UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

(Mark one)

þ      Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year-ended December 31, 2004
or

o      Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

           For the transition period from__________ to __________

Commission file number 0-9592

RANGE RESOURCES CORPORATION

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

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

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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  Noo

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes þ  Noo

     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, 2004 was $988,759,000.

     As of February 26, 2005, there were 81,435,533 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

     Portions of the registrant’s Proxy Statement to be furnished to stockholders in connection with its 2005 Annual Meeting of Stockholders are incorporated by reference in Part III of this Form 10-K.

RANGE RESOURCES CORPORATION

Annual Report on Form 10-K
Year Ended December 31, 2004

     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 7 of this report.

Table of Contents

PART I

ITEM 1. BUSINESS

General

     We are engaged in the exploration, development and acquisition of oil and gas properties, primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. We seek to increase reserves and production through internally generated drilling projects coupled with complementary acquisitions. Previously, we held our Appalachian assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C. or Great Lakes. On June 23, 2004, we purchased the 50% of Great Lakes that we did not own. In December 2004, we also purchased additional Appalachian properties through the purchase of PMOG Holdings, Inc, a private company, or Pine Mountain.

     At year-end 2004, our proved reserves had the following characteristics:

     At year-end 2004, we owned 2,428,000 gross (1,890,000 net) acres of leasehold plus over 400,000 royalty acres. We have built a multi-year inventory of drilling projects which includes over 5,000 identified drilling locations.

History

     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 three years, we have increased our proved reserves 129%, while production has increased 31% during that same time period.

Business Strategy

     Our strategy is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. In implementing our strategy, we employ the following principal elements:

2

Significant accomplishments in 2004

3

Plans for 2005

     We have announced a $254.0 million capital budget for 2005, excluding acquisitions. The budget includes $212.2 million to drill 787 gross (586 net) wells and to undertake 75 gross (53 net) recompletions. Approximately 46% of the budget is attributable to the Appalachian region, with 43% allocated to the Southwestern region and 11% to the Gulf Coast. Also included is $29.6 million for land and seismic and $12.1 million for the expansion and enhancement of gathering systems and facilities.

Acquisitions

     On December 10, 2004, we acquired additional Appalachia oil and gas properties with the purchase of Pine Mountain. The cash purchase price was $222.1 million. Approximately one half of the transaction is attributable to royalty interests. We estimate that the proved reserves assigned to the properties purchased were 205 Bcfe, 99% natural gas and only 40% developed with more than 80% of the reserves coalbed methane. The properties acquired include 417,000 acres located primarily in Virginia and West Virginia. On 373,000 mineral acres, the interest includes a royalty and a working interest. Of the 1,872 producing wells acquired, we own a royalty interest in 1,317 wells, a royalty and working interest in 516 wells and a working interest in 39 wells.

     In June 2004, we purchased the 50% of Great Lakes Energy Partners L.L.C., or Great Lakes, that we did not previously own. The cash purchase price was $228.9 million. As a result of the Great Lakes acquisition, we increased our estimated proved reserves by 255 Bcfe. These reserves are 87% natural gas, 92% operated and have a 20-year reserve life index.

Marketing and Customers

     We market nearly all of our oil and gas production from the properties we operate for both our account and the account of the other working interest owners in these properties. Gas sales are made pursuant to various contractual arrangements, including month-to-month and one to five-year contracts. Pricing on month-to-month and short term contracts is largely New York Mercantile Exchange, or NYMEX, related. For one to five-year contracts, gas is sold based on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on indexes. Less than 600 mcf per day is sold under long term fixed prices. Most contracts contain provisions for price adjustment, termination and other terms customary in the industry. Gas is sold to utilities, marketing companies and industrial users. Oil is sold under contracts ranging in terms from month-to-month or up to as long as one year. The price for oil is generally equal to a posted price set by major purchasers in the area. Oil and gas purchasers are selected on the basis of price, credit quality and service. For a list 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 15. Because alternative purchasers of oil and gas are 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”. Proximity to local markets, availability of competitive fuels and overall supply and demand are factors affecting the prices for which production can be sold. Factors outside of our control, such as international political developments, overall energy supply and demand, weather conditions, economic growth rates and other factors in the United States and elsewhere have had, and will continue to have, a significant effect on energy prices.

     We incur gathering and transportation expenses to move our natural gas from the wellhead to purchaser-specified delivery point. These expenses vary based on volume and distance shipped, and the fee charged by the third party transporters. In the Southwest and Gulf Coast regions, our natural gas and oil are transported primarily through third party 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 Appalachia 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 this Item 1.

