UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

 

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

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
100 Throckmorton Street, Suite 1200, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code
(817) 870-2601

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 þ No o

     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 (Do not check if a smaller reporting company)		Smaller reporting company o

     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, 2009 was $6,361,198,000. 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 19, 2010, there were 159,142,506 shares of Range Resources Corporation Common Stock outstanding.

     Portions of the registrant’s proxy statement to be furnished to stockholders in connection with its 2010 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 oil and gas 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			10
ITEM 1B. Unresolved Staff Comments			19
ITEM 2. Properties			19
ITEM 3. Legal Proceedings			25
ITEM 4. Submission of Matters to a Vote of Security Holders			25
PART II
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			26
ITEM 6. Selected Financial Data			28
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			30
ITEM 7A. Quantitive and Qualitative Disclosures about Market Risk			48
ITEM 8. Financial Statements and Supplementary Data			51
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			51
ITEM 9A. Controls and Procedures			51
ITEM 9B. Other Information			52
PART III
ITEM 10. Directors, Executive Officers and Corporate Governance			53
ITEM 11. Executive Compensation			57
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			57
ITEM 13. Certain Relationships and Related Transactions and Director Independence			57
ITEM 14. Principal Accountant Fees and Services			57
PART IV
ITEM 15. Exhibits and Financial Statement Schedules			58
GLOSSARY OF CERTAIN DEFINED TERMS			59
SIGNATURES			61
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
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

RANGE RESOURCES CORPORATION

Annual Report on Form 10-K

Year Ended December 31, 2009

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,” “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 oil and gas 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 oil and gas 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 company, engaged in the exploration, development and acquisition of primarily natural gas properties, mostly in the Southwestern and Appalachian 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. In 1999, we implemented a strategy of internally generated drillbit growth coupled with complementary acquisitions. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. During the past five years, we have increased our proved reserves 166% (from 1.2 Tcfe in 2004 to 3.1 Tcfe in 2009), while production has increased 122% (from 71,726 Mmcfe in 2004 to 159,112 Mmcfe in 2009) during that same period.

     At year-end 2009, our proved reserves had the following characteristics:

	•		3.1 Tcfe of proved reserves;
	•		84% natural gas;
	•		55% proved developed;
	•		79% operated;
	•		a reserve life of 18.6 years (based on fourth quarter 2009 production);
	•		a pre-tax present value of $2.6 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 $2.1 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 $501.7 million at December 31, 2009.

     At year-end 2009, we owned 3,214,000 gross (2,504,000 net) acres of leasehold, including 289,000 acres where we also own a royalty interest. We have built a multi-year drilling inventory that is estimated to contain over 11,500 drilling locations, both proven and unproven.

     Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our telephone number is (817) 870-2601.

Business Strategy

     Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy is to employ internally generated drillbit growth coupled with complementary acquisitions. Our strategy requires us to make significant investments in technical staff, acreage and 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 Southwestern (which includes the Barnett Shale of North Central 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) and Appalachian (which includes tight-gas, shale, coal bed methane and conventional oil and gas production in Pennsylvania, Virginia, Ohio, New York and West Virginia). 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.
	•		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 oil and gas is in the best performing quartile of our peer group.
	•		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 11,500 identified drilling locations in inventory, both proven and unproven. In 2009, we drilled 463 gross (285.4 net) wells.
	•		Maintain Long-Life Reserve Base. Long-life oil and gas 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 oil and gas 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 execute this strategy.
	•		Maintain Flexibility. Because of the volatility of commodity prices and the risks involved in drilling, 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.
	•		Make Complementary Acquisitions. We target complementary acquisitions in existing core areas where our existing operating and technical knowledge is transferable and drilling results can be forecast with confidence. Over the past three years, we have completed $612.1 million of complementary acquisitions. These acquisitions have been located primarily in the Barnett Shale in North Central Texas and the Marcellus Shale in Pennsylvania.
	•		Equity Ownership and Incentive Compensation. We want our employees to think and act like owners. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees receive equity

grants. As of December 31, 2009, our employees owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $312.7 million.

Significant Accomplishments in 2009

	•		Production and reserve growth — Fourth quarter 2009 marked Range’s 28th consecutive quarter of sequential production growth. In 2009, our annual production averaged 435.9 Mmcfe per day, an increase of 13% from 2008. Proven reserves increased 18% in 2009 to 3.1 Tcfe, marking the eighth consecutive year our proven reserves have increased. This achievement is the result of our continued drilling success, as all of production and reserve growth in 2009 came from our drilling program. Our business is inherently volatile, and while consistent growth such as we have experienced over the past seven years will be challenging to sustain, the quality of our technical teams and our sizable drilling inventory bode well for the future.
	•		Successful drilling program — In 2009, we drilled 463 gross wells. Production was replaced by 484% through drilling in 2009, and our overall success rate was nearly 100%. 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 resource shale plays in 2009. We have two large unconventional plays — the Marcellus Shale in Pennsylvania 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 1.2 million net acres in these two shale plays. We also have 263,000 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, remained level at 42% for both year-end 2008 and 2009. We refinanced $285.2 million of shorter-term bank debt by issuing $300.0 million of senior subordinated fixed rate 8.0% notes having a 10-year maturity, at a discount. This helped to align the maturity schedule of our debt with the long-term life of our assets and reduce interest rate volatility.
	•		Successful unproved property purchases completed — In 2009, we acquired $176.9 million of acreage located in our core areas, primarily in the Marcellus Shale. We paid cash and issued stock for this acreage. We continued to see outstanding results in the Marcellus Shale. Production increased 150%, we proved up additional unproved acreage, acquired additional acreage and continue to work with outside parties to gain pipeline and processing capacity.
	•		Successful dispositions completed — In second quarter 2009, we sold oil properties in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold our natural gas properties in New York for proceeds of $36.3 million. See also Note 3 to our consolidated financial statements.

