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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark one)

Commission File Number 0-9592

RANGE RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)

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

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

Common Stock, $.01 par value
(Title of class)

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 x    No

      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. ( )

      The aggregate market value of voting stock of the registrant held by non-affiliates (excluding voting shares held by officers and directors) was $281,790,768 on March 1, 2001.

      Indicate the number of shares outstanding of each of the registrant’s classes of stock on March 1, 2001: Common Stock $.01 par value: 50,489,906; Preferred Stock $1 par value: 8,235.

DOCUMENTS INCORPORATED BY REFERENCE:
Part III of this report incorporates by reference the Proxy Statement relating
to the Registrant’s 2001 Annual Meeting of Stockholders.

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RANGE RESOURCES CORPORATION

Annual Report on Form 10-K
Year Ended December 31, 2000

PART I

ITEM 1. BUSINESS

General

      Range Resources Corporation (“Range”) is engaged in the acquisition and development of oil and gas properties, primarily in the Southwest, Gulf Coast and Appalachian regions of the United States. The Company pursues development drilling and exploitation projects, acquisitions and, to a lesser extent, exploration of its extensive acreage position. All Appalachian assets are held through a 50% interest in a joint venture, Great Lakes Energy Partners L.L.C. (“Great Lakes”). Independent Producer Finance (“IPF”), a wholly owned subsidiary, provides financing to small oil and gas producers through the purchase of overriding royalty interests. Both Great Lakes and IPF are independently financed and IPF’s and Range’s proportionate share of Great Lakes’ assets and operations are consolidated in the Company’s financial statements. At December 31, 2000, the Company had 583.7 Bcfe of proved reserves, having a pre-tax present value of $2.0 billion based on constant prices of $26.80 per barrel and $9.77 per Mcf. The pre-tax present value based on average projected futures prices as if they would have been in effect on December 31, 2000 of $22.00 per barrel and $4.45 per Mcf would have been $814.3 million. The Company’s proved reserves are 73% natural gas by volume, 70% developed and 83% operated. At year-end, the Company’s properties had a reserve life index of 10.5 years. In addition, the Company owned 488,000 gross (219,000 net) acres of undeveloped leasehold.

History

      Between 1988 and 1997, the Company actively pursued small acquisitions and the further development of its properties. The Company was consistently profitable and steadily increased its production and reserves. Between late 1997 and mid-1998, a series of large acquisitions were consummated which proved extremely disappointing. Production from the acquired properties fell more rapidly than anticipated and further development of the principal fields proved far less attractive than expected. In combination with a steep decline in energy prices which began in late 1997 and the substantial burden imposed by debt and fixed income securities taken on in connection with the purchases, the adverse impact on the Company’s operating results, balance sheet and stock price was severe.

      In 1998 and 1999, sharp reductions in staff and capital budgets, sales of properties and the formation of Great Lakes allowed the Company to materially reduce debt and stabilize its financial position. However, production and reserves fell as a result of these actions. In the Great Lakes transaction, the single most significant step in the debt reduction effort, Range and FirstEnergy Corp. (“FirstEnergy”) contributed their Appalachian oil and gas properties and associated gas pipeline systems to a joint venture, forming one of the largest production companies in the region. To achieve equal ownership despite Range’s contribution of a disproportionate share of the proved reserves, the venture assumed $188.3 million of Range’s bank debt and FirstEnergy contributed $2.0 million of cash.

      Faced with high leverage and significant concern from its banks, the Company moved aggressively to hedge its production as the oil and gas markets began to recover in late 1999. These hedges, which covered roughly 80% of the Company’s anticipated production through the third quarter of 2000, were designed to assure financial viability while the restructuring was completed. Given the continuing sharp rise in oil and gas prices throughout 2000, these hedges substantially limited the benefits to the Company of the price increases. While the Company has continued to hedge on a rolling twelve to eighteen month basis since that time, the rise in prices has permitted a substantial increase in the average price at which production is hedged, particularly since September 30, 2000. At year end 2000, the

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Company had hedges in place on approximately 33.7 Bcfe of gas and 1 million barrels of oil at average prices of $4.07 per Mcf and $28.62 per barrel. These hedges cover approximately 64% and 7% of the Company’s anticipated production on an Mcfe basis for 2001 and 2002, respectively.

      In 2000, with the benefit of rising oil and gas prices, the Company began to gradually increase capital expenditures while keeping spending well below internal cash flow to allow the continued pay down of debt. Through these repayments and exchanges of common stock for fixed income securities, debt was again substantially reduced. Despite capital constraints, the Company managed to modestly increase production in the course of the year primarily by bringing proved non-producing reserves on stream. While production rose during the year, it fell 17% from the prior year level primarily due to the impact of the Great Lakes transaction in late 1999. By mid-year, the progress made in restructuring began to be recognized and the market for the Company’s stock started to rebound. However, due to the lower capital expenditures the Company was unable to replace production and proved reserves fell 5.4% during the year.

