Range Resources - 10-K annual report

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     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

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

     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, 2005 was $2,276,192,000.

     As of February 20, 2006, there were 130,661,982 shares of Range Resources Corporation Common Stock outstanding.

     Portions of the registrant’s proxy statement to be furnished to stockholders in connection with its 2006 Annual Meeting of Stockholders are incorporated by reference in Part III, Items 10-14 of this report.

     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.

     Certain information included in this report, other materials filed or to be filed with the Securities and Exchange Commission or 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.

     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 2005, our proved reserves had the following characteristics:

     At year-end 2005, we owned 2,843,000 gross (2,381,000 net) acres of leasehold, plus over 400,000 royalty acres. We have built a multi-year inventory of drilling projects which includes over 7,700 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 four years, we have increased our proved reserves 143%, while production has increased 59% 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.

     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. Such a strategy requires us to make significant investments in technical staff, acreage and seismic to build drilling inventory. In implementing our strategy, we employ the following principal elements:

     We have announced a $428.9 million capital budget for 2006, excluding acquisitions. The budget includes $358.4 million to drill 1,065 gross (789 net) wells and to undertake 94 gross (58 net) recompletions. Approximately 46% of the budget is attributable to the Appalachia Division, with 46% allocated to the Southwest Division and 8% to the Gulf Coast Division. Also included is $37.6 million for land, $18.5 million for seismic and $14.5 million for the expansion and enhancement of gathering systems and facilities.

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

     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 the financial or personnel resources of Range 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.

     As of January 1, 2006, we had 578 full-time employees, 330 of whom were field personnel. All employees are eligible to receive equity awards approved by the Compensation Committee of the Board of Directors. None is covered by a collective bargaining agreement. Management believes its relationship with employees is good. We regularly utilize independent consultants and contractors to perform various services, particularly in the areas of drilling, completion and field production services such as pumping, maintenance, inspection and testing, permitting and environmental assessment.

     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 also 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 450 Fifth Street, N.W., 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 web site 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.

     We market nearly all of our oil and gas production from the properties we operate for both our interest and that of the royalty owners and other working interest owners. Gas sales are made pursuant to a variety of contractual arrangements, including month-to-month and one-to five-year contracts. Pricing on the month-to-month and short-term contracts is based largely on the New York Mercantile Exchange, or 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 indexes. Less than 300 mcf per day is sold under long-term fixed price contracts. Most 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 term 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, 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 the information set forth in the notes to our consolidated financial statements under the caption “Major Customers” in Note 14. 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, please see the information set forth in Item 7 of this report “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. Increasing market volatility due to international political developments, overall energy supply and demand, weather conditions, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.

     We incur gathering and transportation expenses to move our natural gas and crude oil from the wellhead and tanks to purchaser specified delivery points. These expenses vary based on volume, distance shipped and the fee charged by the third-party transporters. In the Southwestern 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 4,800 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. See “Risk Factors – Our business depends on oil and natural gas transportation facilities, some of which are owned by others,” in Item 1A of this report.

     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, or the MMS. These leases contain relatively standardized terms and require compliance with detailed MMS regulations pursuant to the Outer Continental Shelf Lands Act, or the 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, or 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, or the EPAct 2005. Among other matters, the EPAct 2005 amends the Natural Gas Act, or 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, or 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 will 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.

     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 or the 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 2005, nor do we anticipate that such expenditures will be material in 2006.

     The Comprehensive Environmental Response, Compensation and Liability Act, or 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, or 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, or 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 U.S. Oil Pollution Act, or 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 at least $35 million in 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.

     Oil and natural gas prices are volatile, and an extended 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. For example, in 1998 and early 1999, oil and natural gas prices declined, which contributed to the substantial losses we reported in those years. By early 2001, oil and natural gas prices reached levels above historical norms. Prices declined in the second half of 2001 but have risen steadily since mid-2002. Recent oil and natural gas prices are at historic highs, with oil prices recently reaching $70.85 per barrel and natural gas prices reaching $15.78 per mcf in some markets. 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 including technology, geopolitics, weather patterns and economics.

     Many factors affect oil and natural gas prices including general economic conditions, consumer preferences, discretionary spending levels, interest rates and the availability of capital to the industry. Decreases in oil and natural gas prices from current levels could adversely affect our revenues, net income, cash flow and proved reserves. Significant and prolonged 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 will be unable to replace production.