4

Production, Revenues and Price History

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

Competition

     We encounter substantial competition in 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.

5

Governmental Regulation

     Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future cost or impact of compliance.

Environmental Matters

     Our operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency (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 expenditures in connection with environmental remediation matters in 2004, nor do we anticipate that such expenditures will be material in 2005.

     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 exempt from 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 become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of oil and gas wastes are pending in certain states and these initiatives 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 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 the federal National Pollutant Discharge Elimination System general 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 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 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 solid hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies.

6

     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 statues.

     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.

Risk Factors and Cautionary Statement for Purposes of the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995

     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: 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.

     With the previous paragraph in mind, you should consider the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf:

Risk Factors

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

     Oil and natural gas prices are volatile, and 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 can be 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 $56 per barrel and natural gas prices reaching $10 per mcf in some markets. These record oil and natural gas prices have contributed to our positive earnings over the last 18-24 months. 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

7

a material adverse effect on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we may be unable to replace production.

Hedging transactions may limit our potential gains and involve other risks

     To manage our exposure to price risk, we enter into hedging arrangements from time to time with respect to a 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, 2004, we were party to hedging arrangements covering 19.7 Bcf and 0.6 million barrels of oil and 0.2 million barrels of NGLs. We also had collars covering 37.8 Bcf of gas and 2.8 million barrels of oil. The hedges’ fair value was a pre-tax loss of $71.9 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:

Information concerning our reserves and future net reserve estimates is uncertain

     There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. Estimates of proved 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 expenditures 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, judgment, assumptions used regarding quantities of oil and natural gas in place, recovery rates and future prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and such variances may be material. Any variance in the assumptions could materially affect the estimated quantity and value of the reserves.

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

     In the past, we have been required to write down the carrying value of 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 or deterioration in our exploration results.

     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 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 development results, production data, economics and other factors. While an impairment charge which reflects our long term ability to recover on a prior investment does not impact cash or cash flow from operating activities, it reduces our earnings and increases our leverage ratios.

8

     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 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.

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

     Oil and natural gas operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipelines 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:

     Our current and former 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. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could have a material adverse affect on our financial condition and results of operations.

We are subject to financing and interest rate exposure risks

     Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities and place us at a competitive disadvantage. For example, approximately 40% of our debt is at fixed interest rates with the remaining 60% subject to variable interest rates.

Some of our current and potential competitors have greater resources than we have and we may not be able to successfully compete in acquiring, exploring and developing new properties

     We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods, services and employees needed to operate and manage our business and marketing oil and natural gas. Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial and other resources than we do.

The oil and natural gas industry is subject to extensive regulation

     The oil and natural gas industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and regulations binding on participants in the oil and natural gas industry. Compliance with such rules and regulations often increases our cost of doing business and, in turn, decreases our profitability.

9

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business

     We could be subject to significant liabilities related to our acquisitions. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. However, even a detailed review of all properties and records may not reveal existing or potential problems, 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 which 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. We cannot assure you that our recent and/or future acquisition activity will not result in similar 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 strategy of completing acquisitions 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. Possible future acquisitions could result in our incurring additional debt, contingent liabilities, expenses, and diversion of resources, all of which could have a material adverse effect on our financial condition and operating results.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel

     Our success is highly dependent on our senior management personnel, none of which are currently subject to an employment contract. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

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

     Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

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

     Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in 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 of the world. 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 expenditure to replace production.

10

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

     The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are not able to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

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

     The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. 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.

Our significant indebtedness could limit our ability to successfully operate our business

     We are leveraged and our exploration and development program will require substantial capital resources, estimated to range from $250 to $300 million per year over the next three years. The operation of 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.

Any failure to meet our debt obligations could harm our business, financial condition and results of operation

     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.

Common stockholders will be diluted if additional shares are issued

     Since 1998, we have exchanged 21.3 million shares of common stock for $146.7 million of 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. During 2001, $17.4 million of debt and convertible securities was exchanged for common stock. During 2002, $10.4

11

million of debt and convertible securities were exchanged for common stock. During 2003, $880,000 of debt was exchanged for common stock. In 2004, we exchanged our 5.9% convertible preferred stock for 5.9 million shares of common stock. Also in two transactions during 2004, we sold 17.9 million shares of common stock for total proceeds of $246.1 million which were used, in part, to finance our two large acquisitions during the year. While the exchanges have reduced interest expense, 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 senior credit facility and the 7-3/8% senior subordinated notes agreement. We continue to review alternatives to further strengthen our balance sheet by reducing debt. 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 outstanding shares.