      In 2001, the Company expects to increase its capital budget by 46% to roughly $85 million. This should generate a continued increase in production and, through the increase in spending and a greater emphasis on developing unproved reserves, may permit reserve growth to resume. Finally, the benefits of sharply higher energy prices and reduced fixed charges should allow substantial profitability and a continuing reduction of debt. By year-end 2001, management believes leverage will have been reduced to a fully manageable level and that the Company will be well positioned to again pursue profitable long-term growth.

Description of the Business

      Strategy

      Between 1988 and 1997, assets grew from $7 million to $764 million as stockholders’ equity increased from less than $1 million to $197 million. In 1998 and 1999, the Company incurred almost $200 million of losses from continuing disappointing results on a series of large acquisitions consummated between late 1997 and mid-1998 which led to a series of impairments. These losses materially reduced stockholders’ equity and increased leverage ratios. The significant improvement in oil and gas prices since mid-1999 combined with the benefits of reduced costs allowed the Company to return to profitability in 2000. In 2001, the Company’s goal is to continue to reduce debt while increasing capital expenditures. The 2001 capital budget should provide modest production growth and may permit a resumption of reserve growth.

      At year end, the Company had over 2,100 proven development projects in inventory. Given current oil and gas prices and this development inventory, the Company believes it can achieve growth in reserves, production, cash flow and earnings over the next several years while further reducing debt. The Company currently anticipates spending $85 million on capital expenditures in 2001. The Company’s approximately 488,000 gross (219,000 net) acre undeveloped leasehold position provides significant long-term exploration and development potential.

      Development. Development projects include recompletions of existing wells, infill drilling and the installation of secondary recovery projects. Such projects are pursued within core areas where the Company has significant operational and technical experience. At December 31, 2000, 1,812 proven drilling locations and 318 proven recompletions were in inventory. In 2001, 236 development wells and 73 recompletions are planned.

      Exploration. Onshore exploration projects cover 264,810 gross (102,098 net) acres. These projects target deeper horizons in existing fields as well as prospective fields in trend areas. Offshore exploration focuses on the shallow waters of the Gulf of Mexico where 3D seismic data covering 3.5 million contiguous acres is held. Range has offshore leases covering 145,889 gross (37,012 net) acres on which it has to date identified nine specific projects. The Company’s exploration strategy is based on limiting risk by allocating no more than 10% to 15% of the capital budget to such projects. At times, other companies pay all

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or a disproportionate share of exploration costs to earn an interest in a project. The Company currently anticipates participating in up to 30 exploratory wells in 2001.

      Acquisitions. After a two year period during which the Company entirely withdrew from the acquisition market, management expects to reactivate this effort in the latter part of 2001. At least initially, the focus will be on modest purchases of incremental interests in existing and adjacent properties. To the extent the acquisition effort is successfully reinitiated and capital constraints are reduced, a more substantial effort will be considered beginning in 2002.

Development and Exploration

      In 2000, the Company spent $53.5 million on oil and gas related capital expenditures, an increase of 43% over that expended in 1999 (see Note 16 to the financial statements). Of this amount, $17.6 million was expended in the Southwest, $12.7 million in Appalachia and $23.2 million in the Gulf Coast. These expenditures were primarily focused on placing proved non-producing reserves on stream. They funded 56 recompletions, 178 development and 16 exploratory wells, minor lease acquisitions and seismic work. Exploration and development spending brought 28.3 Bcfe of proved non-producing reserves on stream and added a net 22.4 Bcfe of new reserves. Net reserves added during the year replaced 41% of production (see Note 20 to the financial statements).

Development

      Development includes recompletions, infill drilling and to a lesser extent, installation of secondary recovery projects. As described below, the Company currently has 2,130 proven recompletion opportunities and drilling locations in inventory. Drilling prospects are geographically diverse and target a mix of oil and gas, generally at depths of less than 8,000 feet. Approximately 83% of the proved development locations are concentrated in ten fields covering 824,144 gross (445,928 net) acres. The Company believes that such large acreage blocks and concentration of to be drilled wells provides economies of scale, access to competitively priced field services and focused operating and technical expertise. The following table sets forth information pertaining to the proven development inventory at December 31, 2000.

Exploration

      Onshore. The Company currently has 165 onshore exploration projects covering 264,810 gross (102,098 net) acres. Each project has multiple drilling prospects, some with several targeted formations. Given the current emphasis on debt reduction, only a limited amount of work will be done on these projects in 2001.

      Gulf of Mexico. The Company has a 3D seismic database covering 700 contiguous blocks in the shallow waters of the Gulf, primarily offshore Louisiana. This database has been used to map geological trends within this 3.5 million acre area, identifying specific targets for further exploration. The Company’s current offshore leasehold inventory totals only 25,000 gross (8,383 net) acres. To more fully exploit the 3D

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seismic database, it will be necessary to farm-in or lease significant additional acreage. To date, nine specific prospects have been identified. These prospects target Miocene formations at depths of 8,000 to 18,000 feet.