Industry Operating Environment

     The oil and 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 gas commodity prices. However, since mid-year 2008, we have experienced declines in commodity prices, especially with regard to natural gas prices.

     Significant factors that will impact 2010 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. Natural gas prices are generally determined by North American supply and demand and are also affected by imports of liquefied natural gas. In addition, weather has a significant impact on demand for natural gas since it is a primary heating source.

Plans for 2010

     Our capital expenditure budget for 2010 has been initially set at approximately $950.0 million. 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 2010 budget includes $700.0 million to drill 464 gross (338.2 net) wells and to undertake 38 gross (29.0 net) recompletions. Also included is $190.0 million for land, $20.0 million for seismic and $40.0 million for the expansion and enhancement of gathering systems and facilities. Approximately 82% of the budget is attributable to the Appalachian region and 18% to the Southwestern region.

     In December 2009, we announced our plan to offer for sale our tight gas sand properties in Ohio. The properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. Parties began conducting evaluations in January 2010 and on February 8, 2010 we announced that we had entered into a definitive agreement to sell these assets for a price of $330.0 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 oil and gas production, realized prices and production costs for the last three years. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

		Year Ended December 31,
		2009				2008				2007
Production
Gas (Mmcf)			130,649				114,323				89,595
Crude oil (Mbbls)			2,557				3,084				3,360
Natural gas liquids (Mbbls)			2,187				1,386				1,115
Total (Mmcfe) (a)			159,112				141,145				116,441
Average sales prices (wellhead)
Gas (per mcf)		$	3.32			$	8.07			$	6.54
Crude oil (per bbl)			54.98				96.77				67.47
Natural gas liquids (per bbl)			28.99				49.43				41.40
Total (per mcfe) (a)			4.00				9.14				7.37
Average realized prices (including derivatives that qualify for hedge accounting):
Gas (per mcf)		$	4.77			$	8.15			$	6.85
Crude oil (per bbl)			59.75				73.38				60.40
Natural gas liquids (per bbl)			28.99				49.43				41.40
Total (per mcfe) (a)			5.28				8.69				7.41
Average realized prices (including all derivative settlements)
Gas (per mcf)		$	6.13			$	8.15			$	7.66
Crude oil (per bbl)			62.58				68.20				60.16
Natural gas liquids (per bbl)			28.99				49.43				41.40
Total (per mcfe) (a)			6.44				8.58				8.02
Production costs
Lease operating (per mcfe)		$	0.78			$	0.92			$	0.84
Workovers (per mcfe)			0.04				0.07				0.06
Stock-based compensation (per mcfe)			0.02				0.02				0.02
Total (per mcfe)		$	0.84			$	1.01			$	0.92

Employees

     As of January 1, 2010, we had 787 full-time employees, 373 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 are 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 oil and gas 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 oil and gas 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 gas is sold on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. We sell less than 400 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. Oil and gas purchasers are selected on the basis of price, credit quality and service reliability. For a summary of purchasers of our oil and gas production that accounted for 10% or more of consolidated revenue, see Note 16 to our consolidated financial statements. Because alternative purchasers of oil and gas 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 significant portions of our production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas 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 international political developments, overall energy supply and demand, fluctuating weather conditions, 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 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 4,000 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 oil and gas transportation facilities, many of which are owned by others,” in Item 1A of this report.

Governmental Regulation

     Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing 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. It therefore reflects a significant expansion of FERC’s enforcement authority. Range does not anticipate it will be affected any differently than other producers 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”). Under Order 720, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million Mmbtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. Requests for clarification and rehearing of Order 720 have been filed at FERC and a decision on those requests is pending.

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

     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.

     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.

     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.

     In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, which would establish an economy-wide cap-and-trade program to reduce “greenhouse gas” emissions, including carbon dioxide and methane by 17 percent from 2005 levels by the year 2020 and 80 percent by the year 2050. The U.S. Senate is considering a number of comparable measures. One such measure, the Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been reported out of the Senate Committee on Energy and Natural Resources, but has not yet been considered by the full Senate and also includes a cap-and-trade system for controlling greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The ultimate outcome of these bills remains uncertain, and such bills would have to undergo reconciliation before being adopted as law.

     In addition, 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 September 15, 2009, EPA and the Department of Transportation proposed rules that would limit emissions of greenhouse gases from motor vehicles. The Agencies are expected to finalize those rules in March of 2010.

     While EPA’s endangerment findings and its proposed rules on greenhouse gas emissions from mobile sources do not specifically address stationary sources, it is EPA’s view that once the mobile sources rules are finalized in March 2010, emissions of greenhouse gases from stationary sources will be covered under the federal Prevention of Significant Deterioration and Title V air permit programs, which apply to “major sources” of air emissions. In order to deal with the problem of an excessive number of sources being drawn into these programs, EPA has proposed to reset the 250 tons per year “major source” threshold to 25,000 tons per year of carbon dioxide CO2e (carbon dioxide equivalency) in the “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule.”

     On September 23, 2009, EPA finalized a greenhouse gas reporting rule establishing a national greenhouse gas emissions collection and reporting program. The EPA rules will require covered entities to measure greenhouse gas emissions commencing in 2010 and submit reports commencing in 2011. 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. We do not believe our operations require reporting or monitoring of carbon dioxide emissions under existing laws and regulations; however, we do 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 including 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.

     Finally, 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 the federal Safe Drinking Water Act, or the 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 2009, nor do we anticipate that such expenditures will be material in 2010. However, we regularly have expenditures to comply with environmental laws and those costs continue to increase as our operations expand.