Dividend limitations

     Limits on the payment of dividends and other restricted payments, as defined, are imposed under our senior credit facility and under our 7-3/8% senior subordinated notes. These limitations may, in certain circumstances, limit or prevent the payment dividends independent of our dividend policy.

Our financial statements are complex

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

The price of our common stock may fluctuate significantly, which may result in losses for investors.

     The market price of our common stock has been volatile. From January 1, 2003 to December 31, 2004, the last daily sale price of our common stock reported by the New York Stock Exchange ranged from a low of $5.05 per share to a high of $21.51 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.

Available Information

     We maintain an internet website under the name “www.rangeresources.com.” We make available, free of charge, on our website, the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, our Corporate Governance principles, the charters of the Audit Committee, the Compensation Committee, the Dividend Committee, the Executive Committee, and the Governance and Nomination Committee, and the Code of Business Conduct and Ethics are also available on the 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, quarterly 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.”

Employees

     As of January 1, 2005, we had 504 full-time employees, 303 of whom were field personnel. None are covered by a collective bargaining agreement. Management believes its relationship with employees is good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of field production services such as pumping, maintenance, inspection and testing, permitting and environmental assessment.

12

ITEM 2. PROPERTIES

     The table below summarizes certain data for our core operating areas for the year ended December 31, 2004:

Southwestern division

     The Southwestern division conducts drilling, production and field operations in the Permian Basin of West Texas and the East Texas Basin as well as in the Texas Panhandle and the Anadarko Basin of western Oklahoma. In the Southwestern division, we own interests in 1,600 net producing wells, 95% of which we operate. We have approximately 317,000 net acres under lease. Our average working interest is 73%.

     In December 2003, we completed an $87.9 million producing property acquisition which added more than 500 operated wells and established ourselves as the largest operator in the Conger Field in Sterling County of West Texas. In addition, in April 2004, we purchased a private company owning oil and gas properties in the Permian Basin for $23.1 million with reserves of approximately 22 Bcfe. The related production is 75% oil and 52% of the reserves were proved developed. In total, production has increased in the Southwestern division over 40% from 2002.

     Reserves increased 13.9 Bcfe at December 31, 2004, as compared to year end 2003, a 4% increase due to purchases and drilling additions. On an annual basis, production increased 30% over 2003. During 2004, the region spent $96.4 million to drill 147 (122.0 net) development wells, of which 137 (113.4 net) were productive and 8 (6.6 net) exploratory wells, of which 3 (2.1 net) were productive. During the year, the region achieved a 90% drilling success rate.

     At December 31, 2004, the Southwestern division had a development inventory of 183 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.

Appalachian division

     Our property base in this division is located in the Appalachian Basin, and to a minor extent, the Michigan Basin of the northeastern United States. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton, Knox, Oriskany and Trenton Black River formations at depths ranging from 2,500 to 7,000 feet. After initial flush production, these properties are characterized by gradual decline rates, typically producing for 10 to 35 years. We own interests in approximately 8,400 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 1.8 million gross (1.5 million net) acres under lease.

     In June 2004, we added to our Appalachian properties with the purchase of the 50% of Great Lakes that we did not own for $228.9 million which included estimated proved reserves of 255 Bcfe. In December 2004, we added properties with the Pine Mountain acquisition for $221.9 million. The properties include 417,000 acres located primarily in Virginia and West Virginia. This acquisition added estimated proved reserves of 205 Bcfe. Approximately half of the value is attributable to royalty interests. The reserves are 99% natural gas and are 40% developed. More than 80% of the Pine Mountain reserves are coalbed methane.

     Reserves at December 31, 2004 increased 484.7 Bcfe, or 185% from 2003 due to the acquisitions mentioned above and from drilling additions. On an annual basis, production increased 56% from 2003. During 2004, the region spent $53.6 million to drill 297 (255.4 net) development wells, of which 294 (253.3 net) were productive and 9 (7.7 net) exploratory wells, of which 8 (6.7 net) were productive. During the year, the region achieved a 99% drilling success rate. At December 31, 2004, Great Lakes had an inventory of 2,682 proven drilling locations and 52 proven recompletions.

