UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark one)

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

For the fiscal year-ended December 31, 2006

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

For the transition period from                    to                     

Commission file number 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
777 Main Street, Suite 800, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code
(817) 870-2601

Securities registered pursuant to Section 12(b) of the Act:

Title Of Each Class		Name Of Each Exchange On Which Registered
Common Stock, $.01 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark if the registrant as 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 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. þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerate filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer þ          Accelerated Filer o           Non-Accelerated Filer o

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o     No þ

     The aggregate market value of the voting and non-voting common equity held by non-affiliates (excluding voting shares held by officers and directors) as of June 30, 2006 was $3,681,364,000.

     As of February 20, 2007, there were 139,210,404 shares of Range Resources Corporation Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

 

 

     Portions of the registrant’s proxy statement to be furnished to stockholders in connection with its 2007 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 subsidiaries. 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” at the end of Item 15 of this report.

TABLE OF CONTENTS

PART I
Item 1.		Business			1
Item 1A.		Risk Factors			8
Item 1B.		Unresolved Staff Comments			14
Item 2.		Properties			14
Item 3.		Legal Proceedings			18
Item 4.		Submission of Matters to a Vote of Security Holders			18
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			19
Item 6.		Selected Financial Data			20
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 7A.		Quantitive and Qualitative Disclosures about Market Risk			38
Item 8.		Financial Statements and Supplementary Data			39
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			39
Item 9A.		Controls and Procedures			39
Item 9B.		Other Information			39
PART III
Item 10.		Directors, Executive Officers and Corporate Governance			40
Item 11.		Executive Compensation			42
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			42
Item 13.		Certain Relationships and Related Transactions and Director Independence			42
Item 14.		Principal Accountant Fees and Services			42
PART IV
Item 15.		Exhibits and Financial Statement Schedules			43
GLOSSARY					44
SIGNATURES					46
Third Amended and Restated Credit Agreement
Subsidiaries of Registrant
Consent of Independent Registered Public Accounting Firm
Consent of H.J. Gruy and Associates, Inc.
Consent of DeGoyler and MacNaughton
Consent of Wright and Company
Certification by the President and CEO Pursuant to Section 302
Certification by the CFO Pursuant to Section 302
Certification by the President and CEO Pursuant to Section 906
Certification by the CFO Pursuant to Section 906

RANGE RESOURCES CORPORATION
Annual Report on Form 10-K
Year Ended December 31, 2006

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 upon 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 engaged in the exploration, development and acquisition of oil and gas properties, primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase reserves and production through internally generated drilling projects, coupled with complementary acquisitions.

     At year-end 2006, our proved reserves had the following characteristics:

	•		1.8 Tcfe of proved reserves;
	•		82% natural gas;
	•		63% proved developed;
	•		80% operated;
	•		a reserve life of 16.3 years (based on fourth quarter 2006 production); and
	•		a pre-tax present value of $2.8 billion ($2.0 billion after tax).

     At year-end 2006, we owned 3,215,000 gross (2,500,000 net) acres of leasehold, which includes over 70,000 of acres associated with royalties. We have built a multi-year inventory of drilling projects which is estimated to be over 9,400 identified drilling locations.

     Range was incorporated in early 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 243%, while production has increased 81% during that same period.

     Our corporate offices are located at 777 Main Street, Suite 800, Fort Worth, Texas 76102. Our telephone number is (817) 870-2601. Effective May 1^st, 2007, our corporate offices will be located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102.

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 to achieve such growth. Our strategy requires us to make significant investments in technical staff, acreage and seismic data and technology to build drilling inventory. In implementing our strategy, we employ the following principal elements:

	•		Concentrate in Core Operating Areas. We currently operate in three 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 Anadarko Basin of Western Oklahoma), Appalachian (which includes tight-gas, shale, coal bed methane and conventional oil and gas production in Pennsylvania, Virginia, Ohio, New York and West Virginia) and Gulf Coast. 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 combine the production characteristics of each area to balance our portfolio toward our goal of consistent production and reserve growth.
	•		Maintain Multi-Year Drilling Inventory. We focus on areas where multiple prospective productive horizons and development opportunities exist. We use our technical expertise to build and maintain a multi-year drilling inventory. A large, multi-year inventory of drilling projects increases our ability to consistently grow production and reserves. Currently, we have over 9,400 identified drilling locations in inventory. In 2006, we drilled 1,017 gross (704 net) wells. In 2007, our capital program targets the drilling of 924 gross (691 net) wells.
	•		Make Complementary Acquisitions. We target complementary acquisitions in existing core areas and focus on acquisition candidates 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 $1.3 billion of complementary acquisitions. These acquisitions have been located in the Southwestern and Appalachian regions.
	•		Manage Our Risk Exposure. Allocating the majority of our capital spending to long-term development projects in areas where multiple productive horizons exist serves to reduce our risk exposure. Where our exploration projects may involve high dry hole costs, we often bring in industry partners in order to reduce financial exposure. We also invest in new seismic data and technology each year. By equipping our geologists and geophysicists with state-of-the-art seismic technology with multiple reprocessing applications, we hope to multiply the number of higher potential exploration prospects we drill without substantially adding to dry hole risk.
	•		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 in order to seize an attractive acquisition opportunity. If certain areas generate higher than anticipated returns, we may accelerate drilling in those areas and decrease capital expenditures elsewhere. We also believe in maintaining a strong balance sheet and using commodity hedging. This allows us to be more opportunistic in lower price environments as well as providing more consistent financial results.
	•		Equity Ownership and Incentive Compensation. We want our employees to act like owners. To achieve this, we reward and encourage them through equity ownership in Range. As of December 31, 2006, our employees owned equity securities (vested and unvested) which had a market value of over $170.0 million.

Significant Accomplishments in 2006

•

Production and reserve growth – The fourth quarter of 2006 marked the 16th consecutive quarter of sequential production growth. In 2006, our annual production averaged 276.1 Mmcfe per day, an increase of 15% from 2005. This achievement is the result of our continued drilling success and the completion and integration of complementary acquisitions. Our business is inherently volatile, and while consistent growth such as we have experienced over the past sixteen quarters will be challenging to sustain, the quality of our technical teams and our sizable drilling inventory bode well for the future. Proven reserves increased 25% in 2006 to 1.8 Tcfe, marking the fifth consecutive year our proven reserves have increased.

