
  Director, President and Chief Operating Officer    March 1, 2011
 
       
/s/ ROGER S. MANNY
 
Roger S. Manny
  Executive Vice President and Chief Financial Officer    March 1, 2011
 
       
/s/ DORI A. GINN
 
Dori A. Ginn
  Vice President, Controller and Principal Accounting Officer    March 1, 2011
 
       
/s/ CHARLES L. BLACKBURN
 
Charles L. Blackburn
  Director    March 1, 2011
 
       
/s/ ANTHONY V. DUB
 
Anthony V. Dub
  Director    March 1, 2011
 
       
/s/ V. RICHARD EALES
 
V. Richard Eales
  Lead Independent Director    March 1, 2011
 
       
/s/ ALLEN FINKELSON
 
Allen Finkelson
  Director    March 1, 2011
 
/s/ JAMES M. FUNK
 
James M. Funk
  Director    March 1, 2011
 
       
/s/ JONATHAN S. LINKER
 
Jonathan S. Linker
  Director    March 1, 2011
 
       
/s/ KEVIN S. MCCARTHY
 
Kevin S. McCarthy
  Director    March 1, 2011

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RANGE RESOURCES CORPORATION
INDEX TO FINANCIAL STATEMENTS
         
    Page
    Number
    F- 2  
 
       
    F- 3  
 
       
    F- 4  
 
       
    F- 5  
 
       
    F- 6  
 
       
    F- 7  
 
       
    F- 8  
 
       
    F- 9  
 
       
    F-10  
 
       
    F-37  
 
       
    F-39  

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Stockholders of
Range Resources Corporation:
     Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and the board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of December 31, 2010, our internal control over financial reporting is effective based on those criteria.
     Ernst and Young, LLP, the independent registered public accounting firm that audited our financial statements included in this annual report, has issued an attestation report on our internal control over financial reporting as of December 31, 2010. This report appears on the following page.
             
By:
  /s/ JOHN H. PINKERTON   By:   /s/ ROGER S. MANNY
 
           
 
  John H. Pinkerton       Roger S. Manny
 
  Chairman of the Board and Chief Executive Officer       Executive Vice President and Chief Financial Officer
Fort Worth, Texas
March 1, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders of
Range Resources Corporation:
     We have audited Range Resources Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Range Resources Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
     In our opinion, Range Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Range Resources Corporation as of December 31, 2010 and 2009 and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010 and our report dated March 1, 2011 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
March 1, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Range Resources Corporation:
     We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Range Resources Corporation at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
      As discussed in Note 19 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of the 2009 adoption of new oil and gas reserve estimation and disclosure requirements.
     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
March 1, 2011

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RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
                 
    December 31,  
    2010     2009  
Assets
             
Current assets:
               
Cash and cash equivalents
  $ 2,848     $ 767  
Accounts receivable, less allowance for doubtful accounts of $5,001 and $2,176
    105,983       123,622  
Deferred tax asset
          8,054  
Unrealized derivative gain
    131,450       21,545  
Inventory and other
    21,433       21,292  
 
           
Total current assets
    261,714       175,280  
 
           
 
               
Unrealized derivative gain
          4,107  
Equity method investments
    155,105       146,809  
Natural gas and oil properties, successful efforts method
    6,561,454       6,308,707  
Accumulated depletion and depreciation
    (1,639,397 )     (1,409,888 )
 
           
 
    4,922,057       4,898,819  
 
           
Transportation and field assets
    136,088       161,034  
Accumulated depreciation and amortization
    (61,355 )     (69,199 )
 
           
 
    74,733       91,835  
 
           
Other assets
    84,977       79,031  
 
           
Total assets
  $ 5,498,586     $ 5,395,881  
 
           
 
               
Liabilities
               
Current liabilities:
               
Accounts payable
  $ 312,475     $ 214,548  
Asset retirement obligations
    4,020       2,446  
Accrued liabilities
    69,678       58,585  
Deferred tax liability
    11,848        
Accrued interest
    32,189       24,037  
Unrealized derivative loss
    352       14,488  
 
           
Total current liabilities
    430,562       314,104  
 
           
Bank debt
    274,000       324,000  
Subordinated notes
    1,686,536       1,383,833  
Deferred tax liability
    672,041       776,965  
Unrealized derivative loss
    13,412       271  
Deferred compensation liability
    134,488       135,541  
Asset retirement obligations and other liabilities
    63,786       82,578  
 
           
Total liabilities
    3,274,825       3,017,292  
 
           
Commitments and contingencies
               
 
               