Production

      Production revenue is generated through the sale of natural gas, crude oil and natural gas liquids (“NGL”) from properties owned directly or through partnerships and joint ventures. The Company receives additional revenue from royalties. While production is sold to a limited number of purchasers, only three account for more than 10% of oil and gas revenues. Management believes that the loss of any individual customer would not have a material adverse effect on the Company. Proximity to local markets, availability of competitive fuels and overall supply and demand are factors affecting the prices at which production can be marketed. Factors outside the Company’s control, such as international political developments, overall energy supply and demand, weather conditions, economic growth rates and other factors in the United States and world economies have had, and will continue to have, a significant effect on energy prices.

      The following table sets forth production volumes, revenue and expense information for the past five years (in thousands, except average sales price and operating cost data).

      On an Mcfe basis, approximately 74% of the Company’s production is natural gas. Gas is sold to utilities, marketing companies and industrial users. Gas sales are made pursuant to various contractual arrangements including month-to-month, one to three-year contracts at fixed or variable prices and fixed prices for the life of the well. All contracts other than the fixed price contracts contain provisions for price adjustment, termination and other terms customary in the industry. Great Lakes sells 90% of its gas

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production to FirstEnergy based on closing prices on the New York Mercantile Exchange (“NYMEX”). The terms automatically renew for one-month periods through June 30, 2001. Oil is sold under contracts that can be terminated on 30 days notice. The price received is generally equal to a posted price set by major purchasers in the area. Oil purchasers are selected on the basis of price and service. In 2000, gas revenues totaled $119 million or 69% of oil and gas revenues while revenues from oil and natural gas liquids totaled $54 million. Oil and gas revenues in 2000 increased 19% over the prior year despite a 17% decline in production.

Transportation, Processing and Marketing

      Transportation, processing and marketing revenues are comprised of fees for the transportation and processing of gas as well as oil and gas marketing income. Transportation, processing and marketing revenues decreased 32% in 2000 to $5.3 million primarily as a result of asset sales.

      The Company’s gas transportation and processing assets include (i) 50% ownership in approximately 4,700 miles of gas pipelines in Appalachia held through Great Lakes and (ii) a number of smaller gathering systems associated with the Company’s producing properties. The Appalachian gathering systems transport a majority of Great Lakes’ gas production as well as third party gas to major trunklines and directly to end-users. Third parties who transport gas through the systems are charged a fee based on throughput. In the Southwest and Gulf Coast regions gas production is transported through a combination of Company-owned and third party gathering systems. The Company is typically charged a fee based on throughput in order to transport its gas through third party systems.

      The Company markets its own gas production and manages the impact of price fluctuations through hedging. Only 2% of gas production is currently sold pursuant to fixed price contracts at prices ranging from $1.25 to $4.73 per Mcf (averaging $2.98 per Mcf). The remaining 98% of gas production is sold at market (generally NYMEX) related prices.

Hedging Activities

      The Company regularly enters into hedging agreements to reduce the impact of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge prices and to limit volatility. The Company’s current policy is to hedge between 50% and 75% of its production on a rolling twelve to eighteen month basis. At December 31, 2000, hedges were in place covering 33.7 Bcf of gas and 1.0 million barrels of oil at prices ranging from $2.84 to $6.78 per Mmbtu (averaging $4.07) and from $26.96 to $33.71 per barrel (averaging $28.62). While these transactions have no carrying value, their fair value, represented by the estimated amount that would be required to terminate them, was a net loss of $72.1 million at December 31, 2000. Due to the decline in commodity prices, particularly natural gas, subsequent to year end, the fair market value of these hedge transactions was a net loss of $54.5 million at February 28, 2001. The contracts expire monthly through December 2002 and cover approximately 64% of anticipated 2001 production and 7% of 2002 production. Gains or losses on hedging transactions are determined as the difference between the contract price and a reference price, generally closing prices on the NYMEX. Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. Net gains (losses) relating to these derivatives in 1998, 1999 and 2000 approximated $3.1 million, $(10.6) million and $(43.2) million, respectively. Effective January 1, 2001, the gains (losses) in these hedging positions will be recorded at fair value on the Company’s balance sheet as Other Comprehensive Income (Loss), a component of Stockholders’ Equity.

      In June 2000, the Company repriced 4.1 Bcf of natural gas hedges from an average price of $2.59 to $3.00 per Mmbtu. In exchange, the Company hedged an average of 22,700 Mmbtu per day from April 2001 through March 2002 at an average price of $3.20 per Mmbtu. While the Company’s payment requirement for the repriced hedges was affected, the $6.0 million of estimated net losses on the original hedges were recorded in the periods in which they would have been recorded under generally accepted accounting principles. A deferred loss and associated liability of $6.0 million were recorded on the Balance Sheet at June 30, 2000, of which $665,000 and $945,000 remained at December 31, 2000,

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respectively. The imputed interest cost of the repricing was $168,000. See Note 7 for a summary of the Company’s hedge position at December 31, 2000.