	•		Successful drilling program – In 2006, we drilled 1,017 gross wells. Competition for quality drilling and completion well services was intense in 2006, yet we were able to increase our number of wells drilled by 21% over 2005. 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 important. Production was replaced by 377% through drilling in 2006, and our overall success rate was 99%. The increased pace of drilling did not adversely impact the quality of our drilling program as the 99% success ratio in 2006 compares favorably to the 98% success ratio in 2005.
	•		Continued expansion of drilling inventory and emerging plays – To continue to grow, the size of our prospect inventory must also increase. Our drilling inventory currently includes over 9,400 projects, up from 7,700 at year-end 2005. Meaningful expansion of our coal bed methane plays and our shale plays occurred in 2006. We have now leased 276,000 net acres in our coal bed methane plays and 567,000 net acres in our shale plays. In addition to the expansion of our emerging plays, we have hired additional quality experienced technical professionals to assist us in this effort.
	•		Record financial results and balance sheet improvement – Growth in production volumes and higher oil and gas prices drove our record financial performance in 2006. Revenue, net income, and net cash flow provided from operating activities all reached record highs. The balance sheet continued to improve in 2006 as we refinanced $250 million of shorter term bank debt with a like amount of senior subordinated fixed rate 7.5% notes having a 10-year maturity. This helped to align the maturity schedule of our debt with the long-term life of our assets. Financial leverage, as measured by the debt-to-capitalization ratio improved. Future cash flow will be enhanced through lower income tax payments due to a $229.6 million net operating loss carryforward.
	•		Successful acquisition completed – In June 2006 we acquired Stroud Energy, Inc. (“Stroud”) for $171.5 million in cash and 6.5 million shares of our common stock. The transaction was structured as a merger with Stroud shareholders electing to receive either cash, Range stock, or a combination of both cash and stock. Stroud was a private Fort Worth based independent oil and gas company with operations located in the Barnett Shale play in North Texas, the Cotton Valley in East Texas and the Austin Chalk in Central Texas. We estimate the proved reserves attributable to the Stroud properties totaled 171 Bcfe. Over 90% of Stroud’s Barnett Shale acreage is located in the core or expanding core portions of the Barnett Shale play. In the first quarter of 2007, we sold the Austin Chalk properties in Central Texas for proceeds of $80.4 million.

Plans for 2007

     We have announced a $698.0 million capital budget for 2007, excluding acquisitions. The budget includes $600.0 million to drill 924 gross (691 net) wells and to undertake 72 gross (52 net) recompletions. Approximately 57% of the budget is attributable to the Southwest Division, with 37% allocated to the Appalachia Division and 6% to the Gulf Coast Division. Also included is $58.0 million for land, $20.0 million for seismic and $20.0 million for the expansion and enhancement of gathering systems and facilities. We anticipate drilling slightly fewer shallow wells in favor of deeper wells in 2007 as we seek to improve returns. Deeper wells are typically more costly than shallow wells.

Production, Revenues and Price History

     The following table sets forth information regarding oil and gas production, revenues and direct operating expenses for the last three years.

		Year Ended December 31,
		2006				2005				2004
Production
Gas (Mmcf)			75,267				63,004				50,722
Crude oil (Mbbl)			3,160				3,031				2,512
Natural gas liquids (Mbbl)			1,092				1,012				988
Total (Mmcfe) (a)			100,775				87,263				71,726
Revenues ($000)
Gas		$	497,854			$	380,131			$	225,738
Crude oil			149,370				117,354				70,439
Natural gas liquids			36,704				27,589				19,526
Transportation and gathering			2,507				2,461				2,202
Total			686,435				527,535				317,905
Direct operating expenses (b)			92,224				67,112				46,308
Production and ad valorem taxes			36,915				31,516				20,504
Gross margin		$	557,296			$	428,907			$	251,093
Average sales price (excluding hedging)
Gas (per mcf)		$	6.58			$	7.98			$	5.79
Crude oil (per bbl)			62.60				53.31				39.25
Natural gas liquids (per bbl)			33.62				31.52				23.73
Total (per mcfe) (a)			7.25				7.98				5.80
Average sales price (including hedging)
Gas (per mcf)		$	6.61			$	6.03			$	4.45
Crude oil (per bbl)			47.27				38.71				28.04
Natural gas liquids (per bbl)			33.62				27.27				19.76
Total (per mcfe) (a)			6.79				6.02				4.40
Operating costs (per mcfe)
Direct (b)		$	0.92			$	0.77			$	0.65
Production and ad valorem taxes			0.37				0.36				0.29
Total operating costs		$	1.29			$	1.13			$	0.94
Gross margin (per mcfe)		$	5.53			$	4.92			$	3.50

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 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 to 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.

Employees

     As of January 1, 2007, we had 644 full-time employees, 358 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 utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field and on-site production operation services.

Available Information

     We maintain an internet website under the name “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. 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 777 Main Street, Suite 800, Fort Worth, Texas 76102.

     We file annual reports on Form 10-K, quarterly reports on Form 10-Q and 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, N.E., 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 “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.

Marketing and Customers

     We market nearly all 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. Gas sales are made 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, gas is sold on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. Less than 500 mcf per day is sold under long-term fixed price contracts. Many contracts contain provisions for periodic price adjustment, termination and other terms customary in the industry. Gas is sold to utilities, marketing companies and industrial users. 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 or upon NYMEX pricing or fixed pricing. All oil pricing is adjusted for quality and transportation. Oil and gas purchasers are selected on the basis of price, credit quality and service. For a summary of purchasers of our oil and gas production that accounted for 10% or more of consolidated revenue, see Note 15 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 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 has 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 and Gulf Coast Divisions, our natural gas and oil production are transported primarily through third-party trucks, gathering systems and pipelines. Transportation space on these gathering systems and pipelines is occasionally limited. In Appalachia, we own approximately 4,900 miles of gas gathering pipelines which transport a majority of our Appalachian gas production as well as third-party gas to transmission lines and directly to end- users and interstate pipelines. For additional information, see “Risk Factors – Our business depends on oil and natural 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 in order 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, 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, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individuals wells.

     Certain operations that we conduct are on federal oil and gas leases which are administered by the Minerals Management Service (“MMS”). These leases contain relatively standardized terms and require compliance with detailed MMS regulations pursuant to the Outer Continental Shelf Lands Act, (“OCSLA”) (which are subject to change by the MMS). Lessees must obtain a permit from the MMS prior to the commencement of drilling, and comply with regulation governing, among other things, engineering, and construction specifications for production facilities, safety procedures, plugging and abandonment of Outer Continental Shelf, (“OCS”), wells, the valuation of production, and the removal of facilities. Under certain circumstances, the MMS may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operation. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial and we can provide no assurance that we can continue to obtain bonds or other surety in all cases.