Stockholders’ Equity
               
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding
           
Common stock, $0.01 par, 475,000,000 shares authorized, 160,113,608 issued at December 31, 2010 and 158,336,264 issued at December 31, 2009
    1,601       1,583  
Common stock held in treasury, 204,556 shares at December 31, 2010 and 217,327 shares at December 31, 2009
    (7,512 )     (7,964 )
Additional paid-in capital
    1,820,503       1,772,020  
Retained earnings
    341,699       606,529  
Accumulated other comprehensive income
    67,470       6,421  
 
           
Total stockholders’ equity
    2,223,761       2,378,589  
 
           
Total liabilities and stockholders’ equity
  $ 5,498,586     $ 5,395,881  
 
           
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
                         
    Year Ended December 31,  
    2010     2009     2008  
Revenues and other income:
                       
Natural gas, NGL and oil sales
  $ 909,607     $ 839,921     $ 1,226,560  
Transportation and gathering
    1,068       486       4,577  
Derivative fair value income
    51,634       66,446       71,861  
Gain on the sale of assets
    77,597       10,413       20,166  
Other
    (931 )     (9,925 )     1,509  
 
                 
Total revenues and other income
    1,038,975       907,341       1,324,673  
 
                 
 
                       
Costs and expenses:
                       
Direct operating
    131,602       133,211       142,387  
Production and ad valorem taxes
    33,652       32,169       55,172  
Exploration
    61,087       46,485       67,690  
Abandonment and impairment of unproved properties
    69,971       113,538       47,355  
General and administrative
    140,571       115,319       92,308  
Termination costs
    8,452       2,479        
Deferred compensation plan
    (10,216 )     31,073       (24,689 )
Interest expense
    131,192       117,367       99,748  
Loss on early extinguishment of debt
    5,351              
Depletion, depreciation and amortization
    363,507       373,502       299,831  
Impairment of proved properties
    469,749       930        
 
                 
Total costs and expenses
    1,404,918       966,073       779,802  
 
                 
 
                       
(Loss) income  before income taxes
    (365,943     (58,732 )     544,871  
 
                       
Income tax (benefit) expense
                       
Current
    (836 )     (636 )     4,268  
Deferred
    (125,851     (4,226 )     189,563  
 
                 
 
    (126,687     (4,862 )     193,831  
 
                 
 
                       
Net (loss) income
  $ (239,256   $ (53,870 )   $ 351,040  
 
                 
 
                       
(Loss) income per common share:
                       
Basic
  $ (1.53   $ (0.35 )   $ 2.32  
 
                 
 
                       
Diluted
  $ (1.53   $ (0.35 )   $ 2.25  
 
                 
 
                       
Weighted average common shares outstanding:
                       
Basic
    156,874       154,514       151,116  
Diluted
    156,874       154,514       155,943  
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
                         
    Year Ended December 31,  
    2010     2009     2008  
Operating activities:
                       
Net (loss) income
  $ (239,256 )   $ (53,870 )   $ 351,040  
Adjustments to reconcile net income to net cash provided from operating activities:
                       
Loss  from equity method investments
    1,482       13,699       218  
Deferred income tax (benefit) expense
    (125,851 )     (4,226 )     189,563  
Depletion, depreciation and amortization and proved property impairment
    833,256       374,432       299,831  
Exploration dry hole costs
    3,700       2,159       13,371  
Mark-to-market on natural gas and oil derivatives not designated as hedges
    2,086       115,909       (85,594 )
Abandonment and impairment of unproved properties
    69,971       113,538       47,355  
Unrealized derivative (gain) loss
    (2,387 )     1,696       (1,695 )
Allowance for bad debts
    3,608       1,351       450  
Amortization of deferred financing costs and other
    10,072       8,755       2,900  
Deferred and stock-based compensation
    34,964       73,402       6,621  
Gain on sale of assets and other
    (77,597 )     (10,413 )     (19,507 )
Changes in working capital:
                       
Accounts receivable
    (1,937 )     1,007       6,701  
Inventory and other
    (333 )     (1,463 )     (9,246 )
Accounts payable
    2,867       (44,765 )     10,663  
Accrued liabilities and other
    (1,323 )     464       12,096  
 
                 
Net cash provided from operating activities
    513,322       591,675       824,767  
 
                 
 
                       
Investing activities:
                       