Independent Producer Finance (“IPF”)

      IPF provides capital to small oil and gas producers to finance acquisition and development projects in exchange for term overriding royalty interests. The overrides are dollar-denominated and calculated to provide a contractual rate of return that typically ranges between 15% and 25%. Almost all of the advances are for less than $5 million and most are for $1 million or less. IPF funds itself through a combination of internal cash flow and bank borrowings. At December 31, 2000, IPF’s portfolio included 45 transactions having an aggregate book value of $48.9 million (net of $15.3 million of valuation allowances). The portfolio balance declined 25% from December 31, 1999 primarily due to $24.8 million of repayments received during 2000. The reserves underlying IPF’s royalty interests are not included in Range’s consolidated reserve disclosure.

      IPF provides valuation allowances against advances which may not be recoverable. These allowances reduce reported revenues. During early 2000, IPF provided $603,000 in additional allowances. However, because of higher product prices and growing cash receipts, IPF reversed $1.9 million of previously recorded allowances during the year. Accordingly, reported revenues increased a net $1.3 million, from $8.7 million to $10.0 million. IPF expenses include general and administrative costs and interest expense, which totaled $1.5 million and $3.4 million, respectively, in 2000. At current commodity prices, the Company believes that IPF’s valuation allowances are adequate.

      IPF has three petroleum engineers and geologists with an average of 18 years of experience who identify and evaluate projects. The staff is responsible for defining transaction risk, assessing reserve coverage and negotiating terms. Transactions are structured to minimize risk by focusing on asset coverage and taking direct title to the royalty interests. As dollar-denominated royalties, the transactions leave a portion of the commodity price risk with the producer. However, when extreme price declines occur, as they did in 1998 and 1999, IPF is exposed to substantial losses.

      IPF provides capital to parties who are generally ignored by traditional financial institutions. These producers are typically denied access to financing because: (i) they are too small to access the public securities markets; (ii) private equity and debt financing is too restrictive and expensive; and (iii) few commercial banks are interested in small energy loans as consolidation in the banking industry has raised the size threshold for lending. IPF’s portfolio decreased in 2000 as a limited number of fundings were more than offset by principal repayments. IPF expects demand for funding to rise as acquisition and divestiture activity accelerates and further consolidation in the banking industry reduces the availability of bank financing for small transactions. IPF’s bank debt is non-recourse to Range.

      IPF investments involve the purchase of a term overriding royalty interest pursuant to which it receives a specified share of revenues from specific properties. The producer’s obligation is non-recourse unless he fails to operate prudently, there is title failure and in certain other circumstances. Consequently, IPF’s success is based on its ability to accurately estimate reserves underlying its royalty, the prices at which the production will be sold, and the operator’s ability to recover the reserves on a timely basis. Because the override is considered a property interest, if a producer goes bankrupt, IPF’s interest should be beyond the reach of creditors. If a creditor, the producer as debtor-in-possession or a trustee in a bankruptcy proceeding were to argue successfully that the transaction should be characterized as a loan, IPF may have only a creditor’s claim for repayment. IPF’s ownership in these production payments is a non-operated interest. While IPF is unlikely to be exposed to liabilities associated with direct working interests, such as environmental matters, personal injuries or death and property damage, such events could result in a loss of IPF’s economic interest in the properties. The producer’s obligation to deliver a specified share of revenues to IPF is subject to the ability of the burdened reserves to produce such revenues. As a result, IPF bears the risk that revenues will not be sufficient to amortize its investment or provide an acceptable return.

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      IPF was acquired in 1998. The following table summarizes IPF’s historical investments:

Interest and Other

      The Company earns interest on cash balances and various receivables. However, interest and other income in 2000 was comprised principally of losses on property sales. The Company expects to continue to sell non-strategic properties. Interest and other income in 2000 amounted to $(702,000), representing (0.4)% of revenues.

Competition

      The Company encounters substantial competition in acquiring oil and gas leases, marketing its production, securing personnel and conducting drilling and field operations. Competitors in development, exploration, acquisitions and production include the major oil companies as well as numerous independents, individual proprietors and others. Many competitors have financial and other resources substantially exceeding those of the Company. 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 the Company permit. The ability of the Company to replace and expand its reserve base will depend on its ability to identify and acquire suitable producing properties and prospects for future drilling.

      Acquisitions have generally been financed through the issuance of debt and equity securities and internally generated cash flow. There is competition for capital to finance oil and gas projects. The ability of the Company to obtain financing on satisfactory terms is uncertain and can be affected by numerous factors beyond its control. The inability of the Company to raise external capital in the future could have a material adverse effect on its business.

Governmental Regulation

      The Company’s operations are affected in varying degrees 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 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 Company’s cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, the Company is unable to precisely predict the future cost or impact of complying.