     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 to make any such statement necessary to make the statements made 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.

     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.

Environmental Matters

     Our operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency (“EPA”) issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial 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, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent pollution from former operations such as plugging abandoned wells, and impose substantial liabilities for pollution resulting from operations. In addition, these laws, rules and

regulations may restrict the rate of production. The regulatory burden on the oil and gas industry increases the cost of doing business, affecting growth and profitability. Changes in environmental laws and regulations occur frequently, and changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our operations and financial position, as well as the industry in general. We believe we are in substantial compliance with current 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 2006, nor do we anticipate that such expenditures will be material in 2007.

     The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), known as the “Superfund” law, imposes 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 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, such persons may be subject to joint and several liability 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. Furthermore, 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 such wastes may therefore give rise to liability under CERCLA. Beyond CERCLA, state laws regulate the disposal of oil and gas wastes, and periodically new state legislative initiatives are proposed that could have a significant impact on us. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment pursuant to environmental statutes, common law or both.

     The Federal Water Pollution Control Act (“FWPCA”) imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into waters of the United States. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and Federal National Pollutant Discharge Elimination System permits applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and some other substances into coastal waters. The cost to comply with zero discharges mandated under federal and state law has not had a material adverse impact on our financial condition and results of operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing and implementing storm water pollution prevention plans.

     The Resource Conservation and Recovery Act (“RCRA”) as amended, generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the 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.

     The Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into “waters of the United States” (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have sufficient financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes.

     Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future. For instance, legislation has been proposed in Congress from time-to-time that would alter the RCRA exemption by reclassifying certain oil and gas exploration and production wastes as “hazardous wastes” and make the waste subject to more stringent handling, disposal and clean-up restrictions. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the industry in general. Compliance with environmental requirements generally could have a material adverse effect on our capital expenditures, earnings or competitive position. Although we have not experienced any material adverse effect from compliance with environmental requirements, no assurance may be given that this will continue.

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.

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

     Oil and natural gas prices are volatile, and a decline in prices would adversely affect our profitability and financial condition. The oil and natural gas industry is typically cyclical, and prices for oil and natural gas have been highly volatile. Historically, the industry has experienced severe downturns characterized by oversupply and/or weak demand. Higher oil and natural gas prices have contributed to our positive earnings over the last several years. However, long-term supply and demand for oil and natural 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;
	•		world-wide economic conditions;
	•		political conditions in oil and gas producing regions; and
	•		domestic and foreign governmental regulations.

     Decreases in oil and natural gas prices from current levels could adversely affect 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.

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 natural 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
	•		a sudden, unexpected event materially impacts oil or natural gas prices or the relationship between the hedged price index and the oil and gas sales price.

     In the fourth quarter of 2005, due to the trading volatility of NYMEX gas contracts, we experienced larger than usual differentials between actual prices paid at delivery points and NYMEX based gas hedges. Due to this event, certain of our gas hedges no longer qualify for hedge accounting and are marked to market. This may result in more volatility in our income in future periods.

Information concerning our reserves and future net reserve estimates is uncertain

     There are numerous uncertainties inherent in estimating quantities of proved oil and natural 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.

     The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment, assumptions used regarding quantities of oil and natural gas in place, recovery rates and future

prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and such variances may be material. Any variance in the assumptions could materially affect the estimated quantity and value of the reserves.

If oil and natural gas prices decrease or exploration efforts are unsuccessful, we may be required to take write-downs of our oil and natural gas properties

     In the past, we have been required to write down the carrying value of certain of our oil and natural gas properties, and there is a risk that we will be required to take additional write-downs in the future. This could occur when oil and natural 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 exploration results or mechanical problems with wells where the cost to redrill or repair does not justify the expense which might occur due to hurricanes.

     Accounting rules require that the carrying value of oil and natural 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 natural gas prices at the time of the impairment review, as well as a 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.

     For example, based primarily on the poor performance of certain properties acquired in 1997 and 1998 and significantly lower oil and natural gas prices, we recorded impairments of $215.0 million in 1998 and $29.9 million in 1999. At year-end 2001, we recorded an impairment of $31.1 million due to lower year-end prices. At year-end 2004, we recorded an impairment of $3.6 million on an offshore property due to hurricane damage and related production declines. In the third quarter of 2006, we recorded a $2.4 million impairment on an offshore property due to declining oil and gas prices.

Our business is subject to operating hazards and environmental regulations that could result in substantial losses or liabilities

     Oil and natural 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.

     As we drill to deeper horizons and in more geologically complex areas, we could experience a greater increase in operating and financial risks due to inherent higher reservoir pressures and unknown downhole risk exposures. As we continue to drill deeper, the number of rigs capable of drilling to such depths will be fewer and we may experience greater competition from other operators.

     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.

     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. Recently, we have experienced substantial increases in premiums especially in areas affected by the 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 credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities and place us at a competitive disadvantage. For example at December 31, 2006, approximately 57% of our debt is at fixed interest rates with the remaining 43% subject to variable interest rates.

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 natural 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.

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

     Due to current industry demands, well service providers and related equipment and personnel are in short supply. This is causing escalating prices, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures will likely 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.

The oil and natural gas industry is subject to extensive regulation

     The oil and natural 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 natural gas industry. Compliance with such rules and regulations often increases our cost of doing business and, in turn, decreases our profitability.

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.

     For example, in 1997, we consummated a large acquisition that proved extremely disappointing. Production from the acquired properties fell more rapidly than anticipated and further development results were below the results we had originally projected. The poor production performance of these properties resulted in material downward reserve revisions. There is no assurance that our recent and/or future acquisition activity will not result in similarly disappointing results.

     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 not able 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, none of which 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.

Our future success depends on our ability to replace reserves that we produce

     Because the rate of production from oil and natural 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 natural 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 natural 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.

A portion of our business is subject to special risks generally related to offshore operations and specifically in the Gulf of Mexico

     Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial expense and liabilities that could materially reduce the funds available for exploration, development or leasehold acquisitions or result in the loss of equipment and properties. As of February 20, 2007, we continued to have approximately 1.0 Mmcfe per day of production shut-in due to the effects of hurricanes Katrina and Rita.

     Production of reserves from reservoirs in the Gulf of Mexico generally declines more rapidly than from reservoirs in many other producing regions. This results in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years of production. As a result, reserve replacement needs from new prospects are greater and require us to incur significant capital expenditures to replace production.

New technologies may cause our current exploration and drilling methods to become obsolete

     The oil and natural 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 not able to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

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

     The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or 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. Federal and state regulation of oil and natural 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 natural gas.