Additions to natural gas and oil properties
    (817,033 )     (541,182 )     (881,950 )
Additions to field service assets
    (14,944 )     (33,098 )     (36,076 )
Acreage and proved property purchases
    (296,503 )     (139,288 )     (834,758 )
Investment in equity method investment and other assets
    (45 )     7,076       (44,162 )
Proceeds from disposal of assets
    327,765       234,076       68,231  
Purchase of marketable securities held by the deferred compensation plan
    (17,670 )     (7,470 )     (11,208 )
Proceeds from the sales of marketable securities held by the deferred compensation plan
    19,572       6,079       8,146  
 
                 
Net cash used in investing activities
    (798,858 )     (473,807 )     (1,731,777 )
 
                 
 
                       
Financing activities:
                       
Borrowing on credit facilities
    1,055,000       707,000       1,476,000  
Repayment on credit facilities
    (1,105,000 )     (1,076,000 )     (1,086,500 )
Issuance of subordinated notes
    500,000       285,201       250,000  
Repayment of subordinated notes
    (202,458 )            
Dividends paid
    (25,574 )     (25,169 )     (24,625 )
Debt issuance costs
    (9,600 )     (6,399 )     (8,710 )
Issuance of common stock
    5,903       12,737       291,183  
Change in cash overdrafts
    64,100       (22,370 )     4,420  
Proceeds from the sales of common stock held by the deferred compensation plan
    5,246       7,201       5,303  
Purchases of common stock held by the deferred compensation plan and other treasury stock purchases
          (55 )     (3,326 )
 
                 
Net cash provided from (used in) financing activities
    287,617       (117,854 )     903,745  
 
                 
 
                       
Increase (decrease) in cash and cash equivalents
    2,081       14       (3,265 )
Cash and cash equivalents at beginning of year
    767       753       4,018  
 
                 
Cash and cash equivalents at end of year
  $ 2,848     $ 767     $ 753  
 
                 
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except per share data)
                                                         
                                            Accumulated other    
    Common stock   Treasury   Additional paid-in   Retained   comprehensive (loss)    
    Shares   Par value   common stock   capital   earnings   income   Total
Balance as of
                                                       
December 31, 2007
    149,667     $ 1,497     $ (5,334 )   $ 1,386,884     $ 360,427     $ (25,738 )   $ 1,717,736  
Issuance of common stock
    5,942       59             291,822                   291,881  
Stock-based compensation expense
                      16,562                   16,562  
Common dividends declared ($0.16 per share)
                            (24,625 )           (24,625 )
Treasury stock purchase
                (3,223 )                       (3,223 )
Other comprehensive income
                                  101,971       101,971  
Net income
                            351,040             351,040  
Adoption of ASC 825, net of tax
                            (1,274 )     1,274        
     
Balance as of
                                                       
December 31, 2008
    155,609       1,556       (8,557 )     1,695,268       685,568       77,507       2,451,342  
Issuance of common stock
    2,727       27             57,574                   57,601  
Stock-based compensation expense
                      19,771                   19,771  
Common dividends declared($0.16 per share)
                            (25,169 )           (25,169 )
Treasury stock issuance
                593       (593 )                  
Other comprehensive loss
                                  (71,086 )     (71,086 )
Net loss
                            (53,870 )           (53,870 )
     
Balance as of
                                                       
December 31, 2009
    158,336       1,583       (7,964 )     1,772,020       606,529       6,421       2,378,589  
Issuance of common stock
    1,778       18             26,138                   26,156  
Stock-based compensation expense
                      22,797                   22,797  
Common dividends declared($0.16 per share)
                            (25,574 )           (25,574 )
Treasury stock issuance
                452       (452 )                  
Other comprehensive income
                                  61,049       61,049  
Net loss
                            (239,256 )           (239,256 )
     
Balance as of December 31, 2010
    160,114     $ 1,601     $ (7,512 )   $ 1,820,503     $ 341,699     $ 67,470     $ 2,223,761  
     
See accompanying notes.

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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
(In thousands)
                         
    December 31,  
    2010     2009     2008  
Net (loss) income
  $ (239,256   $ (53,870 )   $ 351,040  
Other comprehensive income (loss):
                       
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes
    (39,931 )     (127,965 )     39,416  
Change in unrealized deferred hedging gains (losses), net of taxes
    100,980       56,879       62,555  
 
                 
Total comprehensive (loss) income
  $ (178,207   $ (124,956 )   $ 453,011  
 
                 
See accompanying notes.