13

Gulf Coast division

     Our Gulf Coast properties are located onshore in Texas, Louisiana and Mississippi and in the shallow waters of the Gulf of Mexico. The division’s wells are characterized by high initial rates and relatively short reserve lives. Over the past several years, we have shifted our focus away from offshore to onshore Gulf of Mexico properties that provide greater operating control, generally lower costs and higher repeatability. Major onshore fields produce from Hartburg formations at depths of 10,000 to 11,000 feet in the Upper Texas Gulf Coast 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 our offshore properties. Onshore, we have approximately 55,000 net acres under lease. Offshore properties include interests in 37 platforms in water depths ranging from 11 to 240 feet. Our offshore leasehold inventory includes 42,000 net acres. We own interests in 44 net producing wells, in this division, 44% of which we operate. Our average working interest is 30%. 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 7.7 Bcfe, or 10%, from 2003 due to production partially offset by drilling additions from drilling. On an annual basis, production decreased 14% from 2003. During 2004, the region spent $34.0 million to drill 8 (3.0 net) development wells, of which 5 (1.8 net) were productive and 7 (1.9 net) exploratory wells, of which 3 (0.5 net) were productive. During the year, the division had a 53% drilling success rate. At December 31, 2004, the Gulf Coast division had an inventory of 8 proven drilling locations and 40 proven recompletions.

Proved Reserves

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

     Our percentage of proved developed reserves declined in 2004 due to the significant proved undeveloped reserves acquired in the Great Lakes and Pine Mountain acquisitions 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%. We do not disclose potential reserves classified as probable or possible associated with our acquisitions.

14

     The following table sets forth summary information by division with respect to estimated proved reserves at December 31, 2004:

     At year-end 2004, 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, 2004, these consultants collectively reviewed approximately 88% 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 revenues and the expected benchmark 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 production taxes and operating expenses). Such calculations, prepared in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” are based on costs and prices in effect at December 31 of each year. Weighted average product prices at December 31, 2004 were $40.44 per barrel of oil, $25.05 per barrel for natural gas liquids, and $6.05 per mcf of gas using benchmark spot prices of $43.33 per barrel and $6.18 per Mmbtu. There can be no assurance that the proved reserves will be produced within the periods indicated and prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties. No estimates of our reserves have been filed with or included in reports to another federal authority or agency since year-end.

Producing Wells

     The following table sets forth information relating to productive wells at December 31, 2004. We also own royalty interests in an additional 1,690 wells. Wells are classified as oil or gas according to their predominant production stream.

15

     The day-to-day operations of oil and gas properties are the responsibility of the operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Acreage

     At December 31, 2004, 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. 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, 2004:

Drilling Results

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

Real Property

     We lease approximately 60,000 square feet of office space primarily in Texas and Oklahoma under standard office lease arrangements that expire at various dates through April 2008. Our Appalachian division owns a 25,000 square foot of office building in one location and other for its 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 are used in field operations. We believe such equipment is in good repair and can be readily replaced if necessary.

16

Title to Properties

     We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often little investigation of record title is made at the time of 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:

17

ITEM 3. LEGAL PROCEEDINGS

     We are involved in various legal actions and claims arising in the ordinary course of business, which include a royalty owner suit filed in 2000 asking for class action certification against us and Great Lakes. In the opinion of management, such litigation and claims are likely to be resolved without a material adverse effect on our financial position or results of operations. See also Note 8 to our consolidated financial statements.

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

     No matters were submitted to a vote of security holders during the fourth quarter of 2004.

18

PART II

     ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     (a) Our common stock is listed on the New York Stock Exchange, or the NYSE, under the symbol “RRC.” During 2004, trading volume averaged 478,745 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.

     Between January 1, 2005 and February 26, 2005, the common stock traded at prices between $18.51 and $25.84 per share. Our 7.375% Notes are not listed on an exchange, but trade over-the-counter.

19

Holders of Record

     At February 26, 2005, there were approximately 2,044 holders of record of our common stock.

Dividends

     The payment of dividends is subject to declaration by our board of directors and depends on earnings, capital expenditures and various other factors. The senior credit facility and the 7.375% senior subordinated notes allow for the payment of common and preferred dividends, with certain limitations. In December 2003, we announced we would begin paying cash dividends on our common stock, initially at a quarterly dividend rate of one cent per share. In December 2004, the quarterly common stock dividend was increased to two cents per share.