     To manage our exposure to price risk, we enter into hedging arrangements 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. For example, at December 31, 2005, we were party to swap hedging arrangements covering 6.7 Bcf and 0.1 million barrels of oil. We also had collars covering 82.8 Bcf of gas and 4.8 million barrels of oil. The derivatives’ fair value was a pre-tax loss of $231.0 million. If oil and natural gas prices continue to rise, we could be subject to margin calls.

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

     Recently, due to the trading volatility of NYMEX gas contracts, we have 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 qualified for hedge accounting in the fourth quarter and were marked-to-market. This may result in more volatility in our income in future periods.

     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 undeveloped reserves, which comprise a significant portion of our 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.

     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. As of December 31, 2005, we continued to have production shut-in due to the effects of hurricanes Katrina and Rita primarily to pipelines and onshore facilities. While we do not currently believe there is any material long-term damage to the shut-in properties, we cannot yet predict whether impairment charges may be required due to these storms.

     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:

     As we begin drilling 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. Currently, we expect

substantial increases in premiums especially in the areas affected by the hurricanes and tropical storms. In addition, we expect insurers to impose 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.

     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, approximately 56% of our debt is at fixed interest rates with the remaining 44% subject to variable interest rates.

     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.

     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 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.

     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 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.

     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.

     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 of February 20, 2006, we continued to have 1.6 Mmcfe per day of production shut-in due to the effects of hurricanes Katrina and Rita. 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.

     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.

     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.

     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.

     We are leveraged and our exploration and development program will require substantial capital resources estimated to range from $450 to $550 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:

     Despite our current levels of indebtedness we still may be able to incur substantially more debt. This could further increase the risks described above.

     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.

     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.

     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. 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, the 7.375% and the 6.375% 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.

     Limits on the payment of dividends and other restricted payments, as defined, are imposed under our bank credit facility and under our 7.375% and 6.375% senior subordinated note agreements. These limitations may, in certain circumstances, limit or prevent the payment of dividends independent of our dividend policy.

     Due to accounting rules, our financial statements continue to be complex, particularly with reference to hedging, asset retirement obligations, equity awards and the accounting for our deferred compensation plan. We expect such complexity to continue and possibly increase.

     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, 2005, the last daily sale price of our common stock reported by the New York Stock Exchange ranged from a low of $6.29 per share to a high of $28.01 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:

     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.

     Not applicable.

     The table below summarizes certain data for our core operating areas for the year ended December 31, 2005:

     The Southwest Division conducts drilling, production and field operations in 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 interests in 1,835 net producing wells, 92% of which we operate. Our average working interest is 74%. We have approximately 550,000 gross (384,000 net) acres under lease.

     Reserves increased 144.4 Bcfe, or 40%, at December 31, 2005, as compared to year-end 2004. Production was more than offset by property purchases (76 Bcfe), drilling additions (87 Bcfe) and a net favorable reserve revision. Annual production increased 14% over 2004. During 2005, the region spent $158.3 million to drill 198 (161.7 net) development wells, of which 191 (155.9 net) were productive and 1 (1 net) exploratory well which was not productive. During the year, the region achieved a 96% drilling success rate.

     At December 31, 2005, the Southwest Division had a development inventory of 228 proven drilling locations and 200 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.

     Our property base in this division is located in the Appalachian basin in the northeastern United States principally in Ohio, Pennsylvania, New York, West Virginia and Virginia and to a minor extent, the Michigan basin. 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, these properties are characterized by gradual decline rates, typically producing for 10 to 35 years. We own interests in approximately 8,822 net producing wells, 74% of which we operate and 4,800 miles of gas gathering lines. Our average working interest is 74%. We have approximately 2.1 million gross (1.9 million net) acres under lease.

     Reserves at December 31, 2005 increased 92.0 Bcfe, or 12%, from 2004 due to drilling additions (123.8 Bcfe) which were partially offset by a net unfavorable reserve revision and production of 34.2 Bcfe. On an annual basis, production increased 69% from 2004 due to our acquisitions in 2004 (See also Note 4 to our consolidated financial statements). During 2005, the region spent $122.6 million to drill 622 (418.7 net) development wells, of which 619 (416.7 net) were productive and 12 (9.3 net) exploratory wells, of which 10 (7.7 net) were productive. During the year, the region achieved a 99% drilling success rate. At December 31, 2005, the Appalachia Division had an inventory of 3,114 proven drilling locations and 182 proven recompletions.

