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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

Commission File Number: 1-13515

FOREST OIL CORPORATION
(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
Warrants to purchase Common Stock, expiring February 15, 2004
Warrants to purchase Common Stock, expiring February 15, 2005
Warrants to purchase Common Stock, expiring March 20, 2010

        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 ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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. ý

        Indicate by check mark whether the registrant is an accelerated filer. Yes ý    No o

        The aggregate market value of the voting stock held by non-affiliates as of June 30, 2002, the last business day of the registrant's most recently completed second fiscal quarter, was $899,972,660 (based on the closing price of such stock on the New York Stock Exchange Composite Tape). As of February 28, 2003, the aggregate market value of the voting stock held by non-affiliates was $926,010,654 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

        There were 48,165,013 shares of the registrant's Common Stock, Par Value $.10 Per Share outstanding as of February 28, 2003.

        Document incorporated by reference: Portions of the registrant's definitive proxy statement for the Forest Oil Corporation annual meeting of shareholders to be held on May 8, 2003, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

PART I

        Throughout this Form 10-K, we make statements that may be deemed "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. See Item 1, "Forward-Looking Statements" below. Historical statements made herein are accurate only as of the date of filing this Form 10-K with the Securities and Exchange Commission and may be relied upon only as of that date.

        In this report, quantities of oil or natural gas liquids are expressed in barrels (BBLS), thousands of barrels (MBBLS) or millions of barrels (MMBBLS). One barrel equals 42 U.S. gallons. Quantities of natural gas are expressed in thousands of cubic feet (MCF), millions of cubic feet (MMCF) or billions of cubic feet (BCF). Equivalent units are expressed in thousand cubic feet of gas equivalents (MCFE), million cubic feet of gas equivalents (MMCFE), or billion cubic feet of gas equivalents (BCFE). Liquids are converted to gas at one barrel of oil equaling six MCF of gas. The term liquids is used to describe oil, condensate and natural gas liquids (NGL). With respect to information relating to Forest's working interest in wells or acreage, "net" oil and gas wells or acreage is determined by multiplying gross wells or acreage by Forest's working interest therein.

        Throughout this Form 10-K we use the terms "Forest", "Company", "we", "our" and "us" to refer to Forest Oil Corporation and its subsidiaries.

Item 1. Business

The Company

        Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, production and marketing of natural gas and liquids in North America and selected international locations. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. On December 31, 2002, we had 456 employees. Our common stock, par value $.10 per share, is traded on the New York Stock Exchange under the symbol "FST."

        We operate from offices located in Anchorage, Alaska; Denver, Colorado; Lafayette and Metairie, Louisiana; and Calgary, Alberta, Canada. Our corporate headquarters is located at 1600 Broadway, Denver, Colorado, 80202, telephone 303.812.1400. Information about Forest, including the periodic and current reports that it files with the Securities and Exchange Commission, and all amendments thereto, are accessible, free of charge, on Forest's website, www.forestoil.com, within 24 hours after filing with the SEC.

        In 2002, we operated in six business units: Offshore Gulf of Mexico, Onshore Gulf Coast, Western United States, Alaska, Canada and International. We conduct exploration and development activities in each of our North American core areas and in selected international locations. Our reserves and producing properties are all located in North America. At December 31, 2002, approximately 89% of our oil and gas reserves were in the United States and approximately 11% in Canada. During 2002, we produced 144 BCFE or an average of 394 MMCFE per day. Approximately 86% of our total production in 2002 was in the United States and approximately 14% in Canada. In the first quarter of 2003 we modified our business unit structure by combining the Offshore Gulf of Mexico and Onshore Gulf Coast units for increased efficiencies.

        For information with respect to our reserves, see Item 2, Properties, of this Form 10-K. For financial information relating to our geographic and operational segments, see Note 13 of Notes to Consolidated Financial Statements of this Form 10-K.

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Exploration and Production Activities

        During 2002, we drilled a total of 69 wells of which 16 were exploration and 53 were development. Our 2002 drilling program achieved a 75% success rate. At December 31, 2002, we held interests in approximately 876 net oil and gas wells in the United States and Canada. Our operations are conducted through our business units described below.