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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS
     Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas and oil company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian and Southwestern regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
     The accompanying consolidated financial statements include the accounts of all of our subsidiaries. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. Income from equity method investments represents our proportionate share of income generated by equity method investees and is included in other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated.
Use of Estimates
     The preparation of financial statements in accordance with generally accepted accounting principles in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and the reported amount of proved natural gas and oil reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.
Reclassifications
     Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation, which includes the reclassification of severance costs associated with the closing of our Houston office and the sale of our New York properties from direct operating expense, exploration expense and general and administrative expense to termination costs. The accompanying consolidated statements of operations also include the reclassification in all periods of the gain on sale of assets from other revenues and the reclassification of impairment of proved properties from depletion, depreciation and amortization. These reclassifications did not impact our net income or loss, stockholders’ equity or cash flows.
Income per Common Share
     Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding. Diluted income (loss) per common share assumes issuance of stock compensation awards, provided the effect is not antidilutive.
Business Segment Information
     We have evaluated how Range is organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, natural gas liquids (“NGLs”) and oil. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
     We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to maximize profitability without regard to individual areas or segments.

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Revenue Recognition and Gas Imbalances
     Natural gas, NGL and oil revenues are recognized when the products are sold and delivery to the purchaser has occurred. We recognize the cost of revenues, such as transportation and compression expense, as a reduction to revenue. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $5.0 million at December 31, 2010 compared to $2.2 million at December 31, 2009. During the year ended 2010, we recorded $3.6 million of bad debt expense compared to $1.4 million in the same period of the prior year.
     We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of the gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2009 were not significant. At December 31, 2010, we had recorded a net liability of $587,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.
Cash and Cash Equivalents
     Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.
Marketable Securities
     Holdings of equity securities held in our deferred compensation plans qualify as trading and are recorded at fair value. Investments in the deferred compensation plans are in mutual funds and consist of various publicly-traded mutual funds. These funds are made up of investments which include equities and money market instruments.
Inventories
     Inventories consist primarily of tubular goods used in our operations and are stated at the lower of specific cost of each inventory item or market, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations.
Natural Gas and Oil Properties
     We follow the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. NGLs and oil are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of natural gas. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules was a change in accounting principle inseparable from a change in estimate for 2009 and was accounted for prospectively. For 2009, we estimated the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves.
     Our natural gas and oil producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on

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assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. For additional information regarding 2010 and 2009 proved property impairments, see Note 11.
     Proceeds from the disposal of natural gas and oil producing properties that are part of an entire amortization group are credited to the net book value of their amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
     We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $811.8 million in 2010 compared to $774.5 million in 2009. We have recorded abandonment and impairment expense related to unproved properties of $70.0 million in 2010 compared to $113.5 million in 2009 and to $47.4 million in 2008.
Transportation and Field Assets
     Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $16.2 million in 2010 compared to $31.7 million in 2009 and $13.7 million in 2008. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that was dismantled in first quarter 2010 and replaced with permanent facilities.
Other Assets
     The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2010 include $27.9 million of unamortized debt issuance costs, $47.8 million of marketable securities held in our deferred compensation plans and $9.3 million of other investments.
Accounts Payable
     Included in accounts payable at December 31, 2010 and 2009, are liabilities of approximately $97.2 million and $33.1 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in our applicable bank accounts.
Stock-based Compensation Arrangements
     The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.
     We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period.

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Derivative Financial Instruments and Hedging
     All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.
     Through December 2010, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is probable to not occur, any unrealized gains or losses is recognized immediately in derivative fair value income in the accompanying consolidated statements of operations. During 2010, we recognized a gain of $11.6 million (pre-tax) compared to a gain of $5.4 million in 2009 and a loss of $583,000 in 2008 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives.
     We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas and oil production. Accordingly, we record changes in the fair value of our collar and call option contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these collar and call options contracts are reclassified out of AOCI and into natural gas, NGL and oil sales when the underlying physical transaction occurs and the hedging contract is settled. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income on the accompanying consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).
     Realized and unrealized gains and losses on derivatives that are not designated as hedges (or “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income in the accompanying consolidated statements of operations. We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreement that effectively fix our basis adjustments.
Asset Retirement Obligations
     The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. The depreciation will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets.

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Deferred Taxes
     Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards.
Accumulated Other Comprehensive Income (Loss)
     The following details the components of AOCI and related tax effects for the three years ended December 31, 2010. Amounts included in AOCI relate to our derivative activity.
                         