The Restructuring

      A series of significant acquisitions financed principally with debt and convertible securities were completed between late 1997 and mid-1998. Due to the poor performance of the acquired properties compounded by a decline in oil and gas prices which began in late 1997, the Company was forced to take a number of steps. These included a workforce reduction, a significant decrease in capital expenditures, the sale of assets, the formation of Great Lakes and the exchange of common stock for fixed income securities. Since year-end 1998, these initiatives have reduced parent company bank debt from over $365 million to $89.9 million. Total debt (including trust preferred) has been reduced 37% to $458.1 million. While

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management believes these steps have stabilized the Company’s financial position, debt remains too high. For the Company to return to its historical posture of consistent profitability and growth, further reductions in debt are believed necessary. The Company expects to utilize excess cash flow to retire debt and to continue to exchange common stock or other equity-linked securities for fixed income securities. While the Company hopes to reacquire the fixed income securities at a discount to face value, existing stockholders will be substantially diluted if a material portion of the fixed income securities are exchanged. The extent of dilution will depend on a number of factors, including the number of shares issued, the price at which stock is issued or newly issued securities are convertible into common stock and the price at which fixed income securities are reacquired. While such exchanges reduce existing stockholders’ proportionate ownership, management believes such exchanges enhance the Company’s financial flexibility and could increase the market value of its common stock.

      While the Company currently believes it has sufficient liquidity and cash flow to meet its obligations, a material drop in oil and gas prices or a reduction in production and reserves would reduce the ability to fund capital expenditures, reduce debt and meet financial obligations.

Environmental Matters

      The Company’s operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency (“EPA”) issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and pipeline, 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 and affects 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 the Company’s operations and financial position, as well as the industry in general. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations. The Company has not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. The Company did not have any material capital expenditures in connection with environmental matters in 2000, nor does it anticipate that such expenditures will be material in 2001.

      The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator 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. 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. 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 the Company.

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      The Federal Water Pollution Control Act (“FWPCA”) imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. 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 have not had a material adverse impact on the Company’s 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 Resources Conservation and Recovery Act (“RCRA”), as amended, generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing solid hazardous waste may be significant, the Company does not expect to experience more burdensome costs than similarly situated companies.

      The U.S. Oil Pollution Act (“OPA”) requires owners and operators of facilities that could be the source of an oil spill into “waters of the United States” (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have 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 reclassify 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 the Company’s operating costs, as well as the industry in general. Compliance with environmental requirements generally could have a material adverse effect on the capital expenditures, earnings or competitive position of the Company. Although the Company has 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 by the Company with the Securities and Exchange Commission (“SEC”), as well as information included in oral statements or other written statements made or to be made by the Company 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,” or “projects” 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

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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, and our ability to implement our business strategy. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph.

      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 the Company or on its behalf.

Common shareholders will be diluted if additional shares are issued

      The Company has filed shelf registration statements which allow it to issue additional common stock and has exchanged common stock for its fixed income securities over the past two years. In 1999, 2000 and early 2001, the Company exchanged common stock for 5 3/4% trust convertible preferred securities, convertible debentures and $2.03 convertible preferred stock. The exchanges were made based on the relative market value of the common stock and the convertible securities at the time of the exchange, incorporating negotiated terms ranging from a 6% discount to a 7% premium. The convertible securities were acquired at discounts to their face value ranging from 10% to 63%. During 2000, $25.0 million of trust preferred, $13.8 million of 6% convertible debentures and $23.2 million of $2.03 convertible preferred stock was acquired in exchange for common stock. See Notes 6 and 9 to the financial statements. While the exchanges reduce interest expense, dividends and future repayment obligations, the larger number of common shares outstanding have a dilutive effect on existing shareholders.

      The Company continues to review alternatives to further strengthen its balance sheet and to retire debt and convertible securities. The Company expects any alternative to involve the prospective issuance of a large number of shares of common stock. Therefore, such alternatives will tend to dilute current shareholders. The Company expects to continue to exchange common stock or other equity linked securities for its fixed income securities. While the Company anticipates reacquiring fixed income securities at a discount to their face value, existing stockholders will be substantially diluted if material portions of the fixed income securities are exchanged. The extent of dilution will depend on various factors, including the number of shares issued, the price at which newly issued securities are convertible into common stock and the price at which fixed income securities are reacquired. While such exchanges reduce existing stockholders’ proportionate ownership, management believes such exchanges enhance the Company’s financial flexibility and could increase the market value of its common stock. The Company’s ability to consummate exchanges and the terms of the exchanges is dependent on a number of factors beyond its control, such as the level of various interest rates, the willingness of other parties to engage in transactions, state and federal regulations covering such transactions and capital market conditions.