     The Gulf Coast properties are located onshore in south Texas, south 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 to the Upper Oligocene in South Louisiana at depths of 10,000 to 12,000 feet to 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 34,000 gross (17,000 net) acres under lease. Offshore properties include interests in 37 platforms in water depths ranging from 11 to 240 feet. We own interests in 30 net producing wells in this division, 39% of which we operate. Our average working interest is 22%. Our Gulf Coast Division also owns a license of a 3-D seismic database covering over 800 contiguous blocks in the shallow water of the Gulf of Mexico, primarily offshore Louisiana.

     Reserves declined 5.1 Bcfe, or 7.2%, from 2004 with production partially offset by drilling additions (6.9 Bcfe). On an annual basis, production decreased 26% from 2004. During 2005, the region spent $31.2 million to drill 3 (1.1 net) development wells, of which 3 (1.1 net) were productive and 5 (1.7 net) exploratory wells, of which 3 (0.4 net) were productive. During the year, the division had a 55% drilling success rate. At December 31, 2005, the Gulf Coast Division had an inventory of 12 proven drilling locations and 37 proven recompletions.

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

     Our percentage of proved developed reserves declined from 2003 to 2004 due to the significant proved undeveloped reserves acquired in the Great Lakes and Pine Mountain acquisitions (see Note 4 to our consolidated financial statements), adding to our future drilling inventory. The Great Lakes acquisition moved our percentage of proved undeveloped reserves from 27% to 32% and the Pine Mountain acquisition increased that percentage to 37%. At year-end 2005, our proved undeveloped percentage declined from 37% to 34% as we continue to aggressively drill.

     The following table sets forth summary information by division with respect to estimated proved reserves at December 31, 2005:

     At year-end 2005, 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, 2005, these consultants collectively reviewed approximately 84% of the 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 6%.

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

     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.

     The following table sets forth information relating to productive wells at December 31, 2005. We also own royalty interests in an additional 1,656 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.

     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.

     At December 31, 2005, 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, 2005:

     The table below summarizes by year and area our undeveloped acreage scheduled to expire in the next five years.

     We engage in drilling activities on properties presently owned by us and intend to drill or develop other properties we may lease or acquire in the future. 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.

     We lease approximately 68,500 square feet of office space primarily in Texas and Oklahoma under standard office lease arrangements that expire at various dates through April 2010. Our Appalachian Division owns a 34,500 square foot office building and various other field offices. 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.

     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 little 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:

     We have been named as a defendant in a number of legal actions arising in the ordinary course of our business. In the opinion of management, such litigation and claims are likely to be resolved without a material adverse effect on our financial position, cash flows or results of operations. See also Note 9 to our consolidated financial statements.

     There were no matters submitted to a vote of our security holders during the fourth quarter of 2005.

     Our common stock is listed on the New York Stock Exchange, or the NYSE, under the symbol “RRC.” During 2005, trading volume averaged 1.3 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).

     Between January 1, 2006 and February 20, 2006, the common stock traded at prices between $23.21 and $30.52 per share. The 7.375% senior subordinated notes and the 6.375% senior subordinated notes are not listed on an exchange, but trade over-the-counter.

     On February 20, 2006, there were approximately 1,940 holders of record of our common stock.

     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, the 7.375% senior subordinated notes and the 6.375% 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.”

     The following table shows selected financial information for the five years ended December 31, 2005. Significant producing property acquisitions in 2003 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 (in thousands, except per share data).

     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.

     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 as each of our operating areas has similar economic characteristics and each meets the criteria for aggregation as defined in Statement of Financial Accounting Standards No. 131, “Disclosure About Segments of an Enterprise and Related Information.”

     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.

     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 exit of larger independent producers and the 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 continue to climb in 2006. In addition, we expect drilling and service costs to increase in 2006 and for lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain aging fields.

     We derive our revenues from the sale of natural gas and oil that is produced from our natural gas and oil 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 2005, 2004 and 2003, 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.

     During 2005, we achieved the following results:

     Our 2005 performance reflects the benefits of higher oil and gas production, higher oil and gas prices and continued focus upon our cost structure. 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, drilling service and operating cost increases are more prevalent due to increased competition for goods and services. We faced other challenges in 2005 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.