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 oil and gas prices significantly affects our cash flow and capital resources and could hamper our ability to produce oil and gas economically

     Oil and gas 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 oil and gas have been volatile. Historically, the industry has experienced downturns characterized by oversupply and/or weak demand. Long-term supply and demand for oil and gas is uncertain and subject to a myriad of factors such as:

	•		the domestic and foreign supply of oil and gas;
	•		the price and availability of alternative fuels;
	•		weather conditions;
	•		the level of consumer demand;
	•		the price of foreign imports;
	•		worldwide economic conditions;
	•		the availability, proximity and capacity of transportation facilities and processing facilities;
	•		the effect of worldwide energy conservation efforts;
	•		political conditions in oil and gas producing regions; and
	•		domestic and foreign governmental regulations and taxes.

     Oil and gas prices have been volatile over the past 18 months. 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. Decreases in oil and gas prices have adversely affected our revenues, net income, cash flow and proved reserves. Significant price decreases could have a material adverse effect on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained decreases in oil and gas prices will further adversely affect our revenues, net income, cash flows, proved reserves and our ability to fund capital expenditures.

Information concerning our reserves and future net cash flow estimates is uncertain

     There are numerous uncertainties inherent in estimating quantities of proved oil and gas 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 oil and gas 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 oil and gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

	•		the amount and timing of oil and gas production;
	•		the revenues and costs associated with that production; and
	•		the amount and timing of future development expenditures.

     The discounted future net cash flows from our proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. For 2009, 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 oil and gas prices decrease or drilling efforts are unsuccessful, we may be required to record write downs of our oil and gas properties

     In the past we have been required to write down the carrying value of certain of our oil and gas properties, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur when oil and gas 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 economics.

     Accounting rules require that the carrying value of oil and gas properties be periodically reviewed for possible impairment. Impairment is recognized 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 oil and gas prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics 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.

     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.

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. From time to time, 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 oil and gas 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 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 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 oil and gas prices in 2008 has 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 gas prices) continue to decline in 2010, 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 oil and gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and gas 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 oil and gas 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.

Our indebtedness could limit our ability to successfully operate our business

     We are leveraged and our exploration and development program will require substantial capital resources depending on the level of drilling and the expected cost of services. Our existing operations will also require ongoing capital expenditures. In addition, if we decide to pursue additional acquisitions, our capital expenditures will increase, both to complete such acquisitions and to explore and develop any newly acquired properties.

     The degree to which we are leveraged could have other important consequences, including the following:

	•		we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;
	•		a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;
	•		we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;
	•		our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;
	•		we are subject to numerous financial and other restrictive covenants contained in our existing credit agreements the breach of which could materially and adversely impact our financial performance;
	•		our debt level could limit our flexibility to grow the business and in planning for, or reacting to, changes in our business and the industry in which we operate; and
	•		we may have difficulties borrowing money in the future.

     Despite our current levels of indebtedness, we still may be able to incur substantially more debt. This could further increase the risks described above. In addition to those risks above, we may not be able to obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly.

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

     Oil and gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic natural gas and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:

	•		injury or loss of life;
	•		severe damage to or destruction of property, natural resources and equipment;
	•		pollution or other environmental damage;
	•		clean-up responsibilities;
	•		regulatory investigations and penalties; or
	•		suspension of operations.

     We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. We have experienced substantial increases in premiums, especially in areas affected by hurricanes and tropical storms. Insurers have imposed revised limits affecting how much the insurers will pay on actual storm claims plus the cost to re-drill wells where substantial damage has been incurred. Insurers are also requiring us to retain larger deductibles and reducing the scope of what insurable losses will include. Even with the increase in future insurance premiums, coverage will be reduced, requiring us to bear a greater potential risk if our oil and gas 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, 2009, approximately 81% of our debt is at fixed interest rates with the remaining 19% subject to variable interest rates.

     Recent and 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 senior 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 and the economy generally may materially adversely affect our business and results of operations

     Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the repricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain financing. In addition, as a result of concerns about the stability of financial markets generally 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 oil, natural gas liquids or gas 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 oil and gas prices rise above the price established by the hedge.

     In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

	•		our production is less than expected;
	•		the counterparties to our futures contracts fail to perform under the contracts; or
	•		an event materially impacts oil or gas prices or the relationship between the hedged price index and the oil and gas sales price.

     We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and gas. 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 oil and gas prices than our competitors who engage in hedging transactions.

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

     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 (as amended by orders on rehearing, “Order 704”) 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 regarding those transactions to FERC. In addition, FERC has issued a final rule (“Order 720”) 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 EPAct 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 four otherwise non-FERC jurisdiction facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. We also must comply 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 oil and gas industry is subject to extensive regulation

     The oil and gas 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 oil and gas 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. 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 and legislators alike. The debate is ongoing 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, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.

     Presently there are no federally mandated greenhouse gas reduction requirements in the United States. However, in June 2009 the U.S. House of Representatives passed bill H.R. 2454, American Clean Energy and Security Act of 2009, which proposes reducing greenhouse gas emissions to 17% below 2005 levels by 2020 and 83% below 2005 levels by 2050. The bill has now passed to the United States Senate for debate and vote. Consequently, the precise federal mandatory emissions reduction program that may be adopted and the specific requirements of any such program are uncertain.

     There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phase 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, additional charges to fund energy efficiency activities, 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.

     Any adoption by federal or state governments mandating a substantial 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.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

     Among the changes contained in President Obama’s budget proposal for fiscal year 2011, released by the White House on February 1, 2010, is the elimination of certain U.S. federal income tax provisions 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, 2009, we have a tax basis of $526 million related to prior year capitalized intangible drilling costs which will be amortized over the next five years.

     The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operation.

     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. 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.

     The elimination of certain federal tax deductions or the imposition of new state taxes discussed about could negatively affect our financial condition and results of operations.