Dividends restrictions

      Restrictions on the payment of dividends and other restricted payments as defined are imposed under the Company’s bank credit agreements and the 8.75% senior subordinated notes. No common dividends may be paid under the current bank agreement. Partially in response to these restrictions, a new $2.03 Convertible Exchangeable Preferred Stock Series D was authorized in September 2000. The Series D had terms substantially identical to the previously outstanding Series C except that dividends could be paid in common stock. In November 2000, 523,140 shares of Series C were exchanged for Series D on a one-for-one basis. In December 2000, 323,140 shares of Series D were exchanged for common stock and the Company elected to pay fourth

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quarter 2000 Series D dividends in common stock. Fourth quarter 2000 dividends paid on the Series C amounted to only $10,000. Subsequent to year-end, all remaining shares of Series D and all but 8,235 shares of Series C were exchanged for common stock. Dividends on the remaining preferred stock amount to less than $17,000 per annum.

      The terms of the 8.75% senior subordinated notes limit restricted payments (including dividends) to the greater of $20 million or a formula based on earnings since the issuance of the notes. Given the Company’s losses over the past few years, the formula provides no availability. Therefore, the Company must rely on the $20 million basket. At December 31, 2000, $4.9 million of the $20 million basket remained available.

Oil and gas prices are volatile, which can adversely affect cash flow available for reinvestment

      The oil industry is highly cyclical and prices for oil and gas are volatile. Historically, the industry has experienced severe downturns characterized by oversupply and/or weak demand. Many factors affect oil and gas prices including general economic conditions, consumer preferences, discretionary spending levels, interest rates and the availability of capital to the industry. In 1998 and early 1999, oil and gas prices fell substantially, which contributed to the substantial losses reported by the Company in those years. At present, oil and gas prices are at levels substantially above their historical norm. Decreases in oil and gas prices from current levels could adversely affect the Company’s revenues, results of operations, cash flows and proved reserves. Significant and prolonged price decreases could have a materially adverse effect on the Company’s operations and limit its ability to fund capital expenditures. The Company has entered into hedging agreements covering approximately 64% and 7% of its anticipated production on an Mcfe basis for 2001 and 2002, respectively.

Hedging activities expose us to certain risks

      We enter into hedging arrangements covering a portion of our future oil and gas production to limit volatility and provide more predictable cash flow. Hedging instruments used include fixed price swaps and have at times included or may include collars, puts and options on futures. While hedging limits our exposure to adverse price movements, hedging may limit the benefit of price increases and is subject to a number of risks, including the risk the other party to the hedge will not perform.

Estimates of oil and gas reserves may change; we may not replace production

      The information on proved oil and gas reserves included in this document are simply estimates. 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 gas in place, recovery rates and future prices for oil and gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will vary from those assumed in our estimates, and such variances may be significant. If the assumptions used to estimate reserves later prove incorrect in any way, the actual quantity of reserves and future net cash flow could be materially different from the estimates used herein. In addition, results of drilling, testing and production along with changes in oil and gas prices may result in substantial upward or downward revisions.

      Without success in exploration, development or acquisitions, our reserves, production and revenues from the sale of oil and gas will decline over time. Exploration, the continuing development of our properties and acquisitions all require significant expenditures as well as expertise. If cash flow from operations proves insufficient for any reason, we may be unable to fund exploration, development and acquisitions at levels we deem advisable.

Our oil and gas properties’ carrying value may be written down

      Accounting rules require that the carrying value of oil and gas properties be periodically reviewed for possible impairment. An “impairment” is recognized when the book value of a proven property is

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greater than the expected undiscounted future cash flows from that property. We may be required to write down the carrying value of a property based on oil and gas prices at the time of the impairment review, as well as a continuing evaluation of development results, production data, economics and other factors. While an impairment charge does not impact cash or cash flow from operating activities, it reduces earnings, increases leverage ratios and reflects the long-term ability to recover a prior investment.

      Based primarily on the poor performance of certain properties acquired between late-1997 and mid-1998 and significantly decreased oil and gas prices, we recorded impairments of $197 million in 1998 and $27 million in 1999. For a further discussion of our accounting policies with respect to oil and gas properties, see Note 1 to the Consolidated Financial Statements.

We could incur substantial environmental liabilities

      Our industry is subject to numerous federal, state and local laws and regulations relating to the environment. We may incur significant costs and liabilities in complying with existing or future environmental laws and regulations. It is possible that increasingly strict environmental laws, regulations and enforcement policies or claims for damages to property, employees, other persons and the environment resulting from current or discontinued operations, could result in substantial costs and liabilities in the future. For additional information concerning environmental matters, see the “Environmental Matters” section included in this report.

Our activities involve operating hazards and uninsured risks

      While we maintain insurance against certain of the risks associated with our operations, including, but not limited to, explosion, pollution and fires, an event against which we are not fully insured could have a significant negative effect on our business. Such occurrences could include title defects on properties, lost equipment in drilling operations when the drilling contractor is not responsible for such loss, costs to redrill wells due to down hole equipment and casing failures, and property damage caused over a period of time not covered by standard industry insurance policies.