     Revenues increased 67% in 2005 over the same period of 2004. This increase is due to higher production and realized oil and gas prices. Our 2005 production growth is due to acquisitions completed in 2004 and to the continued success of our drilling program. Realized prices were higher by 37% in 2005 reflecting higher market prices and the expiration of lower priced oil and gas hedges. Since December 31, 2005, oil and gas prices have remained volatile, particularly the price of natural gas. On February 17, 2006, the NYMEX spot price for natural gas closed at $7.18 per Mmbtu which is significantly below the market price at the end of the year. 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.

     Net income increased $68.8 million, with higher average oil and gas prices and volumes as primary factors contributing to this increase. Increased revenues were partially offset by higher operating costs and higher DD&A.

     Average realized price received for oil and gas during 2005 was $6.02 per mcfe, up 37% or $1.62 per mcfe from 2004. Oil and gas revenues for 2005 reached a record $525.1 million and were 66% higher than 2004 due to higher oil and gas prices and a 22% increase in production. The average price received increased 38% to $38.71 per barrel for oil and increased 36% to $6.03 per mcf for gas from 2004. The effect of our hedging program decreased realized prices $1.96 per mcfe in 2005 versus a decrease of $1.40 in 2004.

     Production volume increased 22% from 2004 due to our drilling program and additions from acquisitions consummated in 2004, primarily our purchase of the 50% of Great Lakes that we did not own and Pine Mountain. Production increased 15.5 Bcfe from 2004. Our production volumes increased 69% in our Appalachia Division, increased 14% in our Southwest Division and declined 26% in our Gulf Coast Division.

     Transportation and gathering revenue of $2.6 million increased $376,000 from 2004. This increase is primarily due to higher gas prices and additional throughput volumes offset by lower oil marketing revenue.

     Mark-to-market on oil and gas derivatives includes a gain of $10.9 million in 2005. In the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the effect of recent volatility of gas prices on the correlation between realized prices and hedge reference prices.

     Other revenue declined in 2005 to a loss of $2.6 million from a gain of $2.8 million in 2004. The 2005 period includes ineffective hedging losses due to widening basis differentials of $3.4 million offset by net IPF income of $514,000. The 2004 period includes a gain on the sale of properties of $5.0 million and $712,000 of ineffective hedging gains offset by $2.0 million write-down of an insurance claim receivable. Other revenue for 2004 also includes net IPF expenses of $1.8 million.

     Direct operating expense increased $20.3 million to $66.6 million due to increased costs from acquisitions, higher oilfield service costs and higher workover costs primarily in our Gulf Coast Division. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $7.4 million of expenses associated with workovers in 2005 versus $1.8 million in 2004. 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 were $0.76 per mcfe and increased $0.11 per mcfe from 2004 consisting of higher field level costs of $0.04 and higher workover costs of $0.07.

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $11.0 million, or 54%, from the same period of the prior year. On a per mcfe basis, production and ad valorem taxes increased from $0.29 per mcfe to $0.36 per mcfe due to higher market prices.

     Exploration expense increased 39% to $29.4 million due to higher seismic costs ($10.5 million) and higher personnel costs, partially offset by lower dry hole costs ($5.0 million). Exploration expense includes exploration personnel costs of $6.0 million in 2005 versus $4.4 million in 2004.

     General and administrative expense for 2005 increased 43%, or $8.8 million, from 2004 with additional personnel costs due to the Great Lakes and Pine Mountain acquisitions ($1.8 million), higher salaries and benefits ($3.5 million), higher legal expenses ($1.3 million) and a $725,000 legal settlement accrual (See also Note 9 to our consolidated financial statements). On a per mcfe basis, general and administration expense increased from $0.29 per mcfe in 2004 to $0.34 per mcfe in 2005.

     Non-cash stock compensation increased 84%, or $16.1 million, from 2004. This non-cash expense relates to the increase 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. The twelve months ended December 31, 2005 also includes $5.8 million mark-to-market expense for stock appreciation rights issued in 2005.

     Interest expense for 2005 increased $15.7 million, or 68%, to $38.8 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 March 2005, we issued $150.0 million of 6.375% senior subordinated notes which added $7.8 million of interest costs. The proceeds from this issuance were used to retire lower interest bank debt. Average debt outstanding on the bank credit facility was $314.8 million and $296.6 million for 2005 and 2004, respectively, and the average interest rates were 4.3% and 3.5%, respectively.