     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.

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 estimated to range from $650.0 million to $825.0 million per year over the next three years, 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;
	•		the terms of our existing credit arrangements contain numerous financial and other restrictive covenants;
	•		our debt level could limit our flexibility 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.

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 or allege a violation of an existing contract. This action could delay when operations can actually commence or could cause a halt to production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, planned operations could be delayed which would impact our future operations and financial condition. Such legal disputes could also distract management and other personnel from their primary responsibilities.

Common stockholders will be diluted if additional shares are issued

     Since 1998, we have exchanged 31.9 million shares of common stock for debt and convertible securities. The exchanges were made based on the relative market value of the common stock and the debt and convertible securities at the time of the exchange. Also in 2004 and 2005, we sold 33.8 million shares of common stock to finance acquisitions. In 2006, we issued 6.5 million shares as part of the Stroud acquisition. While the exchanges have reduced interest expense, preferred dividends and future repayment obligations, the larger number of common shares outstanding had a dilutive effect on our existing stockholders. Our ability to repurchase securities for cash is limited by our bank credit facility and our senior subordinated note agreements. 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 financial statements are complex

     Due to accounting rules, 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 plan. We expect such complexity to continue and possibly increase.

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, 2004 to December 31, 2006, the last daily sale price of our common stock reported by the New York Stock Exchange ranged from a low of $6.25 per share to a high of $31.77 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 include:

	•		changes in oil and natural gas prices;
	•		variations in quarterly drilling, recompletions, acquisitions and operating results;
	•		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 certain data for our core operating areas for the year ended December 31, 2006:

		Average
		Daily												Total				Percentage
		Production				Total				Percentage				Proved				of Total
		(mcfe				Production				of Total				Reserves				Proved
Division		per day)				(mcfe)				Production				(Mmcfe)				Reserves
Southwest			150,731				55,017,031				55	%			774,933				44	%
Appalachia			103,032				37,606,463				37	%			915,054				52	%
Gulf Coast			22,334				8,151,801				8	%			68,239				4	%
			276,097				100,775,295				100	%			1,758,226				100	%

     Segment reporting is not applicable to us as 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.

Southwest Division

     The Southwest Division conducts 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 and the Anadarko Basin of western Oklahoma. In the Southwest Division, we own 2,057 net producing wells, 96% of which we operate. Our average working interest is 73%. We have approximately 687,000 gross (480,000 net) acres under lease.

     Total proved reserves increased 272.3 Bcfe, or 54%, at December 31, 2006 when compared to year-end 2005. Production was more than offset by property purchases (122.9 Bcfe) and drilling additions (208.2 Bcfe). Annual production increased 29% over 2005. During 2006, the region spent $313.1 million to drill 253.0 (212.0 net) development wells, of which 249.0 (210.2 net) were productive and 4 (1.2 net) exploratory wells, of which 2 (0.2 net) were productive. During the year, the region achieved a 99% drilling success rate.

     At December 31, 2006, the Southwest Division had a development inventory of 219 proven drilling locations and 316 proven recompletions. 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 aggressive cost control, upgrading lifting equipment, improving gathering systems and surface facilities and performing restimulations and refracturing operations.

Appalachia Division

     Our properties in this division are located in the Appalachian Basin in the northeastern United States principally in Ohio, Pennsylvania, New York, West Virginia and Virginia. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton, Queenston, Big Lime, Marcellus Shale, Niagaran Reef, Knox, Huntersville Chert, Oriskany and Trenton Black River formations at depths ranging from 2,500 to 12,500 feet. Generally, after initial flush production, most of these properties are characterized by gradual decline rates, typically producing for 10 to 35 years. We own 9,306 net producing wells, 69% of which we operate and 4,900 miles of gas gathering lines. Our average working interest is 73%. We have approximately 2.3 million gross (1.9 million net) acres under lease which includes over 70,000 acres associated with royalties.

     Reserves at December 31, 2006 increased 76.7 Bcfe, or 9%, from 2005 due to drilling additions (161.8 Bcfe) which were partially offset by a net unfavorable reserve revision and production. Annual production increased 10% over 2005. During 2006, the region spent $184.3 million to drill 739 (477.8 net) development wells, of which 737 (477.0 net) were

productive and 10 (7.0 net) exploratory wells, of which 9 (6.0 net) were productive. During the year, the region achieved approximately a 100% drilling success rate. At December 31, 2006, the Appalachia Division had an inventory of 3,300 proven drilling locations and 212 proven recompletions.

Gulf Coast Division

     The Gulf Coast properties are located onshore in Texas, Louisiana and Mississippi and in the shallow waters of the Gulf of Mexico. The division’s wells are characterized by high initial rates and relatively short reserve lives. Over the past several years, we have shifted our focus away from offshore to onshore Gulf of Mexico properties that provide greater operating control, generally lower costs and higher repeatability. Major onshore fields produce from Hartburg formations at depths of 10,000 to 11,000 feet in the Upper Texas Gulf Coast, the Upper Oligocene in South Louisiana at depths of 10,000 to 12,000 feet and the Sligo and Hosston formations at depths of 15,000 to 16,500 feet in the Oakvale field in Mississippi. We operate a majority of our onshore properties while third parties operate all of our offshore properties. Onshore, we have approximately 102,000 gross (56,000 net) acres under lease. Offshore properties include interests in 37 platforms in water depths ranging from 11 to 240 feet. We own 33 net producing wells in this division, 42% of which we operate. Our average working interest is 23%. Our Gulf Coast Division owns a license to a 3-D seismic database covering over 800 contiguous blocks in the shallow water of the Gulf of Mexico, primarily offshore Louisiana.

     Reserves increased 2.4 Bcfe, or 4%, from 2005 with production more than offset by drilling additions (9.5 Bcfe) and a favorable reserve revision. On an annual basis, production decreased 23% from 2005. During 2006, the region spent $38.0 million to drill 8 (4.6 net) development wells, of which 6 (2.6 net) were productive and 3 (1.3 net) exploratory wells, of which 1 (0.7 net) was productive. During the year, the division had a 56% drilling success rate. At December 31, 2006, the Gulf Coast Division had an inventory of 13 proven drilling locations and 59 proven recompletions.