      We maintain insurance in amounts and areas of coverage normal for a company of our size and industry. These include, but are not limited to, workers’ compensation, employers’ liability, automotive liability and general liability. In addition, umbrella liability and operator’s extra expense policies are maintained. All such insurance is subject to normal deductible levels. We do not insure against all risks associated with our business either because insurance is unavailable or because we elect not to insure due to prohibitive cost or other considerations.

      Individuals or companies who feel the Company or those acting on its behalf damaged them physically or financially, have the right under the law to seek recovery in court. In today’s legal climate, the likelihood of suits continues to increase. As verdicts or judgments are so uncertain, the Company may elect to settle claims. Settlements may not be covered by insurance and costs might have to be borne solely by the Company. Even when the Company elects to contest a claim, it may be held liable by the courts. Often, the cost of defending oneself or one’s rights cannot be recovered from the other parties even if you prove successful and the costs must be borne solely by the Company. Such costs and settlements could have a material effect on the Company’s financial position. See Item 3 “Legal Proceedings” included in this report and Note 8 to Consolidated Financial Statements as to certain proceedings and contingencies.

We are subject to financing and interest rate exposure risks

      Our business and operating results can be harmed by factors such as the availability and cost of capital, increases in interest rates, changes in the tax rates, market perceptions of the oil and gas industry or the Company, or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue opportunities and place us at a competitive disadvantage. At December

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31, 2000, the Company had a portion of its borrowings subject to interest rate swap agreements. See Note 7 to the financial statements.

We face considerable competition

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

The oil industry is subject to extensive regulation

      The oil industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and regulations binding on the industry and participants in it. Compliance with such rules and regulations is often difficult and costly and may carry substantial penalties for non-compliance. As the regulatory burden on the industry increases, the cost of complying affects profitability. Generally these burdens do not appear to affect the Company to any greater or lesser extent than other companies in the industry with similar types and quantities of properties in the same areas of the country. While we are a party to several regulatory proceedings before governmental agencies arising in the ordinary course of business, we do not believe that their outcome will have a material adverse effect on our operations or financial condition.

Our high fixed charge burden could impact our liquidity, profitability and cash flow

      The Company pays significant fixed charges associated with its bank debt, 8.75% senior subordinated notes, 6% convertible debentures, the bank debt of its subsidiaries and 5.75% trust preferred. At December 31, 2000, the face value of these obligations totaled $458 million and the associated fixed charges, based on rates in effect at that date totaled $36.3 million a year. In addition, these obligations have certain requirements that the Company must meet to avoid the acceleration of the maturity of these instruments. See Note 6 to the Consolidated Financial Statements for their stated maturities. The acceleration of the maturity of one or more of such obligations could have a material adverse effect on the Company.

      The Company’s significant debt burden could have other important consequences such as, but not limited to, requiring the sale of assets at unfavorable prices, the impact of an increase in interest rates which would increase financing costs and limit capital available for developing and acquiring new properties, limit the ability to raise capital in the equity and/or debt markets, preclude financing options available to less leveraged companies, and make the Company more vulnerable to losses during periods of low oil and gas prices.

Risks associated with IPF

      IPF purchases term overriding royalty interests through which it receives an agreed upon share of revenues from certain properties. The producer’s obligation to deliver revenues to us is non-recourse. Consequently, IPF can only recover its investment and a return through revenues from those properties. These revenues are subject to our ability to accurately estimate reserves and production rates and the operator’s ability to produce and recover these reserves. In summary, IPF bears the risk that future revenues it receives will be insufficient to amortize the price paid for its overrides or to provide an acceptable return.

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Acquisitions are subject to numerous risks

      It generally is not feasible to review in detail every individual property acquired. 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. In late 1997 and 1998, a series of acquisitions were consummated which proved extremely unsuccessful. Ongoing results showed the potential of the properties was far less than our engineering and geological review, as well as a review by one of our independent petroleum engineering firms, had suggested.

Our Chairman has an interest in another oil and gas company that could compete with us

      Our Chairman also serves as the Chairman and Chief Executive Officer of Patina Oil & Gas Corporation (“Patina”), a publicly traded oil and gas company in which he is a significant investor. He is also an officer, director and/or significant investor in several other public and private companies engaged in various aspects of the energy industry. We currently have no business relationship with any of these companies, none of them owns our securities nor do we hold any of theirs. Historically, no material conflict has arisen with regard to these companies. However, conflicts of interests may arise. Board policies are in place that require Mr. Edelman, along with all other officers and directors, to give us notification of any potential conflicts that arise. However, we cannot assure you that we will not compete with one or more of these companies, particularly for acquisitions, or encounter other conflicts of interest in the future.

Success depends on key members of our management

      The Company’s success is highly dependent on its senior management personnel, none of who are currently subject to employment contracts. The loss of one or more of these individuals could have a material adverse effect on the Company.

Employees

      As of January 1, 2001, the Company had 139 full time employees, 49 of whom were field personnel. None are covered by a collective bargaining agreement. Management believes that its relationship with employees is good.