    Gross     Tax Effect     Net of Tax  
Accumulated other comprehensive loss at December 31, 2007
  $ (41,352 )   $ 15,614     $ (25,738 )
Contract settlements reclassified to income
    63,574       (24,158 )     39,416  
Change in unrealized deferred hedging gains
    98,008       (35,453 )     62,555  
Adoption of fair value accounting for trading securities
    2,022       (748 )     1,274  
 
                 
 
                       
Accumulated other comprehensive income at December 31, 2008
    122,252       (44,745 )     77,507  
Contract settlements reclassified to income
    (203,119 )     75,154       (127,965 )
Change in unrealized deferred hedging gains
    91,059       (34,180 )     56,879  
 
                 
 
                       
Accumulated other comprehensive income at December 31, 2009
    10,192       (3,771 )     6,421  
Contract settlements reclassified to income
    (64,772 )     24,841       (39,931 )
Change in unrealized deferred hedging gains
    165,642       (64,662 )     100,980  
 
                 
 
                       
Accumulated other comprehensive income at December 31, 2010
  $ 111,062     $ (43,592 )   $ 67,470  
 
                 
Accounting Pronouncements Implemented
Recently Adopted
     Accounting standards for variable interest entities were amended by the Financial Accounting Standards Board (the “FASB”) in September 2009. The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended accounting standard for variable interest entities requires reconsideration for determining whether an entity is a variable entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. The adoption of this guidance did not have an impact on our consolidated results of operations, financial position or cash flows.
     A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (a) the different classes of assets and liabilities measured at fair value, (b) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (c) the gross presentation of purchases, sales, issuances and settlements for the roll forward of Level 3 activity, and (d) the transfers in and out of Levels 1 and 2. We adopted all aspects of this standard in first quarter 2010. This adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows. See Note 11 for our disclosures about fair value measurements.
     In February 2010, the FASB amended guidance on subsequent events to alleviate potential conflicts between FASB guidance and SEC requirements. Under this amended guidance, SEC filers are no longer required to disclose the date through which subsequent events have been evaluated in originally issued and revised financial statements. This guidance was effective immediately and we adopted these new requirements in first quarter 2010. The adoption of this guidance did not have an impact on our financial statements.

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Accounting Pronouncements Not Yet Adopted
     In December 2010, the FASB issued ASU No. 2010-29, which updates the guidance in ASC Topic 805, Business Combinations. The objective of ASU 2010-29 is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amendments in ASU 2010-29 specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments affect any public entity as defined by ASC 805 that enters into business combinations that are material on an individual or aggregate basis. This guidance will become effective for us for acquisitions occurring on or after the beginning of our 2012 fiscal year. We do not expect the adoption of this guidance will have a material impact upon our financial position or results of operations.
(3) DISPOSITIONS AND ACQUISITIONS
Dispositions
     In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder in June 2010. The total proceeds we received were approximately $323.0 million and we recorded a gain of $77.6 million. The agreement had an effective date of January 1, 2010, and consequently operating net revenue after January 1, 2010 was a downward adjustment to the selling price. The proceeds we received were placed in a like-kind exchange account and in June 2010, we used a portion of the proceeds to purchase proved and unproved natural gas properties in Virginia. In September 2010, the like-kind exchange account was closed and the balance of these proceeds ($135.0 million) was used to repay amounts outstanding under our credit facility.
     In second quarter 2009, we sold certain oil properties located in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold natural gas properties in New York for proceeds of $36.3 million. The proceeds from the sale of these properties were credited to natural gas and oil properties, with no gain or loss recognized, as the dispositions did not materially impact the depletion rate of the remaining properties in the amortization base. Additionally, in fourth quarter 2009, we sold Marcellus Shale acreage for $11.2 million and we recognized a gain of $10.4 million. In first quarter 2008, we sold East Texas properties for proceeds of $64.0 million and recorded a gain of $20.2 million.
     In October 2010, we announced our plan to offer for sale our Barnett Shale properties in North Central Texas. The properties include approximately 360 producing wells and 700 proved and unproved drilling locations. The data room opened in December 2010 and on February 28, 2011, we announced that we signed a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to normal post-closing adjustments. However, the completion of the sale is dependent upon customary prospective buyer due diligence procedures and there can be no assurance the sale will be completed or that there will not be changes to the sales price. (see also Note 11).
Acquisitions
     Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.
     In June 2010, we purchased proved and unproved natural gas properties in Virginia for approximately $134.5 million. After recording asset retirement obligations, the purchase price allocated $131.3 million to proved property and $3.7 million to unproved property. We used proceeds from our like-kind exchange account to fund this acquisition (see Dispositions above). No pro forma information has been provided as the acquisition was not considered significant.
     In 2009, we completed no material acquisitions. In 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.2 million. After recording asset retirement obligations and transactions costs of $827,000, the purchase price allocated to proved properties was $232.9 million and unproved properties was $99.4 million.
(4) INCOME TAXES
     Our income tax benefit was $126.7 million for the year ended December 31, 2010 compared to income tax benefit of $4.9 million in 2009 and income tax expense of $193.8 million in 2008. A reconciliation between the statutory federal income tax rate and our effective income tax (benefit) rate  is as follows:

