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

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

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.

     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.		Business			1
ITEM 1A.		Risk Factors			11
ITEM 1B.		Unresolved Staff Comments			20
ITEM 2.		Properties			20
ITEM 3.		Legal Proceedings			29
ITEM 4.		(Removed and Reserved)			29
PART II
ITEM 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			30
ITEM 6.		Selected Financial Data			32
ITEM 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			34
ITEM 7A.		Quantitive and Qualitative Disclosures about Market Risk			54
ITEM 8.		Financial Statements and Supplementary Data			56
ITEM 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			56
ITEM 9A.		Controls and Procedures			56
ITEM 9B.		Other Information			57
PART III
ITEM 10.		Directors, Executive Officers and Corporate Governance			58
ITEM 11.		Executive Compensation			61
ITEM 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			61
ITEM 13.		Certain Relationships and Related Transactions and Director Independence			61
ITEM 14.		Principal Accountant Fees and Services			61
PART IV
ITEM 15.		Exhibits and Financial Statement Schedules			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

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.

     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.

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

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

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

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.

     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

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.

     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

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.

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:

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the domestic and foreign supply of natural gas and oil;

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the price and availability of alternative fuels;

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weather conditions;

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the level of consumer demand;

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the price of foreign imports;

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worldwide economic conditions;

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the availability, proximity and capacity of transportation facilities and processing facilities;

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the effect of worldwide energy conservation efforts;

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political conditions in natural gas and oil producing regions; and

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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:

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the amount and timing of natural gas and oil production;

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the revenues and costs associated with that production; and

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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

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.

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:

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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;

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a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;

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we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;

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our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;

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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;

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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

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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:

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injury or loss of life;

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severe damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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clean-up responsibilities;

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regulatory investigations and penalties; or

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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.

     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:

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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

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.

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

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;

•

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.

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.

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.

     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

		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

		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

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

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.

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

     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

     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	%

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

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.

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:

		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.

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)

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.

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.

		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

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

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