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ITEM 2. PROPERTIES

      On December 31, 2000, the Company held working interests in 9,649 gross (4,790 net) productive wells and royalty interests in an additional 436. Including its 50% share of Great Lakes’ reserves, its properties contained, net to its interest, estimated proved reserves of 427.7 Bcf of gas and 26.0 million barrels of oil and NGL or a total of 583.7 Bcfe.

Proved Reserves

      The following table sets forth estimated proved reserves over the past five years.

(a)

Oil and NGL are converted to Mcfe at a rate of 6 Mcf per barrel.

      At year end 2000, the Company engaged the following independent petroleum consultants to evaluate its reserves: H.J. Gruy and Associates, Inc. (Southwest), DeGolyer and MacNaughton (Southwest and Gulf Coast), and Wright and Company, Inc. (Appalachia). These engineers were employed primarily based on their geographic expertise as well as their history in engineering certain properties. At December 31, 2000, these consultants collectively evaluated approximately 80% of the proved reserves set forth above. The remainder were evaluated by the internal engineering staff. All estimates of oil and gas reserves are subject to significant uncertainty.

      The following table sets forth the estimated future net revenues from proved reserves and the present value of those revenues in millions over the past five years.

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      Future net revenues represent future revenues from the sale of proved reserves net of production and development costs (including production and ad valorem 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, 2000. Average product prices at December 31, 2000 were $24.95 per barrel of oil, $14.58 per barrel for natural gas liquids, and $9.46 per Mcf of gas using benchmark NYMEX prices of $26.80 per barrel and $9.77 per Mmbtu. There can be no assurance that the proved reserves will be produced within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties. No estimates of reserves have been filed with or included in reports to another federal authority or agency since year-end.

Significant Properties

      The Company’s proved reserves at December 31, 2000 were concentrated in three regions, Southwest, Gulf Coast and Appalachia. The Southwest is divided into the Permian and the Midcontinent divisions. The Appalachian properties represent the Company’s 50% ownership in Great Lakes. At year-end, the Company’s properties included working interests in 9,857 gross (4,788 net) productive oil and gas wells and royalty interests in 436 additional wells. The Company also held interests in 487,688 gross (219,457 net) undeveloped acres. The following table sets forth summary information with respect to estimated proved reserves at December 31, 2000.

Southwest Region

      The Southwestern properties are situated in the Permian and Val Verde Basins of west Texas, the Texas panhandle, the East Texas Basin and the Anadarko Basin of western Oklahoma. Reserves in this region represented 40% by volume and 35% by value of total proved reserves at December 31, 2000. Proved reserves totaled 233 Bcfe, of which 55% was gas. At December 31, 2000, the Southwest Region properties had a development inventory of 193 proven recompletions and 151 drilling locations. Acreage owned by the Southwest Region at December 31, 2000 included 264,719 gross (189,692 net) developed acres and 54,025 gross (41,074 net) undeveloped acres. During 2000, 29 development wells (19.7 net) were drilled, of which 25 (16.8 net) were productive. Two exploratory wells (0.6 net) were drilled, of which none were productive.

      Permian. The Permian properties, located in the Permian and Val Verde Basins of west Texas, contained 175 Bcfe of proved reserves at year end. These reserves represented 30% by volume and 23% by value of total proved reserves and were 57% oil and NGL. In the fourth quarter of 2000, net production averaged 4,244 barrels of oil and NGL and 19.1 Mmcf of gas per day, or 44.6 Mmcfe per day in total. Producing wells total 1,256 (1,129 net), of which the Company operates approximately 93%. Major producing areas include Sonora, Sterling and Big Lake/Fuhrman-Mascho/Powell Ranch. The Oakridge and Frances Hill fields in the Sonora area produce from multiple deltaic channel Canyon sandstones at depths of 2,600 to 6,000 feet. At Sterling, gas production is derived from Canyon/Cisco sub-marine sand deposits at

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4,000 to 8,000 foot depths, while oil production comes from Silurian Fusselman carbonates at 8,200 to 10,000 feet. The Big Lake/Fuhrman-Mascho/Powell Ranch area produces primarily oil from the San Andres/Grayburg formations at depths ranging from 2,500 feet to 4,600 feet and from the Wolfcamp formation at a depth of 8,000 to 9,000 feet. At December 31, 2000, the Permian division had a development inventory of 155 proven recompletions and 135 proven drilling locations. Acreage owned by the Permian division at December 31, 2000 included 66,919 gross (64,892 net) developed acres and 48,325 gross (37,374 net) undeveloped acres. During 2000, eleven development wells (6.1 net) were drilled, all of which were productive. One exploratory well (0.5 net) was drilled, which was dry.

      Midcontinent. The Midcontinent properties, located in the Anadarko Basin of western Oklahoma and the Texas panhandle, held proved reserves of 59 Bcfe at December 31, 2000. These reserves, representing 10% by volume and 12% by value of total proved reserves were 92% gas. Of the 311 gross (197