     Depletion, depreciation and amortization, or DD&A, increased $24.5 million, or 24%, due to higher production and higher depletion rates. DD&A increased from $1.39 per mcfe in 2004 to $1.46 per mcfe in 2005. The twelve months ended December 31, 2004 includes a $3.6 million impairment charge on an offshore property in our Gulf Coast Division. For 2006, based on our current reserve base, we expect our DD&A rate to average approximately $1.55 per mcfe.

     Tax expense for 2005 increased $41.8 million, or 170%, over 2004 due to a 166% increase in income before taxes. Our effective tax rate for 2005 and 2004 was 37%. Given our available net operating loss carryforward, we do not expect to pay significant federal income taxes; however, we do expect to pay $1.1 million of state income taxes.

     The following table presents information about our operating expenses per mcfe for 2005 and 2004.

     Net income increased $6.8 million, with higher average oil and gas prices and volumes as a primary factor contributing to this increase. Increased revenues were partially offset by higher operating costs and higher DD&A. The year ended 2003 included an $18.5 million gain on retirement of debt and convertible securities versus a loss of $39,000 in 2004. The year ended 2003 also included a $4.5 million favorable cumulative effect of change in accounting principle.

     Average realized price received for oil and gas during 2004 was $4.40 per mcfe, up 13%, or $0.50 per mcfe, from 2003. Oil and gas revenues for 2004 reached $315.7 million and were 39% higher than 2003 due to higher oil and gas prices and a 24% increase in production. The average price received increased 19% to $28.04 per barrel for oil and increased 13% to $4.45 per mcf for gas from 2003. The effect of our hedging program decreased realized prices $1.40 per mcfe in 2004 versus a decrease of $1.04 in 2003.

     Production volume increased 24% from 2003 due to our drilling program and additions from acquisitions consummated in late 2003 and 2004, primarily the Conger Field acquisition in 2003 and our purchase of the 50% of Great Lakes that we did not own in 2004. Production increased 13.7 Bcfe from 2003. Our production volumes increased 56% in our Appalachian Division, increased 30% in our Southwestern Division and declined 14% in our Gulf Coast Division.

     Transportation and gathering revenue of $2.2 million declined $1.3 million from 2003. This decline is due to lower oil marketing revenues and additional gas transportation system employee expense related to the Conger Field acquisition ($1.1 million) partially offset by additional revenue related to the Great Lakes acquisition.

     Gain (loss) on retirement of securities was a loss of $39,000 in 2004 versus a gain of $19.0 million in 2003. The year ended 2004 includes the purchase for cash of $2.7 million of 6% debentures. During 2003, 193,500 shares of common stock were exchanged for $880,000 of 6% debentures with a conversion expense of $465,000 recorded on the exchange. In addition, 2003 included $9.1 million of 6% debentures, $500,000 of 8.75% Notes, and $5.3 million of Trust Preferred Securities were repurchased for cash. Also in 2003, $10.2 million of cash and $50.0 million of our newly issued convertible preferred stock was exchanged for $79.5 million of Trust Preferred Securities.

     Other revenue increased in 2004 to $2.8 million from a loss of $2.7 million in 2003. The 2004 period includes a gain on the sale of properties of $5.0 million and $712,000 of ineffective hedging gains offset by $2.0 million write-down of an insurance claim receivable. Other revenue for 2004 also includes net IPF expenses of $1.8 million. Other revenue in 2003 includes an ineffective hedging loss of $1.2 million and net IPF expenses of $1.4 million.

     Direct operating expense increased $9.9 million to $46.3 million due to increased costs from acquisitions and higher oilfield service costs. Our operating expenses are increasing as we add new wells and maintain production from our existing properties. We incurred $1.8 million of expenses associated with workovers in 2004 versus $2.7 million in 2003. On a per mcfe basis, direct operating expenses increased $0.02 per mcfe with higher field level costs offset by lower workover costs.

     Production and ad valorem taxes are paid based on market prices and not hedged prices. These taxes increased $7.6 million, or 59%, from the same period of the prior year. On a per mcfe basis, production and ad valorem taxes increased from $0.22 per mcfe to $0.29 per mcfe due to higher market prices.