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 a high-risk 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 oil and gas 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 oil and gas prices;
	•		limitations in the market for oil and gas;
	•		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, pipelines 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 oil and gas 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.

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

     The United States Congress is currently considering legislation to amend the Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formation to stimulate natural gas 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. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level. This additional regulation and permitting could lead to operational delays or increased operating costs and could result in additional burdens that could 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.

Our business depends on oil and gas transportation facilities, most of which are owned by others

     The marketability of our oil and gas production depends in part on the availability, proximity and capacity of pipeline systems 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. Federal and state regulation of oil and gas 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 oil and gas. If any of these third party pipelines and other facilities become partially or fully unavailable to transport 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. We have no control over when or if such facilities are restored or 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 rules 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. 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, 2007 to December 31, 2009, 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 oil and gas 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

     As of the date of this filing, we have no unresolved comments from the staff of the Securities and Exchange Commission.

ITEM 2.		PROPERTIES

     The table below summarizes data for our operating regions for the year ended December 31, 2009.

		Average
		Daily
		Production												Proved				Percentage of
		(mcfe				Production				Percentage of				Reserves				Proved
Region		per day)				(mcfe)				Production				(Mmcfe)				Reserves
Southwestern			256,941				93,783,324				59	%			1,314,497				42	%
Appalachian			178,982				65,328,638				41	%			1,814,242				58	%
			435,923				159,111,962				100	%			3,128,739				100	%

     Approximately 65% of our proved reserves at December 31, 2009 are located in the Barnett Shale in our Southwestern region and the Marcellus Shale and Nora Area in our Appalachian region. Each of these plays has a large portfolio of drilling opportunities. Our reserve estimates do not include any probable or possible reserves. 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.

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 1,854 net producing wells, 96% of which we operate. Our average working interest is 66%. We have approximately 886,000 gross (568,000 net) acres under lease.

     Total proved reserves in the Southwestern region decreased 26.6 Bcfe, or 2%, at December 31, 2009, when compared to year-end 2008. Production, asset sales (103.5 Bcfe) and an unfavorable reserve revision for lower prices were partially offset by drilling additions (195.5 Bcfe). Annual production increased 4% over 2008. During 2009, the region spent $252.9 million to drill 90 (77.1 net) development wells, of which 89 (76.5 net) were productive, and 7 (6.1 net) exploratory wells, of which 6 (5.4 net) were productive. During the year, the region achieved a 99% drilling success rate.

     At December 31, 2009, the Southwestern region had a development inventory of 441 proven drilling locations and 421 proven recompletions. During the year, the Southwestern region drilled 37 proven locations and added 75 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 in 2007 and 2008. We now own approximately 131,700 net acres. At December 31, 2009, we have 167 proven drilling locations in this area, and 51 proven recompletions and plan to drill 28 wells in 2010. Our production in the Barnett Shale increased from 93,654 mcfe per day in 2008 to 122,030 mcfe per day in 2009. During 2009, we drilled 47 net development wells, all of which were successful.

Appalachian Region

     Our properties in this area are located in the Appalachian Basin in the northeastern United States, principally in Pennsylvania, Ohio, West Virginia and Virginia. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton, Big Lime and Marcellus Shale formations at depths ranging from 2,500 to 9,000 feet. Generally, after initial flush production, most of these properties are characterized by gradual decline rates, typically producing for more than 40 years. We own 8,052 net producing wells, 66% of which we operate, and approximately 4,000 miles of gas gathering lines. Our average working interest is 77%. We have approximately 2.3 million gross (1.9 million net) acres under lease, which include 289,000 acres where we also own a royalty interest.

     Reserves at December 31, 2009 increased 501.8 Bcfe, or 38%, from 2008 with drilling additions (574.4 Bcfe) partially offset by asset sales (36.1 Bcfe) and production. Annual production increased 28% over 2008. During 2009, the region spent $348.8 million to drill 352 (194.0 net) development wells, all of which were productive, and 14 (8.3 net) exploratory wells, all of which were productive. At December 31, 2009, the Appalachian region had an inventory of 3,600 proven drilling locations and 500 proven recompletions. During the year, the Appalachian region drilled 248 proven locations and added 566 new proven locations.

     In December 2009, we announced our plans to offer for sale our tight gas sand properties in Ohio, which include 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipelines and gathering system infrastructure. Parties began evaluations in January 2010 and on February 8, 2010, we announced that we had entered into a definitive agreement to sell these assets for a purchase price of $330.0 million, subject to typical post-closing terms and conditions. In 2009, these properties produced 25.9 Mmcfe per day.

Marcellus Shale

     We began operations in the Marcellus Shale, located in Pennsylvania, in 2004. This has been our largest investment area over the last two years. We recorded 167 proven drilling locations at December 31, 2009. Our 2009 production was 150% greater than 2008 and at year-end 2009 was about 113,000 mcfe per day. During 2009, we drilled 44 net development wells and 4 net exploratory wells in the Marcellus Shale, all of which were successful. In 2010, we plan to drill 150 wells.

     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 three 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.

Nora Area

     In 2004, we acquired natural gas properties in the Nora Area. In 2007, 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 Field. Production in the Nora Area increased from 46,800 Mcfe per day in 2008 to 52,400 Mcfe per day in 2009. During 2009, we drilled 148 net development wells and 4 net exploratory wells and achieved a 100% drilling success rate. In 2010, we plan to drill 229 wells.