        Offshore Gulf of Mexico.    Our offshore operations are comprised of interests in the Gulf of Mexico. In 2002, the Offshore Gulf of Mexico was Forest's leading business unit for oil and gas production, contributing 46% of total production (67 BCFE, an average of 184 MMCFE per day). At December 31, 2002, this business unit accounted for 23% of our total estimated proved reserves. Forest participated in drilling 17 wells in the Offshore Gulf of Mexico during 2002, of which 14 wells were productive.

        Onshore Gulf Coast.    Our Onshore Gulf Coast business unit includes interests in properties located in the Texas and Louisiana Gulf Coast. In 2002, the Onshore Gulf Coast business unit contributed 9% of total production (14 BCFE, an average of 38 MMCFE per day). At December 31, 2002, this business unit accounted for 15% of our total estimated proved reserves. In 2002, the Onshore Gulf Coast business unit participated in drilling three wells, two of which were productive.

        Western United States.    Our Western business unit is comprised primarily of our interests in Oklahoma, Utah, Wyoming, West Texas and Southeast New Mexico. In 2002, the Western business unit contributed 16% of total production (23 BCFE, an average of approximately 63 MMCFE per day). The Western business unit accounted for 20% of our estimated proved reserves at December 31, 2002. In 2002, the Western Business unit participated in drilling 27 wells, of which 23 were productive.

        Alaska.    Our Alaska operations are located primarily in the Cook Inlet area, consisting of production from Redoubt Shoal Field, McArthur River Field, West McArthur River Unit and Trading Bay Field. In 2002, the Alaskan business unit contributed 14% of our sales volumes (20 BCFE, an average of 55 MMCFE per day). At December 31, 2002, 31% of our total estimated proved reserves were in Alaska. In 2002, Forest participated in drilling six wells in Alaska, five of which were productive. We commenced production at Redoubt Shoal in December 2002.

        Canada.    Our Canadian operations include interests in the Plains region of Alberta, the Foothills regions of Alberta and British Columbia, and the Northwest Territories. In 2002, our Canadian operations contributed 14% of total production (20 BCFE, an average of 55 MMCFE per day). At December 31, 2002, the Canadian business unit accounted for 11% of our total estimated proved reserves. During 2002, the Canadian business unit participated in drilling 16 wells, eight of which were productive.

        International.    Forest evaluates oil and gas opportunities in countries outside North America. We currently hold concessions in South Africa, Gabon, Switzerland, Germany, Albania, Italy and Romania, as well as overriding royalty interests in certain other areas. To date, Forest has not recorded any proved reserves related to its international concessions. The book value of these international interests at December 31, 2002 represents approximately 2% of our total assets.

        In connection with our activities related to the development of the Ibhubesi Gas Field, offshore South Africa, we signed a Participation Agreement on March 13, 2003 with The Petroleum Oil and Gas Corporation of South Africa (Pty) Limited (PetroSA) and Anschutz Overseas South Africa (Pty) Limited (Anschutz Overseas). Under the terms of the Participation Agreement, PetroSA has agreed to contribute US$30 million towards a drilling program starting in 2003 in order to earn an undivided 24% cost bearing interest (16.8% from Forest and 7.2% from Anschutz Overseas) in certain sub-lease agreements covering portions of Forest's South African offshore acreage, including the Ibhubesi Gas Field. PetroSA also has the option to acquire additional cost bearing interests. The Participation

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Agreement will not become operative until PetroSA has satisfactorily completed additional due diligence within twenty (20) days after the effective date, various governmental approvals have been obtained and the US$30 million has been transferred to an escrow account. We have dedicated considerable resources to the exploration of properties in South Africa; however, we do not expect to record any reserves for the Ibhubesi discovery until gas sales agreements have been executed.