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    Year Ended December 31,
    2010   2009   2008
Federal statutory tax rate
    (35.0 %)     (35.0 %)     35.0 %
State
    (0.3 )     29.3       1.8  
Valuation allowance
    0.6       (2.8 )     (0.2 )
Other
    0.1       0.2       (1.0 )
 
                       
Consolidated effective tax (benefit) rate
    (34.6 %)     (8.3 %)     35.6 %
 
                       
     Income tax (benefit) provision attributable to (loss) income before income taxes consists of the following:
                         
    Year Ended December 31,  
    2010     2009     2008  
    (in thousands)  
Current:
                       
U.S. federal
  $     $ (1,000 )   $ 1,000  
U.S. state and local
    (836 )     364       3,268  
 
                 
 
  $ (836 )   $ (636 )   $ 4,268  
 
                 
 
                       
Deferred:
                       
U.S. federal
  $ (125,319 )   $ (20,913 )   $ 186,436  
U.S. state and local
    (532 )     16,687       3,127  
 
                 
 
  $ (125,851 )   $ (4,226 )   $ 189,563  
 
                 
 
                       
Total tax (benefit) provision
  $ (126,687 )   $ (4,862 )   $ 193,831  
 
                 

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     Significant components of deferred tax assets and liabilities are as follows:
                 
    December 31,  
    2010     2009  
    (in thousands)  
Deferred tax assets:
               
Current
               
Deferred compensation
  $ 5,857     $ 3,337  
Current portion of asset retirement obligation
    1,579       952  
Other
    4,106       6,207  
Current portion of net operating loss carryforward
    17,586        
 
           
Total current
    29,128       10,496  
 
           
 
               
Non-current
               
Net operating loss carryforward
    85,120       72,131  
Deferred compensation
    49,933       53,869  
AMT credits and other credits
    3,211       3,815  
Non-current portion of asset retirement obligation
    23,127       29,642  
Cumulative unrealized mark-to-market loss
    9,826       8,625  
Other
    23,481       20,311  
Valuation allowance
    (4,841 )     (2,555 )
 
           
Total non-current
    189,857       185,838  
 
           
 
               
Deferred tax liabilities:
               
Current
               
Net unrealized gain in AOCI
    (40,976 )     (2,443 )
 
           
Total current
    (40,976 )     (2,443 )
 
           
 
               
Non-current
               
Depreciation, depletion and investments
    (858,502 )     (959,931 )
Net unrealized gain in AOCI
    (2,616 )     (1,328 )
Other
    (780 )     (1,543 )
 
           
Total non-current
    (861,898 )     (962,802 )
 
           
 
               
Net deferred tax liability
  $ (683,889 )   $ (768,911 )
 
           
     At December 31, 2010, deferred tax liabilities exceeded deferred tax assets by $683.9 million, with $43.6 million of deferred tax liability related to net deferred hedging gains included in AOCI. As of December 31, 2010, we have a $4.8 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to top executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). As of December 31, 2009, we had a valuation allowance of $600,000 recorded against our capital loss carryover and a $2.0 million valuation allowance on the deferred tax asset related to our deferred compensation plan.
     At December 31, 2010, we had regular net operating loss (“NOL”) carryforwards of $413.2 million and alternative minimum tax (“AMT”) NOL carryforwards of $363.9 million that expire between 2012 and 2030. Our deferred tax asset related to regular NOL carryforwards at December 31, 2010 was $102.7 million, which is net of the ASC 718 Stock Compensation reduction for unrealized benefits. Regular NOLs generally offset taxable income and to such extent, no income tax payments are required. At December 31, 2010, we have AMT credit carryforwards of $665,000 that are not subject to limitation or expiration.
     We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Mississippi, Ohio, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in New Mexico, Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years after 2006 and we are subject to various state tax examinations for years after 2005. We have not extended the statute of limitation period in any tax jurisdiction. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2010. Throughout 2010, our unrecognized tax benefits were not material.