Proved Reserves

     In December 2008, the SEC announced that it had approved revisions to modernize its oil and gas company reserve reporting requirements. We adopted the new rules as of December 31, 2009. See additional disclosures below and also in Item 8. Financial Statements and Supplemental information on Natural Gas and Oil Exploration, Development and Production Activities. 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-End Prices
		Oil and NGLs				Natural Gas				Total
Reserve Category		(Mbbls)				(Mmcf)				(Mmcfe)				%
Proved
Developed			46,831				1,445,705				1,726,696				55	%
Undeveloped			38,839				1,169,012				1,402,043				45	%
Total Proved			85,670				2,614,717				3,128,739

     The following table sets forth our estimated proved reserves for 2008, 2007, 2006 and 2005 based on end of year prices:

		2008				2007				2006				2005
Natural gas (Mmcf)
Developed			1,337,978				1,144,709				875,395				724,876
Undeveloped			875,568				688,088				560,583				400,534
Total			2,213,546				1,832,797				1,435,978				1,125,410
Oil and NGLs (Mbbls)
Developed			49,009				47,015				37,750				33,029
Undeveloped			24,327				19,645				15,957				13,863
Total			73,336				66,660				53,707				46,892
Total (Mmcfe) (a)			2,653,565				2,232,762				1,758,226				1,406,762
% Developed			62	%			64	%			63	%			66	%

     The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2009:

		Reserve Volumes																PV-10 (a)
		Natural Gas				Oil & NGL				Tota								Amount
		(Mmcf)				(Mbbls)				(Mmcfe)				%				(In thousands)				%
Southwestern Region			1,057,475				42,837				1,314,497				42	%		$	1,202,950				46	%
Appalachian Region			1,557,242				42,833				1,814,242				58	%			1,389,847				54	%
Total			2,614,717				85,670				3,128,739				100	%		$	2,592,797				100	%

Recent SEC Rule-Making Activity

     In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

	•		Commodity Prices — Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
	•		Disclosure of Unproved Reserves — Probable and possible reserves may be disclosed separately on a voluntary basis.
	•		Proved Undeveloped Reserve Guidelines — Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
	•		Reserves Estimation Using New Technologies — Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
	•		Reserves Personnel and Estimation Process — Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
	•		Non-Traditional Resources — The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

     We adopted the rules effective December 31, 2009, as required by the SEC.

Effect of Adoption

     Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of the new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 86.0 Bcfe. Use of the old year-end prices rules would have resulted in an increase in proved reserves of approximately 3.0 Bcfe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 89.0 Bcfe. We also estimate that we added 230 Bcfe of additional proved undeveloped reserves, primarily in our Marcellus Shale play, where we have experienced good drilling results as allowed by the new SEC definitions.

Reserve Estimation

     At year-end 2009, the following independent petroleum consultants conducted a review of our 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, 2009, these consultants collectively reviewed approximately 88% 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 reserves 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; oil and gas 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. 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, 2009 with any federal authority or agency with respect to our estimate of oil and gas 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 Oil and Natural Gas Liquids

     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, 2009 natural gas liquids represented approximately 10% 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 include this production as barrels of oil. Prices for a standard barrel of natural gas liquids in 2009 averaged approximately 47% 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, 2009, our PUDs totaled 38.8 Mmbbls of crude oil and 1.2 Tcf of natural gas, for a total of 1.4 Tcfe. Approximately 77% of our PUDs at year-end 2009 were associated with our major development areas in the Barnett, Marcellus and Nora properties. Changes in PUDs that occurred during the year were due to:

	•		conversion of approximately 117 Bcfe PUDs into proved developed reserves;
	•		new PUDs added of 528 Bcfe; and
	•		negative revisions of approximately 30 Bcfe in PUDs due to change in commodity prices.

     Costs incurred relating to the development of PUDs were approximately $140 million in 2009. Estimated future development costs relating to the development of PUDs are projected to be approximately $292 million in 2010, $472 million in 2011, and $428 million in 2012. All PUD drilling locations are scheduled to be drilled prior to the end of 2014.

     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):

		December 31, 2009
		2009				2008				2007				2006				2005
Future net cash flows		$	6,721			$	8,441			$	11,908			$	6,391			$	10,429
Present value
Before income tax			2,593				3,400				5,205				2,771				4,887
After income tax (Standardized Measure)			2,091				2,581				3,666				2,002				3,384
Benchmark prices (NYMEX)
Oil price (per barrel)			60.85				44.60				95.98				61.05				61.04
Gas price (per mcf)			3.87				5.71				6.80				5.64				10.08
Wellhead prices
Oil price (per barrel)			54.65				42.76				91.88				57.66				57.80
Gas price (per mcf)			3.19				5.23				6.44				5.24				9.83

     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 the new SEC rules, prices for 2009 were based on a twelve-month average, without escalation. Prices for 2005, 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, 2009. 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 crude oil or gas 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			9,868				7,378				75	%
Crude oil			1,741				1,593				92	%
Total			11,609				8,972				77	%

     The day-to-day operations of oil and gas 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.

Acreage

     We own interests in developed and undeveloped oil and gas acreage. These ownership interests generally take the form of working interests in oil and 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, 2009. 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			—				—				67,465				61,217				67,465				61,217
Louisiana			8,351				3,083				6,049				2,912				14,400				5,995
Michigan			161				161				123				123				284				284
Mississippi			5,794				3,370				39,792				20,908				45,586				24,278
New Mexico			6,890				4,967				1,200				912				8,090				5,879
New York			—				—				26,106				13,157				26,106				13,157
Ohio			270,483				251,827				239,466				210,872				509,949				462,699
Oklahoma			176,020				106,739				136,193				73,469				312,213				180,208
Pennsylvania			650,795				560,865				629,596				565,966				1,280,391				1,126,831
Texas			256,538				170,824				181,358				119,546				437,896				290,370
Virginia			93,805				47,949				180,134				95,076				273,939				143,025
West Virginia			66,143				63,966				122,372				119,730				188,515				183,696
			1,534,980				1,213,751				1,629,854				1,283,888				3,164,834				2,497,639
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
2010			239,268				182,985				14	%
2011			362,698				300,869				23	%
2012			272,384				231,497				18	%
2013			135,353				125,319				10	%
2014			44,941				40,053				3	%

     We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three 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. 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.