Proved Reserves

     The following table sets forth our estimated proved reserves at the end of each of the past five years:

		December 31,
		2006				2005				2004				2003				2002
Natural gas (Mmcf)
Developed			875,395				724,876				580,006				344,187				320,224
Undeveloped			560,583				400,534				366,422				142,217				120,043
Total			1,435,978				1,125,410				946,428				486,404				440,267
Oil and NGLs (Mbbls)
Developed			37,750				33,029				27,715				24,912				17,176
Undeveloped			15,957				13,863				10,451				8,111				5,776
Total			53,707				46,892				38,166				33,023				22,952
Total (Mmcfe) (a)			1,758,226				1,406,762				1,175,425				684,541				577,977
% Developed			63	%			66	%			64	%			72	%			73	%

     Our percentage of proved developed reserves declined from 2003 to 2004 due to the proved undeveloped reserves acquired in the Great Lakes and Pine Mountain acquisitions (see Note 3 to our consolidated financial statements), adding to our future drilling inventory. From 2004 to 2005, our proved undeveloped percentage declined from 36% to 34% as we continued to aggressively drill. The Stroud acquisition in June of 2006 was primarily responsible for the decrease in the proved developed reserve percentage in 2006. The Stroud acquisition significantly increased our Barnett Shale drilling and prospect inventory.

     The following table sets forth summary information by division with respect to estimated proved reserves at December 31, 2006:

		Pre-tax Present Value (a)								Reserve Volumes
		Amount								Oil & NGL				Natural Gas				Total
		(In thousands)				%				(Mbbls)				(Mmcf)				(Mmcfe)				%
Southwest		$	1,407,302				51	%			39,859				535,770				774,933				44	%
Appalachia			1,181,045				43	%			12,183				841,958				915,054				52	%
Gulf Coast			183,095				6	%			1,665				58,250				68,239				4	%
Total		$	2,771,442				100	%			53,707				1,435,978				1,758,226				100	%

     At year-end 2006, the following independent petroleum consultants reviewed our reserves: DeGolyer and MacNaughton (Southwest and Gulf Coast), H.J. Gruy and Associates, Inc. (Southwest), and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their history in engineering certain properties. At December 31, 2006, these consultants collectively reviewed approximately 87% of our proved reserves. All estimates of oil and gas reserves are subject to uncertainty. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%.

     The following table sets forth the estimated future net revenues, excluding open hedging contracts, from proved reserves, the present value of those net revenues and the expected benchmark prices and average field prices used in projecting them over the past five years (in millions except prices):

		December 31,
		2006				2005				2004				2003				2002
Future net revenue		$	6,391			$	10,429			$	5,035			$	2,687			$	1,817
Present value
Pre-tax			2,771				4,887				2,396				1,396				965
After tax			2,002				3,384				1,749				1,003				500
Benchmark prices
Oil price (per barrel)		$	61.05			$	61.04			$	43.33			$	32.52			$	31.17
Gas price (per mcf)		$	5.64			$	10.08			$	6.18			$	6.19			$	4.75
Wellhead prices
Oil price (per barrel)		$	57.66			$	57.80			$	40.44			$	29.48			$	27.52
Gas price (per mcf)		$	5.24			$	9.83			$	6.05			$	6.03			$	4.76

     Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations, prepared in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities,” are based on costs and prices in effect at December 31 of each year. There can be no assurance that the proved reserves will be produced within the periods indicated and prices and costs will not 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. No estimates of our reserves have been filed with or included in reports to another federal authority or agency since year-end.

Producing Wells

     The following table sets forth information relating to productive wells at December 31, 2006. We also own royalty interests in an additional 1,991 wells where 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 natural gas according to their predominant production stream.

										Average
		Total Wells								Working
		Gross				Net				Interest
Crude oil			2,381				2,038				86	%
Natural gas			13,330				9,358				70	%
Total			15,711				11,396				73	%

     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

     At December 31, 2006, we owned interests in developed and undeveloped oil and gas acreage as set forth in the table below. These ownership interests generally take the form of working interests in oil and gas leases or licenses 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 our developed and undeveloped acreage held at December 31, 2006:

		Acres								Average Working
		Gross				Net				Interest
Developed			1,458,500				1,139,185				78	%
Undeveloped			1,756,406				1,360,545				77	%
Total (a)			3,214,906				2,499,730				78	%

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
2007			223,980				179,351				14	%
2008			227,172				164,179				13	%
2009			280,443				204,338				16	%
2010			107,479				88,798				7	%
2011			277,866				217,487				17	%

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.

		2006								2005								2004
		Gross				Net				Gross				Net				Gross				Net
Development wells
Productive			992.0				689.7				813.0				573.8				436.0				368.5
Dry			8.0				4.6				10.0				7.7				16.0				12.0
Exploratory wells
Productive			12.0				6.9				13.0				8.1				14.0				9.2
Dry			5.0				2.6				5.0				3.9				10.0				6.9
Total wells
Productive			1,004.0				696.6				826.0				581.9				450.0				377.7
Dry			13.0				7.2				15.0				11.6				26.0				18.9
Total			1,017.0				703.8				841.0				593.5				476.0				396.6
Success ratio			99	%			99	%			98	%			98	%			95	%			95	%

Real Property

     We lease approximately 203,700 square feet of office space, primarily in Texas and Oklahoma under standard office lease arrangements that expire at various dates through 2017. Our Appalachian Division owns a 34,500 square foot office building and various other field offices. In the first half of 2007, our Fort Worth office will be relocating to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. We believe our facilities are adequate to meet our current needs and existing space could be expanded or additional space could be leased if required. We own various vehicles and other equipment that is used in field operations. We believe such equipment is in good repair and can be readily replaced if necessary.

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 prior to 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
	•		burdens such as net profit interests.

ITEM 3. LEGAL PROCEEDINGS

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

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

     There were no matters submitted to a vote of our security holders during the fourth quarter of 2006.

PART II

ITEM 5. MARKET FOR 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 2006, trading volume averaged 1.1 million shares per day. The following table shows the quarterly high and low sale prices, cash dividends declared and volumes as reported on the NYSE composite tape for the past two years (as adjusted for a three-for-two stock split effected on December 2, 2005).

										Cash Dividends				Average Daily
		High				Low				Declared				Volumes
2005
First quarter		$	17.59			$	12.34				0.0133				1,072,650
Second quarter			18.62				13.50				0.0133				1,334,709
Third quarter			26.33				18.01				0.0133				1,203,888
Fourth quarter			28.37				20.71				0.02				1,565,650
2006
First quarter		$	30.52			$	22.52				0.02				1,343,584
Second quarter			30.29				21.74				0.02				1,202,248
Third quarter			30.37				23.38				0.02				884,865
Fourth quarter			31.77				22.80				0.03				895,294

     Between January 1, 2007 and February 20, 2007, the common stock traded at prices between $25.29 and $31.25 per share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.