        During 2002, we entered into two participation agreements in connection with our exploration activities in Gabon and Germany. Pursuant to these agreements, Forest received partial cost reimbursements and will be carried for future drilling costs in exchange for a reduced interest in the concessions.

        Foreign oil and natural gas operations are subject to certain risks, such as nationalization, confiscation, terrorism, renegotiation of existing contracts and currency fluctuations. Forest monitors the political, regulatory and economic developments in any foreign countries in which we operate. We sometimes attempt to reduce the risks associated with conducting operations in foreign countries by entering into farmout arrangements where we retain a working interest. We cannot assure you that these measures will adequately address all of these risks.

Sales and Markets

        Oil and gas operations.    Forest's U.S. production of natural gas is generally sold at the wellhead in the areas where it is produced or at nearby "pooling points". Our U.S. natural gas production is generally sold on a month to month basis in the spot market using published indices. We believe that the loss of one or more of our current natural gas spot purchasers would not have a material adverse effect on Forest's business in the United States because any individual spot purchaser could be readily replaced by another spot purchaser who would pay approximately the same sales price. Sales to Reliant Energy Services, Inc., a purchaser of natural gas in the Gulf of Mexico, represented approximately 10% of our total revenue in 2002.

        Our oil and natural gas liquids are typically sold under short-term contracts at prices based upon posted field prices. Except in Alaska, our liquids production is generally sold at the wellhead. Our Alaskan oil production, which represented approximately 14% of our total 2002 production, is currently being sold to a local refiner, Tesoro Alaska Petroleum Company and its affiliate. The oil is transported to a terminal by a pipeline company that is 40% owned by Forest. Our contract with this refiner expires on December 31, 2003 and is renewed automatically from year to year thereafter until terminated by either party upon written notice 60 days prior to December 31. Sales to this purchaser represented 16% of our total revenue in 2002.

        Canadian Forest's natural gas production is sold either through the ProMark Netback Pool, which is operated by ProMark on behalf of Canadian Forest, or through Canadian Forest's direct sales contracts or under spot contracts. ProMark is a wholly owned subsidiary of Canadian Forest. Canadian Forest sold approximately 76% of its natural gas production through the ProMark Netback Pool in 2002. Canadian oil and natural gas liquids are typically sold under short-term contracts at prices based upon posted prices at Alberta pipeline and processing hubs, netted back to the field.

        We enter into energy swaps and collars to hedge the price of a portion of our spot market volumes against price fluctuations.

        Marketing and trading activities.    The ProMark Netback Pool matches major end users with providers of gas supply through firm transportation arrangements, and uses a netback pricing mechanism to establish the wellhead price paid to producers. Under this netback arrangement, producers receive the blended market price less related transportation and other direct costs. ProMark charges a marketing fee to the pool participant producers for marketing and administering the gas supply pool.

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        The ProMark Netback Pool gas sales in 2002 averaged 73 MMCF per day, of which Canadian Forest supplied approximately 31 MMCF per day or 42%. Approximately 21% of the volumes sold in the ProMark Netback Pool in 2002 were sold at fixed prices. The remainder of the volumes sold were priced in a variety of ways, including prices based on published indices.

        In addition to operating the ProMark Netback Pool, ProMark provides other marketing services for other producers and consumers of natural gas. ProMark manages long-term gas supply contracts for industrial customers and provides full-service purchasing, accounting and gas nomination services for both producers and customers on a fee-for-services basis. ProMark follows procedures to immediately match its gas purchase and sales commitments with offsetting gas purchase or sales, so there is not a risk from an open trading book position. We are, however, exposed to credit risk in that there exists the possibility that the counterparties to agreements will fail to perform their contractual obligations. The credit of counterparties is evaluated and letters of credit, prepayments or parent guarantees are obtained when considered necessary to minimize credit risk.

Competition

        The oil and natural gas industry is intensely competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Forest's competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop properties and our ability to select, acquire and develop proved reserves. We compete with a substantial number of other companies including many companies with larger technical staffs and greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, generate electricity and market refined products. We also compete with major and independent oil and gas companies in the marketing and sale of oil and gas to transporters, distributors and end users. The oil and natural gas industry competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. Forest competes with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time. Finally, companies not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies provide competition for Forest.