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(5) (LOSS) INCOME PER COMMON SHARE
     Basic net (loss) income per share attributable to common shareholders is computed as (i) net (loss) income (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted net (loss) income per share attributable to common shareholders is computed as (i) basic net (loss) income attributable to common shareholders (ii) plus diluted adjustments to income allocable to participating securities divided by weighted average diluted shares outstanding. The following table sets forth a reconciliation of net (loss) income to basic net (loss) income attributable to common shareholders and to diluted net (loss) income attributable to common shareholders and a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands except per share amounts):
                         
    Year Ended December 31,  
    2010     2009     2008  
Numerator:
                       
Net (loss) income
  $ (239,256 )   $ (53,870 )   $ 351,040  
Less: Basic income allocable to participating securities (a)
    (453 )            
 
                 
Basic net (loss) income attributable to common shareholders
    (239,709 )     (53,870 )     351,040  
Diluted adjustments to income allocable to participating securities (a)
                 
 
                 
Diluted net (loss) income attributable to common shareholders
  $ (239,709 )   $ (53,870 )   $ 351,040  
 
                 
 
                       
Denominator:
                       
Weighted average common shares outstanding — basic
    156,874       154,514       151,116  
Effect of dilutive securities:
                       
Employee stock options, SARs and stock held in the deferred compensation plan
                4,876  
Treasury shares
                (49 )
 
                 
Weighted average common shares outstanding — diluted
    156,874       154,514       155,943  
 
                 
 
                       
(Loss) income per common share:
                       
Basic — net (loss) income
  $ (1.53   $ (0.35 )   $ 2.32  
Diluted — net (loss) income
  $ (1.53   $ (0.35 )   $ 2.25  
 
(a)   Restricted stock awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Restricted stock awards do not participate in undistributed net losses.
     Weighted average common shares — basic excludes 2.8 million shares at December 31, 2010, 2.6 million shares at December 31, 2009 and 2.3 million shares at December 31, 2008 of restricted stock held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Stock appreciation rights (“SARs”) of 880,000 for the year ended December 31, 2008 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations. Due to our net loss from operations for the years ended December 31, 2010 and December 31, 2009, we excluded all outstanding stock options, stock appreciation rights and restricted stock from the computations of diluted net income per share because the effect would have been anti-dilutive.

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(6) SUSPENDED EXPLORATORY WELL COSTS
     We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to expense. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2010, 2009 and 2008 (in thousands):
                         
    2010     2009     2008  
Balance at beginning of period
  $ 19,052     $ 47,623     $ 15,053  
Additions to capitalized exploratory well costs pending the determination of proved reserves
    28,897       26,216       43,968  
Reclassifications to wells, facilities and equipment based on determination of proved reserves
    (24,041 )     (52,849 )     (3,847 )
Capitalized exploratory well costs charged to expense
          (1,938 )     (7,551 )
 
                 
Balance at end of period
    23,908       19,052       47,623  
Less exploratory well costs that have been capitalized for a period of one year or less
    (13,181 )     (10,778 )     (41,681 )
 
                 
Capitalized exploratory well costs that have been capitalized for a period greater than one year
  $ 10,727     $ 8,274     $ 5,942  
 
                 
 
                       
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year
    4       6       3  
 
                 
     As of December 31, 2010, the $10.7 million of capitalized exploratory well costs that have been capitalized for more than one year relates primarily to wells waiting on pipelines, with three of these wells in our Marcellus Shale area. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of December 31, 2010 (in thousands):
                                 
    Total     2010     2009     2008  
Capitalized exploratory well costs that have been capitalized for more than one year
  $ 10,727     $ 4,546     $ 4,602     $ 1,579  
 
                       

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(7) INDEBTEDNESS
     We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2010 is shown parenthetically). No interest was capitalized during 2010, 2009, and 2008 (in thousands):
                 
    December 31,  
    2010     2009  
Bank debt (2.7%)
  $ 274,000     $ 324,000  
 
               
Senior subordinated notes:
               
7.375% senior subordinated notes due 2013, net of $1,638 discount in 2009
          198,362  
6.375% senior subordinated notes due 2015
    150,000       150,000  
7.5% senior subordinated notes due 2016, net of $317 and $363 discount, respectively
    249,683       249,637  
7.5% senior subordinated notes due 2017
    250,000       250,000  
7.25% senior subordinated notes due 2018
    250,000       250,000  
8.0% senior subordinated notes due 2019, net of $13,147 and $14,166 discount, respectively
    286,853       285,834  
6.75% senior subordinated notes due 2020
    500,000        
 