Holders of Record

     On February 20, 2007, there were approximately 1,967 holders of record of our common stock.

Dividends

     In December 2006, the Board of Directors increased our quarterly dividend to $0.03 per common share. 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 2006, for the repurchase of up to $10.0 million of common stock based on market conditions and opportunities. There were no repurchases during the fourth quarter of 2006.

ITEM 6. SELECTED FINANCIAL DATA

     The following table shows selected financial information for the five years ended December 31, 2006. Significant producing property acquisitions in 2006 and 2004 affect the comparability of year-to-year financial and operating data. All weighted average shares and per share data have been adjusted for the 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 (in thousands, except per share data).

		Year Ended December 31,
		2006				2005				2004				2003				2002
Balance Sheet Data:
Current assets (a)		$	320,337			$	207,977			$	136,336			$	66,092			$	50,619
Current liabilities (b)			232,356				321,760				177,162				106,964				67,206
Oil and gas properties, net			2,676,676				1,741,182				1,402,359				723,382				564,406
Total assets			3,187,674				2,018,985				1,595,406				830,091				658,484
Bank debt			452,000				269,200				423,900				178,200				115,800
Subordinated debt			596,782				346,948				196,656				109,980				90,901
Stockholders’ equity (c)			1,256,161				696,923				566,340				274,066				206,109
Weighted average dilutive shares outstanding			138,711				129,125				97,998				86,775				81,627
Cash dividends declared per common share			0.09				.0599				.0267				.0067				—
Cash Flow Data:
Net cash provided from operating activities			479,875				325,745				209,249				124,680				114,472
Net cash used in investing activities			911,659				432,377				624,301				186,838				103,950
Net cash provided from (used in) financing activities			429,416				93,000				432,803				61,455				(12,568	)

Statement of Operations Data:

		Year Ended December 31,
		2006				2005				2004				2003				2002
Revenues
Oil and gas sales		$	683,928			$	525,074			$	315,703			$	226,402			$	190,954
Transportation and gathering			2,507				2,461				2,202				3,509				3,495
Gain (loss) on retirement of securities			—				—				(39	)			18,526				3,098
Mark-to-market on oil and gas derivatives			86,491				10,868				—				—				—
Other			6,802				(2,563	)			2,841				(2,670	)			(5,958	)
Total revenue			779,728				535,840				320,707				245,767				191,589
Costs and expenses
Direct operating			92,224				67,112				46,308				36,423				31,869
Production and ad valorem taxes			36,915				31,516				20,504				12,894				8,574
Exploration			45,252				30,604				21,243				13,946				11,525
General and administrative			49,886				33,444				20,610				17,818				16,217
Deferred compensation plan			6,873				29,474				19,176				6,559				1,023
Interest expense and dividends on trust preferred			57,577				38,797				23,119				22,165				23,153
Depletion, depreciation and amortization			167,262				127,514				99,408				86,549				76,820
Provision for impairment			2,399				—				3,563				—				—
Total costs and expenses			458,388				358,461				253,931				196,354				169,181
Income from continuing operations before income taxes and accounting change			321,340				177,379				66,776				49,413				22,408
Income tax provision (benefit)
Current			1,912				1,071				(245	)			170				(4	)
Deferred			121,814				65,297				24,790				18,319				(3,354	)
			123,726				66,368				24,545				18,489				(3,358	)
Income from continuing operations			197,614				111,011				42,231				30,924				25,766
Loss from discontinued operations			(38,912	)			—				—				—				—
Income before cumulative effect of changes in accounting principles			158,702				111,011				42,231				30,924				25,766
Cumulative effect of changes in accounting principles, net of taxes			—				—				—				4,491				—
Net income			158,702				111,011				42,231				35,415				25,766
Preferred dividends			—				—				(5,163	)			(803	)			—
Net income available to common stockholders		$	158,702			$	111,011			$	37,068			$	34,612			$	25,766
Earnings per common share:
Basic – income from continuing operations		$	1.48			$	0.89			$	0.40			$	0.37			$	0.32
– loss from discontinued operations			(0.29	)			—				—				—				—
– cumulative effect of changes in accounting principles			—				—				—				0.05				—
– Net income		$	1.19			$	0.89			$	0.40			$	0.42			$	0.32
Diluted – income from continuing operations		$	1.42			$	0.86			$	0.38			$	0.36			$	0.32
– loss from discontinued operations			(0.28	)			—				—				—				—
– cumulative effect of changes in accounting principles			—				—				—				0.05				—
– Net income		$	1.14			$	0.86			$	0.38			$	0.41			$	0.32

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 and oil company engaged in the exploration, development and acquisition of oil and gas properties, primarily in the Southwestern, Appalachian and Gulf Coast 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 find, develop and acquire oil and gas reserves that are economically recoverable. We use the successful efforts method of accounting for our oil and gas activities.

Industry Environment

     We operate entirely within the United States, a mature region for the exploration and production of oil and gas. As a mature region, while new discoveries of oil and gas occur in the United States, the size and frequency of these discoveries is declining, while finding and development costs are increasing. We believe that there remain areas of the United States, such as the Appalachian basin and certain areas in our Southwest and Gulf Coast Divisions, which are underexplored or have not been fully explored and developed with the benefit of newly available exploration, production and reserve enhancement technology. Examples of such technology include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging and analysis, horizontal drilling and completion techniques, secondary and tertiary recovery practices, and automated remote well monitoring and control devices.

     Another characteristic of a mature region is the historical exit of larger independent producers and major oil companies from such regions. These companies, searching for ever larger new discoveries, have ventured increasingly overseas and offshore, de-emphasizing their onshore United States assets. This movement out of mature basins by larger companies has provided acquisition opportunities for companies like ours that maintain well-equipped technical teams capable of generating additional value from these assets. In other situations, to increase cash flow without increasing capital spending, larger independent producers and major integrated oil companies have allowed smaller companies the opportunity to explore and develop reserves on their undeveloped acreage through joint ventures and farm-in arrangements.

     We believe the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities. Acquisition values have reached historic highs and we expect these values to remain high in 2007. In addition, we expect drilling and service costs to remain at a high level in 2007 and for lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain aging fields.

     Natural gas is a commodity. The price that we receive for the natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal condition, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. A substantial or extended decline in oil and gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and our ability to access capital markets.

Source of Our Revenues

     We derive our revenues from the sale of natural gas and oil that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our natural gas and oil production. During 2006, 2005 and 2004 the use of derivative instruments prevented us from realizing the full benefit of upward price movements and may continue to do so in future periods.