Drilling Results

     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, 2009, we were in the process of drilling 13 gross (13 net) wells.

		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Development wells
Productive			441.0				270.4				602.0				466.0				942.0				680.5
Dry			1.0				0.6				6.0				4.9				9.0				7.9
Exploratory wells
Productive			20.0				13.7				20.0				16.1				11.0				6.3
Dry			1.0				0.7				6.0				3.2				5.0				3.5
Total wells
Productive			461.0				284.1				622.0				482.1				953.0				686.8
Dry			2.0				1.3				12.0				8.1				14.0				11.4
Total			463.0				285.4				634.0				490.2				967.0				698.2
Success ratio			99.6	%			99.6	%			98.1	%			98.3	%			98.6	%			98.4	%

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 15 to our consolidated financial statements.

ITEM 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     There were no matters submitted to a vote of our security holders during fourth quarter 2009.

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 2009, trading volume averaged 2.7 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
2008
First quarter		$	65.53			$	43.02			$	0.04
Second quarter			76.81				61.13				0.04
Third quarter			72.98				37.34				0.04
Fourth quarter			44.15				23.77				0.04
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

     Between January 1, 2010 and February 19, 2010, the common stock traded at prices between $45.00 and $54.65 per share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.

Holders of Record

     On February 19, 2010, there were approximately 1,545 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 of Directors deems relevant. 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. As of December 31, 2009, 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, 2009. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2004, and that dividends were reinvested.

		2004				2005				2006				2007				2008				2009
Range Resources Corporation		$	100			$	194			$	203			$	380			$	255			$	371
S&P 500 Index			100				105				121				128				81				102
DJ U.S. Expl. & Prod. Index			100				165				174				250				150				211

ITEM 6.		SELECTED FINANCIAL DATA

     The following table shows selected financial information for the five years ended December 31, 2009. Significant producing property acquisitions in 2006, 2007 and 2008 affect the comparability of year-to-year financial and operating data. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. The financial and statistical data contained in the following discussion reflect our Gulf of Mexico operations as discontinued operations. All weighted average shares and per share data have been adjusted for a three-for-two stock split effected December 2, 2005. 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,
		2009				2008				2007				2006				2005
						(in thousands, except per share data)
Balance Sheet Data:
Current assets (a)		$	175,280			$	404,311			$	261,814			$	388,925			$	207,977
Current liabilities (b)			314,104				353,514				305,433				251,685				321,760
Oil and gas properties, net			4,898,819				4,842,046				3,492,593				2,603,796				1,679,593
Total assets			5,395,881				5,551,879				4,005,293				3,183,382				2,018,985
Bank debt			324,000				693,000				303,500				452,000				269,200
Subordinated notes			1,383,833				1,097,562				847,158				596,782				346,948
Stockholders’ equity (c)			2,378,589				2,451,342				1,717,736				1,258,089				696,923
Weighted average dilutive shares outstanding			154,514				155,943				149,911				138,711				129,125
Cash dividends declared per common share			0.16				0.16				0.13				0.09				.0599
Statement of Cash Flow Data:
Net cash provided from operating activities		$	591,675			$	824,767			$	642,291			$	479,875			$	325,745
Net cash used in investing activities			(473,807	)			(1,731,777	)			(1,020,572	)			(911,659	)			(432,377	)
Net cash (used in) provided from financing activities			(117,854	)			903,745				379,917				429,416				93,000

Statement of Operations Data:

		Year Ended December 31,
		2009				2008				2007				2006				2005
						(in thousands, except per share data)
Revenues
Oil and gas sales		$	839,921			$	1,226,560			$	862,537			$	599,139			$	495,470
Transportation and gathering			486				4,577				2,290				2,422				2,306
Derivative fair value income (loss)			66,446				71,861				(9,493	)			142,395				10,303
Other			488				21,675				5,031				856				1,024
Total revenue			907,341				1,324,673				860,365				744,812				509,103
Costs and expenses
Direct operating			133,846				142,387				107,499				81,261				57,866
Production and ad valorem taxes			32,169				55,172				42,443				36,415				30,822
Exploration			46,899				67,690				45,782				44,088				29,529
Abandonment and impairment of unproved properties			113,538				47,355				11,236				4,549				623
General and administrative			116,749				92,308				69,670				49,886				33,444
Deferred compensation plan			31,073				(24,689	)			35,438				(233	)			29,474
Interest expense			117,367				99,748				77,737				55,849				37,619
Depletion, depreciation and amortization			374,432				299,831				220,578				154,482				113,741
Total costs and expenses			966,073				779,802				610,383				426,297				333,118
(Loss) income from continuing operations before income taxes			(58,732	)			544,871				249,982				318,515				175,985
Income tax (benefit) expense
Current			(636	)			4,268				320				1,912				1,071
Deferred			(4,226	)			189,563				95,987				120,726				64,809
			(4,862	)			193,831				96,307				122,638				65,880
(Loss) income from continuing operations			(53,870	)			351,040				153,675				195,877				110,105
Discontinued operations, net of taxes			—				—				63,593				(35,247	)			906
Net (loss) income		$	(53,870	)		$	351,040			$	217,268			$	160,630			$	111,011
(Loss) income per common share:
Basic—(loss) income from continuing operations		$	(0.35	)		$	2.32			$	1.07			$	1.46			$	0.89
—discontinued operations			—				—				0.44				(0.26	)			—
—net (loss) income		$	(0.35	)		$	2.32			$	1.51			$	1.20			$	0.89
Diluted—(loss) income from continuing operations		$	(0.35	)		$	2.25			$	1.02			$	1.41			$	0.85
—discontinued operations			—				—				0.43				(0.25	)			0.01
—net (loss) income		$	(0.35	)		$	2.25			$	1.45			$	1.16			$	0.86

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with Item 6, “Selected Financial Data” and our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K.

     Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. See “Disclosures Regarding Forward-Looking Statements” at the beginning of this Annual Report and “Risk Factors” in Item 1A for additional discussion of some of these factors and risks.

Overview of Our Business

     We are an independent natural gas company engaged in the exploration, development and acquisition of primarily gas properties, mostly in the Southwestern and Appalachian regions of the United States. We operate in one 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.

     Our strategy is to increase reserves and production through internally generated drilling projects coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to economically find, develop, acquire and produce oil and gas reserves. We use the successful efforts method of accounting for our oil and gas activities. Our corporate headquarters is located in Fort Worth, Texas.

Industry Environment

     We operate entirely within the United States. As traditional basins in the U.S. have matured, exploration and production has shifted to unconventional “resource” plays, typically shale reservoirs that historically were not thought to be productive for oil and gas. These plays cover large areas, provide multi-year inventories of drilling opportunities and, with modern oil and gas technology, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. These advancements make these plays more resilient to lower commodity prices while increasing the domestic supply of natural gas and, with increased supply, an expected reduction in the volatility of natural gas prices. Examples of such technological advancements include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation using almost one hundred percent sand and water, advances in well logging and analysis, horizontal drilling and completion technologies and automated remote well monitoring and control devices.

     Oil and gas are commodities. The price that we receive for the natural gas we produce is largely a function of market supply and demand in the United States. Demand for natural gas in the United States increased substantially over the past 10 years; however, the current economic slowdown has reduced this demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of natural gas can result in price volatility. Factors impacting the future supply balance are the growth in domestic gas production and the increase in the United States’ LNG import capacity. American gas supplies have increased as a result of recent expansion in domestic unconventional gas production. Existing LNG capacity may result in lower natural gas prices. Crude oil prices are generally determined by global supply and demand.

     The reduced liquidity provided by the worldwide financial markets and other factors resulted in an economic slowdown in the United States and other industrialized countries in 2008, which resulted in reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the expansion in domestic unconventional gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply has resulted in declines in natural gas prices from their highs in mid-2008. These circumstances have led to a decrease in drilling activity and reduced the demand for drilling rigs, oilfield supplies, tubulars and drill pipe. During 2009, we experienced lower overall industry costs, but these declines lagged behind the decline in prices. The duration and magnitude of the commodity price declines cannot be predicted.

     Oil and gas prices affect:

	•		the amount of cash flow available to us for capital expenditures;
	•		our ability to borrow and raise additional capital;
	•		the quantity of oil and gas that we can economically produce;
	•		revenues and profitability; and
	•		the accounting for our oil and gas activities.

     Any continued or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital.

Capital Budget for 2010

     Our capital budget for 2010 is currently set at $950.0 million, excluding acquisitions. The 2010 capital budget is more than the 2009 capital spending levels with higher expected operating cash flows resulting from higher projected oil and gas prices and higher production. For 2010, we expect our cash flow and proceeds from asset sales to fund our capital budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices, drilling success and other factors.

Source of Our Revenues

     We derive our revenues from the sale of oil and gas that is produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, quality, Btu content and transportation costs to market. Production volumes and the price of oil and gas are the primary factors affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our gas and oil production. The use of derivative instruments has in the past and may in the future, prevent us from realizing the full benefit of upward price movements but also protects us from declining price movements. Our average realized price calculations (including all derivative settlements) include both the effects of the settlement of derivative contracts that are accounted for as hedges and the settlement of derivative contracts that are not accounted for as hedges.

Principal Components of Our Cost Structure

	•		Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workovers expenses related to our oil and gas properties. These costs, on an mcfe basis, are expected to continue to moderate in 2010. Direct operating expenses also include stock-based compensation expense (non-cash) associated with grants of stock appreciation rights (SARs) and the amortization of restricted stock grants as part of employee compensation.
	•		Production and Ad Valorem Taxes. Production taxes are paid on produced oil and gas based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.
	•		Exploration Expenses. These are geological and geophysical costs, including payroll and benefits for the geological and geophysical staff, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. Exploration expense includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
	•		General and Administrative Expenses. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. General and administrative expense includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
	•		Abandonment and impairment of unproved properties. This category includes unproved property impairment and costs associated with lease expirations.
	•		Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility and with our longer-term debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.

	•		Depreciation, Depletion and Amortization. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This expense also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.
	•		Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on a basis other than federal taxable income. Currently, substantially all of our federal taxes are deferred, however, we anticipate using all of our net operating loss carryforwards and we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income. For additional information, see “Risk Factors-Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation,” in Item 1A of this report.

Management’s Discussion and Analysis of Income and Operations

Overview of 2009 Results

     During 2009, we achieved the following financial and operating results:

	•		achieved 13% production growth;
	•		achieved 18% reserve growth;
	•		drilled 285 net wells with a 99.6% success rate;
	•		continued expansion of key plays by growing production, proving up acreage and acquiring additional unproved acreage;
	•		maintained a strong balance sheet by retaining a debt to capitalization ratio of 42% and issuing $300 million of new senior subordinated notes;
	•		received proceeds of $234 million from asset sales;
	•		realized $592 million of cash flow from operating activities; and
	•		ended the year with stockholders’ equity of $2.4 billion.