           
Total debt
  $ 1,960,536     $ 1,707,833  
 
           
Bank Debt
     In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. On December 31, 2010, the facility amount was $1.25 billion and the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-six commercial banks, with no one bank holding more than 5% of the total facility. The facility amount may be increased to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. As of December 31, 2010, the outstanding balance under the bank credit facility was $274.0 million as well as $5.4 million of undrawn letters of credit leaving $970.1 million of borrowing capacity available under the facility amount. The loan matures on October 25, 2012. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.75% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. The weighted average interest rate was 2.2% for the year ended December 31, 2010 compared to 2.4% for the year ended December 31, 2009 and 4.4% for the year ended December 31, 2008. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2010, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.875% on our base rate loans.
Subsequent Development
     On February 18, 2011, we entered into an amended and restated revolving bank facility, which replaced our previous bank credit facility. The new facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. At closing, the facility amount was $1.5 billion, the borrowing base was $2.0 billion and there was $1.0 billion of borrowing capacity available under the facility amount. The new bank credit facility provides for a borrowing base subject to redetermination semi-annually each April and October and for event-driven unscheduled redeterminations. The new bank group is comprised of twenty-seven commercial banks, with no one bank holding more than 7% of the total facility. The facility amount may be increased to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. As of February 25, 2011, the outstanding balance under the bank credit facility was $440.0 million and of undrawn letters of credit leaving $1.1 billion of borrowing capacity available under the facility amount. The loan matures on February 18, 2016. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.50% to 1.50% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.50% to 2.5%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to base rate loans or to convert all or any of the base rate loans to LIBOR loans. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At closing, the commitment fee was 0.375% and the interest rate margin was 1.50% on our LIBOR loans and 0.50% on our base rate loans.

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Senior Subordinated Notes
     In August 2010, we issued $500.0 million aggregate principal amount of 6.75% senior subordinated notes due 2020 (“6.75% Notes”) for net proceeds after underwriting discounts and commissions of $491.3 million. The 6.75% Notes were issued at par. Interest on the 6.75% Notes is payable semi-annually in February and August and is guaranteed by substantially all of our subsidiaries. We may redeem the 6.75% Notes, in whole or in part, at any time on or after August 1, 2015, at redemption prices of 103.375% of the principal amount as of August 1, 2015 declining to 100.0% on August 1, 2018 and thereafter. Before August 1, 2013, we may redeem up to 35% of the original aggregate principal amount of the 6.75% Notes at a redemption price equal to 106.75% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that at least 65% of the original aggregate principal amount of the 6.75% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. We used $287.1 million of the proceeds to repay outstanding borrowings under our credit facility and $204.2 million to redeem our 7.375% senior subordinated notes due 2013.
     If we experience a change of control, there will be a requirement to repurchase all or a portion of all of our senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and will be subordinated to future senior debt that we or our subsidiary guarantors are permitted to incur under the bank credit facility and the indentures governing the subordinated notes.
Early Extinguishment of Debt
     In August 2010, we redeemed our 7.375% senior subordinated notes due 2013 at a redemption price equal to 101.229%. We recorded a loss on extinguishment of debt of $5.4 million including the transaction call premium costs as well as the expensing of related deferred financing cost on the repurchased debt.
Guarantees
     Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our subsidiaries of our senior subordinated notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.
Debt Covenants and Maturity
     Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at December 31, 2010.
     Following is the principal maturity schedule for the long-term debt outstanding as of December 31, 2010 (in thousands):
         
    Year Ended
December 31,
 
2011
  $  
2012
    274,000  
2013
     
2014
     
2015
    150,000  
2016
    249,682  
Thereafter
    1,286,854  
 
     
 
  $ 1,960,536  
 
     
     The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At December 31, 2010, we were in compliance with these covenants.

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(8) ASSET RETIREMENT OBLIGATIONS
     Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2010 and 2009 is as follows (in thousands):
                 
    2010     2009  
Beginning of period
  $ 78,812     $ 83,457  
 
               
Liabilities incurred
    1,562       1,622  
Acquisitions
    556        
Liabilities settled
    (2,605 )     (724 )
Disposition of wells
    (12,891 )     (15,946 )
Accretion expense
    5,320       5,893  
Change in estimate
    (8,081 )     4,510