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 workovers and repairs to our oil and gas properties not covered by insurance. These costs are expected to remain high in 2007 as the demand for these services continues to increase. Direct operating expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		Production and Ad Valorem Taxes. These costs are primarily paid based on a percentage of market prices and not on hedged prices of production or at fixed rates established by federal, state or local taxing authorities.
	•		Exploration Expense. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells or dry holes. Exploration expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		General and Administrative Expense. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants and mark-to-market of SARs as part of employee compensation.
	•		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 public traded debt securities. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow. We expect our 2007 capital budget to be funded with internal cash flow and asset sales.
	•		Depreciation, Depletion and Amortization. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as platforms, 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 regular 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 another basis. Currently, all of our federal taxes are deferred; however, at some point, we will utilize 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.

Management’s Discussion and Analysis of Income and Operations

		2006				2005				2004
Production:
Crude oil (bbls)			3,159,623				3,031,468				2,512,434
NGLs (bbls)			1,091,785				1,011,692				988,192
Natural gas (mcf)			75,266,847				63,003,600				50,722,121
Total (mcfe) (a)			100,775,295				87,262,560				71,725,877
Average daily production:
Crude oil (bbls)			8,656				8,305				6,865
NGLs (bbls)			2,991				2,772				2,700
Natural gas (mcf)			206,210				172,613				138,585
Total (mcfe) (a)			276,097				239,076				195,972
Average sales prices (excluding hedging):
Crude oil (per bbl)		$	62.60			$	53.31			$	39.25
NGLs (per bbl)			33.62				31.52				23.73
Natural gas (per mcf)			6.58				7.98				5.79
Total (per mcfe) (a)			7.25				7.98				5.80
Average sales prices (including hedging):
Crude oil (per bbl)		$	47.27			$	38.71			$	28.04
NGLs (per bbl)			33.62				27.27				19.76
Natural gas (per mcf)			6.61				6.03				4.45
Total (per mcfe) (a)			6.79				6.02				4.40
Average NYMEX prices (b)
Oil (per bbl)		$	66.22			$	56.56			$	41.42
Natural gas (per mcf)			7.26				8.55				6.09

Overview of 2006 Results

     During 2006, we achieved the following results:

	•		15% production growth and 25% reserve growth;
	•		Drilled over 700 net wells;
	•		Continued expansion of drilling inventory and emerging plays;
	•		Record financial results and continued balance sheet improvement; and
	•		Completed an acquisition of properties containing 171 Bcfe of proved reserves.

     Our 2006 performance reflects another year of successfully executing our strategy of growth through drilling and complementary acquisitions. 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 the operation are critical to profitability and long-term value creation for stockholders. Generating meaningful growth while containing costs represents an ongoing challenge for management. During periods of historically high oil and gas prices, such as 2005 and 2006, drilling service and operating cost increases are more prevalent due to increased competition for goods and services. We faced other challenges in 2006 including attracting and retaining qualified personnel, consummating and integrating acquisitions, and accessing the capital markets to fund our growth and capital simplification process on sufficiently favorable terms. We have continued to expand and improve the technical staff through the hiring of additional experienced professionals. Our inventory of exploration and development prospects continues to build, providing new growth opportunities, greater diversification of technical risk and better efficiency.

     Total revenues increased 46% in 2006 over the same period of 2005. This increase is due to higher production and realized oil and gas prices. Our 2006 production growth is due to acquisitions completed in 2006 and to the continued success of our drilling program. Realized prices were higher by 13% in 2006 reflecting the expiration of lower priced oil and gas hedges. As discussed in Item 1A of this report, significant changes in oil and gas prices can have a significant impact on our balance sheet and our results of operations, particularly on the fair value of our derivatives.

Comparison of 2006 to 2005

     Oil and gas revenue for the years ended December 31, 2006 and 2005 (in thousands) is summarized in the following table:

		2006				2005				Change				%
Revenues:
Oil wellhead		$	197,815			$	161,627			$	36,188				22	%
Oil hedges			(48,445	)			(44,273	)			(4,172	)			9	%
Total oil revenue		$	149,370			$	117,354			$	32,016				27	%
Gas wellhead		$	495,920			$	502,691			$	(6,771	)			1	%
Gas hedges			1,934				(122,560	)			124,494				102	%
Total gas revenue		$	497,854			$	380,131			$	117,723				31	%
NGL		$	36,704			$	31,891			$	4,813				15	%
NGL hedges			—				(4,302	)			4,302				100	%
Total NGL revenue		$	36,704			$	27,589			$	9,115				33	%
Combined wellhead		$	730,439			$	696,209			$	34,230				5	%
Combined hedges			(46,511	)			(171,135	)			124,624				73	%
Total oil and gas revenue		$	683,928			$	525,074			$	158,854				30	%

     Average realized price received for oil and gas during 2006 was $6.79 per mcfe, up 13% or $0.77 per mcfe from 2005. Oil and gas revenues for 2006 reached a record $683.9 million and were 30% higher than 2005 due to higher realized oil and gas prices and a 15% increase in production. The average price received increased 22% to $47.27 per barrel for oil and increased 10% to $6.61 per mcf for gas from 2005. The effect of our hedging program decreased realized prices $0.46 per mcfe in 2006 versus a decrease of $1.96 in 2005.

     Production volumes increased 15% from 2005 due to continued drilling success and additions from acquisitions consummated in 2006. Production increased 13.5 Bcfe from 2005. Our production volumes increased 10% in our Appalachia Division, increased 29% in our Southwest Division and declined 22% in our Gulf Coast Division.

     Mark-to-market on oil and gas derivatives includes a gain of $86.5 million in 2006. In the fourth quarter of 2005, certain of our gas hedges no longer qualified for hedge accounting due to the effect of gas price volatility on the correlation between realized prices and hedge reference prices.

     Other revenue increased in 2006 to a gain of $6.8 million from a loss of $2.6 million in 2005. The 2006 period includes $6.0 million of ineffective hedging gains and income from equity method investments of $548,000. The 2005 period includes ineffective hedging losses of $3.4 million.

     Our operating expenses have increased as we continue to grow. We believe most of our operating expense fluctuations should be analyzed on a unit-of-production, or per mcfe basis.