        Forest's business is affected not only by such competition, but also by general economic developments, governmental regulations and other factors that affect our ability to market our oil and natural gas production. The prices of oil and natural gas realized by Forest are highly volatile. The price of oil is generally dependent on world supply and demand, while the price we receive for our natural gas is tied to the specific markets in which such gas is sold. Declines in crude oil prices or natural gas prices adversely impact Forest's activities. Our financial position and resources may also adversely affect our competitive position. Lack of available funds or financing alternatives can prevent us from executing our operating strategy and from deriving the expected benefits therefrom. For further information concerning Forest's financial position, see Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Form 10-K.

        ProMark also faces competition from other gas marketers, some of whom are significantly larger in size and have greater financial resources than ProMark, Canadian Forest or Forest.

Regulation

        Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations and foreign laws and regulations.

        United States.    Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted

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and by certain agencies of the Federal government for operations on Federal leases. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions requiring permits for the drilling of wells and maintaining bonding requirements in order to drill or operate wells and provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the number of wells which may be drilled in an area and the unitization or pooling of crude oil and natural gas properties. In this regard, some states can order the pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

        The Federal Energy Regulatory Commission (FERC) regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 (NGA) and the Natural Gas Policy Act of 1978 (NGPA). In the past, the Federal government has regulated the prices at which oil and gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989 (the Decontrol Act) removed all NGA and NGPA price and nonprice controls affecting producers' wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

        Commencing in 1992, the FERC issued Order No. 636 and subsequent orders (collectively, Order No. 636), which require interstate pipelines to provide transportation services separate from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. Commencing in February 2000, the FERC issued Order No. 637 and subsequent orders (collectively, Order No. 637), which imposed a number of reforms intended to further enhance competition in natural gas markets. Most major aspects of Order No. 637 were upheld in judicial review, though certain issues were remanded to FERC, have been considered on remand, and are pending rehearing at FERC.

        While any additional FERC action on these matters would affect Forest only indirectly, these changes are intended to further enhance competition in natural gas markets. We cannot predict whether and to what extent the FERC's regulations will survive rehearing and further judicial review and, if so, whether the FERC's actions will achieve the goal of increasing competition in natural gas markets in which our natural gas is sold. However, we do not believe that we will be affected materially differently than other natural gas producers and markets with which and in which we compete.

        The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines operating on or across the Outer Continental Shelf (the OCS) provide open-access, non-discriminatory service. Commencing in April 2000, FERC issued Order No. 639 and subsequent orders (collectively, Order No. 639), which imposed certain reporting requirements applicable to "gas service providers" operating on the OCS concerning their prices and other terms and conditions of service. The purpose of Order No. 639 is to provide regulators and other interested parties with sufficient information to detect and to remedy discriminatory conduct by such service providers. FERC has stated that these reporting rules apply to OCS gatherers and has clarified that they may also apply to other OCS service providers including platform operators performing dehydration, compression, processing and related services for third parties. The U.S. District Court overturned the FERC's reporting rules as exceeding its authority

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under OCSLA. The FERC has recently appealed this decision. We cannot predict whether and to what extent these regulations might be reinstated, and what effect, if any, they may have on our financial condition or operations. The rules, if reinstated, may increase the frequency of claims of discriminatory service, may decrease competition among OCS service providers and may lessen the willingness of OCS gathering companies to provide service on a discounted basis.

        Certain operations that we conduct are on federal oil and gas leases, which are administered by the Bureau of Land Management (BLM) and the Minerals Management Service (MMS). These leases contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). Many onshore leases contain stipulations limiting activities that may be conducted on the lease. The stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban any surface activity. For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard and the Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling. Lessees must also comply with detailed BLM or MMS regulations, as applicable, governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of OCS wells, calculation of royalty payments and the valuation of production for this purpose and removal of facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the BLM or MMS, as applicable, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

        In March 2000, the MMS issued a final rule modifying the valuation procedures for the calculation of royalties owed for crude oil sales. When oil production sales are not in arms-length transactions, the new royalty calculation will base the valuation of oil production on spot market prices instead of the posted prices that were previously utilized. We do not believe that this rule will have a material adverse effect on our operations.

        Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by Congress, states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. We do not anticipate, however, that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon our capital expenditures, earnings or competitive position. No material portion of Forest's business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the Federal government.

        Canada.    The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be created.

        In Canada, oil and natural gas exported from Canada is subject to regulation by the National Energy Board (NEB), an independent federal regulatory agency and the government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export

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contracts must continue to meet certain criteria prescribed by the NEB. Natural gas exports for a term of less than two years or for a term two to 20 years (in quantities of or more than 30,000 cubic meters per day), must be made pursuant to a NEB order. Oil exports may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any export has been obtained from the NEB. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB, as will an oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years). The issue of such a license requires the approval of the government of Canada.

        The provincial governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

        In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

        The Petroleum Registry of Alberta is a new initiative of both industry and the Alberta government. Its purpose is to streamline data transfers between industry and government and industry to industry (i.e., partner to partner). The initiative makes use of technology such as the Internet to facilitate the transfer of regulatory and royalty data, reports and royalty payments.

        Concurrent with the implementation of the registry, the government of Alberta imposed a new NGL royalty system for products situated in the residue gas stream. It is the goal of this policy to maintain royalty neutrality. As such, there appears to be minimal effect on Canadian Forest's royalties.

        From time to time the governments of Canada, Alberta, British Columbia and Saskatchewan have established incentive programs which have included royalty rate deductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid by Forest to the provincial governments. The trend in recent years has been for provincial governments to allow such programs to expire without renewal, and consequently few such programs are currently operative.

        In Alberta, certain producers of oil or natural gas are entitled to a credit against the royalties to the Crown by virtue of the ARTC (Alberta royalty tax credit) program. The credit is determined by applying a specified rate to a maximum of $2 million CDN of Alberta Crown royalties payable for each producer or associated group of producers. The specified rate is a function of the Royalty Tax Credit reference price which is set quarterly by the Alberta Department of Energy and ranges from 25% to 75%, depending on oil and gas par prices for the previous calendar quarter. Canadian Forest is eligible for ARTC credits only on eligible properties acquired and wells drilled after the change of control that occurred when Canadian Forest was acquired by Forest. Production from properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible.

        Regulation in Northwest Territories of Canada.    The provincial governments have jurisdiction over the exploration and development of oil and gas resources in the provinces of Canada and the federal government has jurisdiction over the exploration and development of oil and gas resources in the

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Canadian territories. The federal regulatory regime reflects the extended timelines and increased capital expenditures inherent in working in the northern environment, providing for work commitments and work deposits coupled with the suspension and/or reimbursement of rentals and royalties at earlier developmental stages. This regime is subject to change as development in the Northwest Territories evolves toward a more conventional model. It is possible that, at some point, jurisdiction over the oil and gas resources in these territories could be transferred to the territorial governments of the Yukon, the Northwest Territories and Nunavut. If so, the territorial governments would have the authority to regulate the grant of drilling permits, the construction of pipelines and other matters affecting oil and gas exploration and development activities. We are unable to predict whether any transfer of jurisdiction to the territorial governments would affect our exploration and development activities in the Northwest Territories, although it is possible that the territorial governments would adopt policies or regulations that could delay or limit our proposed exploration and development activities, delay or prevent the construction of pipelines or result in the payment of higher royalties or taxes than would otherwise be the case under the current federal regulatory framework.

        As a result of Canadian Forest's activity in the Northwest Territories, a large royalty tax credit has been accumulated to the extent of qualified capital expenditures. This credit can be used to eliminate royalties on existing and future producing wells.