     Exploration expense increased 52% to $21.2 million due to higher dry hole costs ($8.5 million) and higher personnel costs partially offset by lower seismic purchases ($2.6 million). Exploration expense includes exploration personnel costs of $4.4 million in 2004 versus $3.3 million in 2003.

     General and administrative expense for 2004 increased 16%, or $2.8 million, from 2003 due primarily to higher professional fees and additional personnel costs due to the Great Lakes acquisition. On a per mcfe basis, general and administrative expense declined from $0.31 per mcfe in 2003 to $0.29 per mcfe in 2004.

     Non-cash stock compensation increased $12.6 million from 2003. This non-cash expense relates to the increase in value of our common stock and other investments held in our deferred compensation plans. Our common stock price increased from $6.30 per share at the end of 2003 to $13.64 per share at the end of 2004.

     Interest expense for 2004 increased $1.0 million, or 4%, to $23.1 million with higher interest rates and average debt balance partially offset by a lower call premiums of $1.8 million. Interest expense for 2003 included a $2.0 million call premium on the 8.75% Notes. Average debt outstanding on the bank credit facility was $262.4 million and $104.7 million for 2004 and 2003, respectively and the average interest rates were 3.3% and 3.1%, respectively.

     Depletion, depreciation and amortization, or DD&A, increased $16.4 million, or 19%, to $103.0 million due to higher production and a $3.6 million (or $0.05 per mcfe) impairment charge on an offshore property in our Gulf Coast division. The impairment was attributable to hurricane damage and related production declines. On a per mcfe basis, excluding the impairment charge on the offshore property, DD&A declined from $1.49 per mcfe to $1.39 per mcfe. For 2005, based on our current reserve base, we expect our DD&A rate to average $1.45 per mcfe.

     Tax expense for 2004 increased $6.1 million, or 33%, over 2003 due to a 35% increase in income before taxes. Year-end 2004 and 2003 provide for a tax rate of 37%. Given our available net operating loss carryforward, we do not expect to pay significant cash federal income taxes.

     The following table presents information about our operating expenses for each of the years in the two-year period ended December 31, 2004.

     During 2005, our cash provided from operations was $325.7 million, and we spent $441.8 million on capital expenditures (including acquisitions). During this period, financing activities provided net cash of $93.0 million. Our financing activity included the sale in March 2005 of $150.0 million of 6.375% Notes that enabled us to better match the maturities of our debt with the life of our properties and decrease our interest rate volatility. In addition, in June 2005 we issued 6.9 million common shares in a public offering for net proceeds of $109.2 million. At December 31, 2005 we had $4.7 million in cash, total assets of $2.0 billion and a debt-to-capitalization ratio of 47%. Long-term debt at December 31, 2005 totaled $616.1 million, including $269.2 million of bank debt and $346.9 million of senior subordinated notes. Available borrowing capacity under the bank credit facility at December 31, 2005 was $330.8 million.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves which is typical in the oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We believe that net cash generated from operating activities and unused committed borrowing capacity under the bank credit facility combined with our oil and gas price hedges currently in place will be adequate to satisfy near term financial obligations and liquidity needs. However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proved reserves.

     In 2004, we filed a new universal shelf registration statement with the SEC registering $500.0 million aggregate amount of common stock, preferred stock and other equity and debt securities. In December 2004, we issued 8.6 million shares of common stock under this shelf registration statement for an aggregate price of $107.8 million. In June 2005, we issued 6.9 million shares of common stock under this shelf registration for an aggregate price of $113.9 million. As of December 31, 2005, we have $278.3 million of capacity remaining under the shelf. Range qualifies as a Well-Known Seasoned Issuer.

     We maintain a $600.0 million revolving credit facility, which we refer to as our bank debt or our bank credit facility. The bank credit facility is secured by substantially all of our assets and matures on January 1, 2009. Availability under the bank credit facility is subject to a borrowing base set by the banks semi-annually and more often in certain other circumstances. The borrowing base is dependent on a number of factors, primarily the lenders’ assessment of future cash flows. Redeterminations of the borrowing base require approval of 75% of the lenders; increases require unanimous approval. At February 20, 2006, the bank credit facility had a $600.0 million borrowing base of which $310.7 million was available.