     The following table presents information about our operating expenses on an mcfe basis for 2006 and 2005:

Operating expenses per mcfe		2006				2005				Change				%
Direct operating expense (excluding $0.01 per mcfe stock-based compensation in 2006)		$	0.90			$	0.76			$	0.14				18	%
Production and ad valorem tax expense			0.37				0.36				0.01				3	%
General and administrative expense (excluding stock-based compensation of $0.14 per mcfe in 2006 and $0.06 per mcfe in 2005)			0.35				0.33				0.02				6	%
Interest expense			0.57				0.44				0.13				30	%
Depletion, depreciation and amortization expense (excluding impairment)			1.66				1.46				0.20				14	%

     Direct operating expense (excluding stock-based compensation) increased $24.2 million to $90.8 million due to higher oilfield service costs, higher volumes and the integration of our recent acquisitions. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $6.7 million of expenses associated with workovers in 2006 versus $7.4 million in 2005. In 2006, 54% of our workover expenses were incurred by our Gulf Coast division and were primarily hurricane related. In 2005, 58% of our workover expenses were incurred by our Gulf Coast Division and were primarily hurricane related. On a per mcfe basis, direct operating expenses (excluding stock-based compensation) were $0.90 per mcfe and increased $0.14 per mcfe from 2005 with the increase consisting primarily of higher offshore well insurance ($0.02 per mcfe), higher utilities ($0.02 per mcfe), and higher water disposal and equipment costs ($0.06 per mcfe).

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $5.4 million, or 17%, from the same period of the prior year. On a per mcfe basis, production and ad valorem taxes increased from $0.36 per mcfe in 2005 to $0.37 per mcfe in 2006 due to higher market prices.

     General and administrative expense (excluding stock-based compensation) for 2006 increased 25%, or $7.0 million, due to higher salaries and benefits ($6.0 million) and higher office rent and general office expense ($1.0 million). On a per mcfe basis, general and administration expense (excluding stock-based compensation) increased from $0.33 per mcfe in 2005 to $0.35 per mcfe in 2006.

     Interest expense for 2006 increased $18.8 million, or 48%, to $57.6 million with higher average interest rates, higher average debt balances and the refinancing of certain debt from short-term floating to longer-term fixed rates. In 2006, we issued $250.0 million of 7.5% senior subordinated notes which added $9.7 million of interest costs. The proceeds from this issuance were used to retire shorter term bank debt. In 2006, the average debt outstanding on the bank credit facility was $347.8 million with an average interest rate of 6.4% compared to an average debt outstanding in 2005 of $314.8 million with an average interest rates of 4.5%.

     Depletion, depreciation and amortization, (“DD&A”), increased $42.1 million, or 33%, due to higher production and higher depletion rates. DD&A (excluding impairment) increased from $1.46 per mcfe in 2005 to $1.66 per mcfe in 2006. In the fourth quarter of 2006, we lowered our salvage value estimates on our Appalachia wells which increased DD&A expense by $4.6 million. In 2006, we also recorded impairment of $2.4 million on an offshore property due to declining oil and gas prices which added $0.02 per mcfe. For 2007, based on our current reserve base, we expect our DD&A rate to average approximately $1.87 per mcfe. The increase in DD&A per mcfe is related to our Stroud acquisition, increasing drilling costs and the mix of our production.

     Operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense and deferred compensation plan expense. In 2006, stock-based compensation is a component of direct operating expense ($1.4 million), exploration expense ($3.1 million), general and administrative expense ($14.3 million) and a $320,000 reduction of gas transportation revenues for a total of $19.1 million. In 2005, stock-based compensation is equal to $480,000 included in direct operating, $1.2 million included in exploration expense, $4.9 million included in general and administrative expense and a reduction of $117,000 of gas transportation revenues for a total of $6.7 million. This expense represents the amortization of restricted stock grants in 2006 and 2005, expenses related to the adoption of SFAS No. 123(R) in 2006 and in 2005, the mark-to-market of SARs granted to employees. The increase in stock-based compensation in 2006 is the result of adopting SFAS No. 123(R) which requires expensing of stock options.

     Exploration expense increased 48% to $45.3 million due to higher seismic costs ($1.6 million), higher dry hole costs ($9.1 million) and higher personnel costs. The following table details our exploration-related expenses (in thousands):

Exploration expenses		2006				2005				Change				%
Dry hole expense		$	16,103			$	7,045			$	9,058				129	%
Seismic			15,412				13,844				1,568				11	%
Personnel expense			6,917				5,872				1,045				18	%
Stock-based compensation expense			3,079				1,250				1,829				146	%
Other			3,741				2,593				1,148				44	%
Total exploration expense		$	45,252			$	30,604			$	14,648				48	%

     Deferred compensation plan expense decreased 77%, or $22.6 million from 2005. This non-cash expense relates to the increase or decrease in value of our common stock and other investments held in our deferred compensation plans. Our common stock price increased from $13.64 per share at the end of 2004 to $26.34 per share at the end of 2005 to $27.46 per share at the end of 2006.

     Income tax expense for 2006 increased $57.4 million, or 86%, over 2005 due to a 81% increase in income from continuing operations. Our effective tax rate was 39% for 2006 and was 37% for 2005. The twelve months ended December 31, 2006 includes a $2.8 million adjustment for changes in state tax rates. Given our available net operating loss carryforward, we do not expect to pay significant federal income taxes. We paid $1.8 million of state income taxes in 2006.

     Discontinued operations includes the operating results and impairment losses on the Austin Chalk properties which were acquired as part of the Stroud transaction. See also Note 4 to our consolidated financial statements. Due to significant price declines subsequent to the purchase of these properties and volumes produced since the acquisition, we recognized impairment of $74.9 million. These properties were sold on February 13, 2007 for proceeds of $80.4 million.

Comparison of 2005 to 2004

     Oil and gas revenue for the years ended December 31, 2005 and 2004 (in thousands) is summarized in the following table:

		2005				2004				Change				%
Revenues
Oil wellhead		$	161,627			$	98,608			$	63,019				64	%
Oil hedges			(44,273	)			(28,169	)			(16,104	)			57	%
Total oil revenue		$	117,354			$	70,439			$	46,915				67	%
Gas wellhead		$	502,691			$	293,769			$	208,922				71	%
Gas hedges			(122,560	)			(68,031	)			(54,529	)			80	%
Total gas revenue		$	380,131			$	225,738			$	154,393				68	%
NGL		$	31,891			$	23,446			$	8,445				36	%
NGL hedges			(4,302	)			(3,920	)			(382	)			10	%
Total NGL revenue		$	27,589			$	19,526			$	8,063				41	%
Combined wellhead		$	696,209			$	415,823			$	280,386				67	%
Combined hedges			(171,135	)			(100,120	)			(71,015	)			71	%
Total oil and gas revenue		$	525,074			$	315,703			$	209,371				66	%