Equity Compensation Plans

     The following table summarizes securities issuable and authorized by the stockholders under certain equity compensation plans ^(a):

EQUITY COMPENSATION PLAN INFORMATION

20

ITEM 6. SELECTED FINANCIAL DATA

     The following table shows selected financial information for the five years ended December 31, 2004. Significant producing property acquisitions in 2003 and 2004 affect the comparability of year-to-year financial and operating data. See Item 1, “Acquisitions.” This information should be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operation,” (in thousands, except per share data).

Statement of Operations Data:

21

22

     The following tables set forth unaudited financial information on a quarterly basis for each of the last two years (in thousands, except per share data):

     The total of quarterly earnings per share does not necessarily equal the earnings per share for the year, because our convertible securities have not been dilutive in every quarter. (See Item 7 of this report, “Management’s Discussion and Analysis ”).

23

     The total of quarterly earnings per share does not necessarily equal the earnings per share for the year, because our convertible securities have not been dilutive in every quarter (See Item 7 of this report, “Management’s Discussion and Analysis ”).

24

     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 our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K.

     Statements in our discussion may be forward-looking statements. 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 Item 1 of this report, “Risk Factors,” for additional discussion of some of these factors and risks.

Overview

     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 operations areas has similar economics 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.”

     We seek 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.

     During 2004, we achieved the following results:

25

Critical Accounting Policies and Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally adopted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and related footnote disclosures. Application of certain of our accounting policies, including those related to oil and gas revenues, bad debts, the fair value of derivatives, oil and gas properties, asset retirement obligations, marketable securities, income taxes and contingencies and litigation require significant estimates. We base our estimates on historical experience and various assumptions that are believed reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies reflect our more significant judgments and estimates used in the preparation of our financial statements.

Property, Plant and Equipment

     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 revision, 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 senior 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 senior credit facility. To further ensure the reliability of reserve estimates, we engage independent petroleum consultants to review the estimates of proved reserves.

     The following table sets forth a summary of the reserves which were reviewed by independent petroleum consultants for each of the years ended 2004, 2003 and 2002.

     We utilize the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved oil and gas reserves as estimated by our engineers. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

     We adhere to statement of Financial Accounting Standards No. 19 (“SFAS 19”) for recognizing any impairment of capitalized costs to unproved properties. The greatest portion of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and periodically evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. We consider a combination of time, geologic and engineering factors to evaluate the need for impairment of these costs. Unproved properties had a net book value of $14.8 million, $12.2 million and $19.0 million in 2004, 2003 and 2002, respectively.

     Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the costs capitalized. Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to oil and gas producing activities and reserve quantities disclosure in Note 18, “Unaudited Supplemental Reserve Information” to our consolidated financial statements. Changes in the estimated reserves are considered in estimates for accounting purposes and are reflected on a prospective basis.

26

     We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property’s carrying value for impairment. We cannot predict whether impairment charges may be required in the future. We had an impairment of $3.6 million in 2004 on an offshore property.

Derivatives

     We use commodity derivative contracts to manage our exposure to oil and gas price volatility. We account for our commodity derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). Earnings are affected by the ineffective portion of a hedge contract (changes in realized prices that do not match the changes in the hedge price). Ineffective gains or losses are recorded in other revenue while the hedge contract is open and may increase or reverse until settlement of the contract. This may result in significant volatility to current period income. For derivatives qualifying as hedges, the effective portion of any changes in fair value is recognized in stockholders’ equity as other comprehensive income, or OCI, and then reclassified to earnings, in oil and gas revenue, when the transaction is consummated. This may result in significant volatility in stockholders’ equity. The fair value of open hedging contracts is an estimated amount that could be realized upon termination.

     The commodity derivatives we use include commodity collars and swaps. While there is a risk that the financial benefit or rising prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are: more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets. We also have some interest rate swap agreements to protect against the volatility of variable interest rates under our senior credit facility.

Asset Retirement Obligations

     We have significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as well as regulatory, political, environmental, safety and public relations considerations.

     Asset retirement obligations are not unique to us or to the oil and gas industry and in 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”). We adopted this statement effective January 1, 2003, as discussed in Note 4, “Asset Retirement Obligations,” to our consolidated financial statements. SFAS 143 significantly changed the method of accruing for costs that an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, the statement requires us to record a separate liability for the fair value of our asset retirement obligations, with an offsetting increase to the related oil and gas properties on our consolidated balance sheet.

     Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in our consolidated statement of operations.