     Limitations on the payment of dividends and other restricted payments as defined are imposed under our bank debt, the 7.375% Notes and the 6.375% Notes. Under the bank credit facility, common and preferred dividends are permitted. The terms of both the 7.375% Notes and the 6.375% Notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings and equity issuances since the original issuances of the notes. At December 31, 2005, approximately $432.9 million was available under the restricted payment baskets for both the 6.375% Notes and the 7.375% Notes. The bank credit facility provides for a restricted payment basket of $20.0 million plus 66-2/3% of net cash proceeds from common stock issuances and 50% of net income. Approximately $365.8 million was available under the bank credit facility restricted payment basket as of December 31, 2005. The debt agreements contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2005.

     Our principal sources of cash are operating cash flow, bank borrowings and at times, issuance of debt and equity securities. Our operating cash flow is highly dependent on oil and gas prices. As of December 31, 2005, we had entered into hedging agreements covering 61.2 Bcfe, 43.7 Bcfe and 14.3 Bcfe for 2006, 2007 and 2008, respectively. The $288.2 million

of cash capital expenditures for 2005, excluding acquisitions, was funded with internal cash flow. The $429.0 million capital budget for 2006, which excludes acquisitions, is expected to increase production and to expand the reserve base. Based on current projections, oil and gas futures prices and our hedge position, the 2006 capital program is expected to be funded with internal cash flow.

     Net cash provided from operating activities in 2005, 2004 and 2003 was $325.7 million, $209.2 million and $124.7 million, respectively. In 2005, cash flow from operations increased due to higher production volumes and prices partially offset by increasing operating, exploration and interest expenses. In 2004, cash flow from operations increased due to higher volumes and prices partially offset by increasing operating and exploration expenses. In 2003, cash flow from operations increased with higher volumes and higher prices partially offset by increasing operating and exploration expenses.

     Net cash used in investing activities in 2005, 2004 and 2003 was $432.4 million, $624.3 million and $186.8 million, respectively. In 2005, we spent $276.9 million in additions to oil and gas properties and $153.6 million on acquisitions. The 2004 period included $166.6 million in additions to oil and gas properties and $485.6 million of acquisitions. The 2003 period included $91.2 million in additions to oil and gas properties, and $103.9 million of acquisitions, partially offset by $10.3 million of IPF net repayments.

     Net cash provided from financing activities in 2005, 2004 and 2003 was $93.0 million, $432.8 million and $61.5 million, respectively. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings. During 2005, we received proceeds of $150.0 million and $109.2 million from the issuance of our 6.375% Notes and a common stock offering. During 2005, the outstanding balance under our bank credit facility declined $154.7 million primarily due to the proceeds received from the 6.375% Notes being applied to our bank debt. During 2004, we received proceeds of $98.1 million and $246.1 million from the issuance of additional 7.375% Notes and two common stock offerings, respectively. During 2004, the outstanding balance under our bank credit facility increased $245.7 million with $70.0 million related to the Great Lakes transaction and the remaining increase the result of funding other acquisitions. Also in 2004, we redeemed the remaining outstanding 6% Debentures for $11.6 million. During 2003, the outstanding balance under our bank credit facility increased $62.4 million primarily due to the December acquisition of producing properties in the Conger field. In 2003, total debt declined $9.9 million. During 2003, we redeemed $84.8 million of the Trust Preferred Securities and $69.3 million of the 8.75% Notes and issued $100.0 million of 7.375% Notes.

     Our primary needs for cash are for exploration, development and acquisition of oil and gas properties, repayment of principal and interest on outstanding debt and payment of dividends. During 2005, $288.2 million of capital was expended primarily on drilling projects. Also in 2005, $153.6 million was expended on acquisitions primarily to purchase producing properties. The capital program, excluding acquisitions, was funded by net cash flow from operations and our acquisitions were funded primarily with proceeds received from our common stock offering. The 2006 capital budget of $429.0 million, excluding acquisitions, is expected to be funded by cash flow from operations. Development and exploration activities are highly discretionary, and, for the foreseeable future, we expect such activities to be maintained at levels equal to or below internal cash flow. To the extent capital requirements exceed internal cash flow, debt or equity may be issued to fund these requirements. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a drop in oil and gas prices or a reduction in production or reserves could adversely affect our ability to fund capital expenditures and meet our financial obligations. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