     Our 2009 performance reflects another year of successfully executing our strategy of growth through drilling. During 2009, we did not make a material acquisition of proved reserves. Instead, we acquired unproved acreage, primarily in the Marcellus Shale. The business of exploring for, developing, and acquiring oil and gas is highly competitive and capital intensive. As in any commodity business, the costs associated with finding, acquiring, extracting, and financing our operations are critical to profitability and long-term value creation for stockholders. As a result of the drop in commodity prices, we have increased our efforts on improving our operating efficiency. These efforts resulted in lower direct operating expense per mcfe for 2009 when compared to 2008. However, as we continue to expand our Marcellus Shale team to meet the needs of this developing asset, we have experienced upward pressure on our general and administrative costs per mcfe. To mitigate this trend, we closed our Gulf Coast division office effective November 1, 2009 with those operations being combined and operated out of the Southwest division in Fort Worth. We successfully faced other challenges in 2009, including accessing the capital markets to fund our growth on sufficiently favorable terms, continuing to introduce new extraction technologies into the Marcellus Shale and retaining qualified operational people despite our lower capital spending program. We began the year in the midst of a worldwide economic decline and have taken several steps to improve our liquidity (see Management’s Discussion and Analysis of Financial Condition-Cash Flows and Liquidity). Our inventory of exploration and development prospects continues to provide new growth opportunities. We continue to believe that our portfolio of long-lived assets positions us for future growth.

     Total revenues decreased 32% in 2009 over the same period of 2008. This decrease was due to lower realized oil and gas prices somewhat offset by higher production. Our 2009 production growth was due to the continued success of our drilling program. Average realized prices (including all derivative settlements) were 25% lower in 2009. As discussed in Item 1A of this report, significant changes in oil and gas prices can have a material impact on our balance sheet and our results of operations, including the fair value of our derivatives.

2010 Outlook

     For 2010, the Board has approved a $950.0 million capital budget for oil and gas related activities, excluding proved property acquisitions. We expect to fund our 2010 capital budget expenditures with cash flows from operations and proceeds from asset sales. The price risk on a portion of our forecasted oil and gas production for 2010 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions. The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. We announced our plan to offer for sale our tight gas sand properties in Ohio and the data room opened in January 2010. These properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. On February 8, 2010, we announced that we had entered into a definitive agreement to sell these assets for a price of $330.0 million, subject to typical post-closing adjustments. The completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.

Oil and Gas Sales, Production and Realized Price Calculations

     Our oil and gas sales vary from year to year as a result of changes in realized commodity prices and production volumes. Hedges included in oil and gas sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in the statement of operations in derivative fair value income (loss). Oil and gas sales decreased 32% from 2008 due to a 39% decrease in realized prices, partially offset by a 13% increase in production. Oil and gas sales in 2008 increased 42% from 2007 due to a 21% increase in production and an 17% increase in realized prices. The following table illustrates the primary components of oil and gas sales for each of the last three years (in thousands):

		2009				2008				2007
Oil and Gas Sales
Oil wellhead		$	140,577			$	298,482			$	226,686
Oil hedges realized			12,184				(72,135	)			(23,755	)
Total oil revenue		$	152,761			$	226,347			$	202,931
Gas wellhead		$	432,821			$	923,160			$	585,538
Gas hedges realized			190,934				8,561				27,916
Total gas revenue		$	623,755			$	931,721			$	613,454
Total NGL revenue		$	63,405			$	68,492			$	46,152
Combined wellhead		$	636,803			$	1,290,134			$	858,376
Combined hedges			203,118				(63,574	)			4,161
Total oil and gas sales		$	839,921			$	1,226,560			$	862,537

     Our production continues to grow through drilling success as we place new wells into production and through additions from acquisitions, partially offset by the natural decline of our oil and gas wells and asset sales. For 2009, our production volumes increased 28% in the Appalachian region and 4% in the Southwestern region. Crude oil production declined from 2008 primarily due to the sale of certain oil properties in West Texas. For 2008, our production volumes increased 18% in the Appalachian region, increased 22% in our Southwestern region and increased 61% in our Gulf Coast region. For 2007, our production volumes increased 15% in the Appalachian region, increased 28% in the Southwestern region and declined 17% in our Gulf Coast region. Our production for each of the last three years is set forth in the following table:

		2009				2008				2007
Production
Crude oil (bbls)			2,556,879				3,084,529				3,359,668
NGLs (bbls)			2,186,999				1,385,701				1,114,730
Natural gas (mcf)			130,648,694				114,323,436				89,594,626
Total (mcfe) (a)			159,111,962				141,144,816				116,441,014
Average daily production
Crude oil (bbls)			7,005				8,428				9,205
NGLs (bbls)			5,992				3,786				3,054
Natural gas (mcf)			357,942				312,359				245,465
Total (mcfe) (a)			435,923				385,642				319,016

     Our average realized price (including all derivative settlements) received for oil and gas during 2009 was $6.44 per mcfe compared to $8.58 per mcfe in 2008 and $8.02 per mcfe in 2007. Our average realized price (including all derivative settlements) calculation includes all cash settlements for derivatives, whether or not they qualify for hedge accounting. Average price calculations for each of the last three years is shown below:

		2009				2008				2007
Average Prices
Average sales prices (wellhead):
Crude oil (per bbl)		$	54.98			$	96.77			$	67.47
NGLs (per bbl)			28.99				49.43				41.40
Natural gas (per mcf)			3.32				8.07				6.54
Total (per mcfe) (a)			4.00				9.14				7.37
Average realized prices (including derivatives that qualify for hedge accounting):
Crude oil (per bbl)			59.75				73.38				60.40
NGLs (per bbl)			28.99				49.43				41.40
Natural gas (per mcf)			4.77				8.15				6.85
Total (per mcfe) (a)			5.28				8.69				7.41
Average realized prices (including all derivative settlements):
Crude oil (per bbl)			62.58				68.20				60.16
NGLs (per bbl)			28.99				49.43				41.40
Natural gas (per mcf)			6.13				8.15				7.66
Total (per mcfe) (a)			6.44				8.58				8.02
Average NYMEX prices (b):
Crude oil (per bbl)			60.49				100.47				72.34
Natural gas (per mcf)			4.02				8.91				6.92