     SFAS 143 required a cumulative adjustment to reflect the impact of implementing the statement had the rule been in effect since inception. We calculated the cumulative accretion expense on the ARO liability and the cumulative depletion expense on the corresponding property balance. The sum of this cumulative expense was compared to the depletion expense originally recorded. Because the historically recorded depletion expense was higher than the cumulative expense calculated under SFAS 143, the difference resulted in a $4.5 million gain, net of tax, which we recorded as cumulative effect of change in accounting principle on January 1, 2003.

27

Deferred Taxes

     We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed many months after the close of a calendar year; (b) tax returns are subject to audit which can take years to complete; and (c) future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryovers and other deductible differences. We routinely evaluate all deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

     In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income (loss) has not yet been earned. At year-end 2003, deferred tax assets exceeded deferred tax liabilities by $9.0 million with $24.6 million of deferred tax assets related to unrealized deferred hedging losses included in OCI. At year-end 2004, deferred tax liabilities exceeded deferred tax assets by $91.4 million with $26.0 million of deferred tax assets related to unrealized deferred hedging losses included in OCI. Based on our projected profitability and because if prices remain constant, the unrealized hedging losses should be offset in the future by higher realization on our production, no year-end 2004 valuation allowance was deemed necessary.

     We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions on our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

     A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

Bad Debt Expense

     We periodically assess the recoverability of all material trade and other receivables to determine their collectability. At Independent Producer Finance, or IPF, receivables are evaluated quarterly and provisions for uncollectible amounts are established. Such provisions for uncollectible amounts are recorded when management believes that a related receivable is not recoverable based on current estimates of expected discounted cash flows and other factors which could affect the collection.

Revenues

     We recognize revenues from the sale of products and services in the period delivered. We use the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. Revenues are sensitive to changes in prices received for our products. A substantial portion of production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. Changes in the supply and demand for oil and natural gas can have dramatic effects on prices. Political instability and availability of alternative fuels could impact worldwide supply, while economic factors can impact demand. At IPF, payments believed to relate to return are recognized as income. Currently, all IPF receipts are being recognized as a return of capital.

Other

     We record a write down of marketable securities when the decline in market value is considered to be other than temporary. Third party reimbursements for administrative overhead costs incurred due to our role as operator of oil and gas properties are applied to reduce general and administrative expense. Salaries and other employment costs of those employees working on our exploration efforts are expensed as exploration expense. We do not capitalize general and administrative expense or interest expense.

Recent Accounting Pronouncements

     On December 16, 2004, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 123 (revised 2004), Share-Based Payment which is a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation. Statement 123(R) supercedes APB opinion No. 25, Accounting for Stock Issued to employees, and amends FASB Statement No. 95, Statement of Cash Flows. Generally, the approach in Statement 123(R) is similar to the approach described in Statement 123. However, Statement 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative. The provisions of this statement become effective for our third quarter 2005. Management has not determined the impact that this statement will have on our consolidated financial statements.

     In December 2004, the Financial Accounting Standards Board  issued a FASB Staff Position (FSP) that provides accounting guidance on how companies should account for the effects of the American Jobs Creation Act of 2004 that was signed into law on October 22, 2004. FSP FAS 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004,” states that the manufacturers’ deduction provided for under this legislation should be accounted for as a special deduction instead of a tax rate change. The FSP may affect how a company accounts for deferred income taxes. The FSP is effective December 31, 2004. We are currently evaluating the impact from the FSP on our results of operations and financial position and we expect to complete our evaluation during the first half of fiscal 2005.

28

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

     During 2004, we spent $832.9 million on acquisitions, development and exploration. Acquisition expenditures were primarily comprised of $310.7 million for the 50% of Great Lakes we did not own and $297.8 million for the Pine Mountain acquisition. See footnote 16 to our consolidated financial statements. At December 31, 2004, we had $18.4 million in cash, including $17.3 million of cash proceeds held in escrow to be used to purchase similar assets and $1.6 billion of total assets. Total capitalization was $1.2 billion, of which 48% was represented by stockholder equity and 52% by debt. At December 31, 2004, we had a working capital deficit of $40.8 million which included an unrealized hedging liability of $61.0 million due to the mark-to-market of all open hedges. Because payments on this hedging liability are made monthly and we will also collect production proceeds to which this hedging relates, the amount should be self-funding.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the capital intensive extractive 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 senior 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, 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 5.75 million shares of common stock under this shelf registration statement for an aggregate price of $107.8 million. As of December 31, 2004, we have $392.2 million of capacity remaining under the shelf.

     The following summarizes our contractual financial obligations at December 31, 2004 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities and refinancing proceeds.