     The amount of future dividends is subject to declaration by the board of directors and depends on earnings, capital expenditures and various other factors, such as restrictions under our bank debt and the 7.375% Notes and the 6.375% Notes. In 2005, we paid $7.6 million in dividends to our common stockholders ($0.02 per share in the fourth quarter and $0.0133 per share in the third, second and first quarter). In 2004, we paid $3.2 million in dividends to our common stockholders ($0.0067 per share in the second and third quarter and $0.0133 per share in the fourth quarter). In 2005, 2004 and 2003, we paid $2.2 million, $2.9 million and $803,000 in preferred stock dividends. As of December 31, 2004, our 5.9% convertible preferred stock was converted to common stock.

     In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of December 31, 2005, we do not have any capital leases nor

have we entered into any material long-term contracts for drilling rigs or equipment. As of December 31, 2005, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2005. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2005 reflects accrued interest payable on our bank debt of $652,000 which is payable in January 2006. We expect to make annual interest payments of $14.8 million per year on our $200.0 million of 7.375% Notes and payments of $9.6 million per year on our $150.0 million of 6.375% Notes.

     The following summarizes our contractual financial obligations at December 31, 2005 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities and refinancing proceeds.

     We enter into hedging agreements to reduce the impact of oil and gas price volatility on our operations. At December 31, 2005, swaps were in place covering 6.7 Bcf of gas at prices averaging $6.60 per mcf and 0.1 million barrels of oil at prices averaging $35.00 per barrel. We also had collars covering 82.8 Bcf of gas at weighted average floor and cap prices of $6.77 to $9.43 and 4.8 million barrels of oil at weighted average floor and cap prices of $45.21 to $56.58. The hedges’ fair value, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a pretax loss of $231.0 million at December 31, 2005. The contracts expire monthly through December 2008. Transaction gains and losses are determined monthly and are included as increases or decreases on oil and gas revenue in the period the hedged production is sold. Realized hedging losses of $171.1 million $100.1 million and $60.4 million were realized in 2005, 2004 and 2003, respectively. Changes in the value of the ineffective portion of all open hedges are recognized in earnings quarterly in other income. Unrealized effective gains and losses on hedging positions are recorded at an estimate of fair value based on a comparison of the contract price and a reference price, generally NYMEX, on our consolidated balance sheet as other comprehensive income, or OCI, a component of stockholders’ equity. As of the fourth quarter of 2005, certain of our gas hedges no longer qualify for hedge accounting due to the effect of recent volatility of gas prices on the correlation between realized prices and hedge reference prices and were marked-to-market in the amount of a gain of $10.9 million.

     At December 31, 2005, the following commodity derivative contracts were outstanding:

     At December 31, 2005, we had $616.1 million of debt outstanding. Of this amount, $350.0 million bears interest at a fixed rate averaging 7.0%. Bank debt totaling $269.2 million bears interest at floating rates, which averaged 5.4% at year-end 2005, excluding interest rate swaps. At December 31, 2005, we had fixed rate interest rate swap agreements on notional debt of $35.0 million. These swaps consist of two agreements at 1.8% which expire in June 2006. The 90-day LIBOR rate on December 31, 2005 was 4.5%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2005 would cost us approximately $2.3 million in additional annual interest, net of swaps.

     We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital resource position, or for any other purpose.

     Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In 2005 and 2004, we experienced an overall increase in drilling and service costs compared to 2003, especially with regard to steel products. We expect further increases in these costs for 2006.

     The following table indicates the average oil and gas prices received over the last five years and quarterly for 2005, 2004 and 2003. Average price calculations exclude hedging gains and losses. Oil is converted to natural gas equivalent at the rate of one barrel equals six mcfe.

     Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. Actual results could differ from the estimates and assumptions used.

     Certain accounting estimates are considered to be critical if a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and b) the impact of the estimates and assumptions on financial condition or operating performance is material.

     Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Vice President of Reservoir Engineering who reports directly to our Chief Operating Officer. In addition, because substantially all of our proved reserves are pledged as collateral for our bank credit facility, our estimates of proved reserves are reviewed twice annually by independent engineers on behalf of each of the sixteen banks participating in our bank credit facility. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to review our estimates of proved reserves.

     The following table sets forth a summary of the percent of reserves which were reviewed by independent petroleum consultants for each of the years ended 2005, 2004 and 2003.