        Canadian Forest's right to produce oil and gas from its Northwest Territories properties, along with the production rights of other industry participants in these properties, is subject to conversion of certain instruments (i.e., exploration licenses or significant discovery licenses) into production licenses on those lands which contain commercial discoveries. The right to such conversion is not absolute and is subject to an application process and regulatory approval. In addition, the right to produce may be dependent on the negotiation of a pooling agreement or the imposition of a forced pooling order, if other producers have rights in the spacing unit. Until the finalization of the particulars of such agreement and, or order, it would not be possible to finally determine Canadian Forest's share of production in such lands.

        North American Free Trade Agreement.    On January 1, 1994 the North American Free Trade Agreement (NAFTA) among the governments of Canada, the United States and Mexico became effective. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36-month period), (ii) impose an export price higher than the domestic price, or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements. NAFTA contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

        Environmental Matters.    Extensive U.S. federal, state and local laws, as well as law of foreign countries, govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (commonly called the EPA) issue regulations to implement and enforce such laws. Environmental laws and regulations are often difficult and costly to comply with and substantial administrative, civil and even criminal penalties can be imposed for failure to comply. These laws and regulations may, in certain circumstances, impose "strict liability" for environmental contamination, rendering an owner or lessee liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of the owner or lessee. This regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. Changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations or earnings, as well as the oil

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and gas exploration and production industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future.

        The Oil Pollution Act of 1990 (OPA) and regulations thereunder impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A "responsible party" includes the owner or operator of a pipeline, vessel or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages from oil spills. OPA also requires operators of offshore OCS facilities to demonstrate to the MMS that they possess at least $35 million in financial resources that are available to pay for costs that may be incurred in responding to an oil spill. This financial responsibility amount can increase up to a maximum of $150 million if the MMS determines that a greater amount is justified based on specific risks posed by the operations or if the worst case oil-spill discharge volume possible at a facility exceeds applicable threshold volumes established by the MMS. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by OPA.

        The U.S. Federal Water Pollution Control Act (commonly called the Clean Water Act) imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes in "waters of the United States," a broadly-defined term that includes all navigable waters. Many state discharge regulations and the federal National Pollutant Discharge Elimination System generally prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into coastal waters. Although the costs to comply with these zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our financial condition and operations.

        The Comprehensive Environmental Response, Compensation and Liability Act, as amended (commonly called CERCLA but also known as "Superfund") and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current owner and operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances that have been released at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. In the ordinary course of Forest's operations, substances may be generated that fall within the definition of "hazardous substances." Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. Moreover, we may own or operate properties that in the past were operated by third parties whose operations were not under our control. Those properties and any wastes that may have been disposed or released on them may be subject to CERCLA, and analogous state laws, and we potentially could be required to remediate such properties.

9

        In Canada, the oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of fines and penalties, the revocation of licenses and authorizations or civil liability for pollution damage.

        Although we maintain insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to fully cover all such costs or that such insurance will continue to be available in the future or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant environmental-related event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.

        We have established guidelines to be followed to comply with U.S. and Canadian environmental laws and regulations. In addition, we have designated a compliance officer whose responsibility is to monitor regulatory requirements and their impacts on Forest or Canadian Forest and to implement appropriate compliance procedures. We also employ an environmental director whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance against the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future.

        We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate making increased expenditures as a result of increasingly stringent laws relating to the protection of the environment.

Forward-Looking Statements

        The information in this Form 10-K includes "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. All statements, other than statements of historical facts or present facts, that address activities, events, outcomes and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K, in Part II, Item 7 under the caption "—Risk Factors."

        These forward-looking statements appear in a number of places and include statements with respect to, among other things:

•

estimates of our future natural gas and liquids production, including estimates of any increases in oil and gas production;



•

planned capital expenditures and availability of capital resources to fund capital expenditures;



•

our outlook on oil and gas prices;



•

estimates of our oil and gas reserves;



•

the impact of political and regulatory developments;

10

•

our future financial condition or results of operations and our future revenues and expenses; and



•

our business strategy and other plans and objectives for future operations.

        We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures and the other risks described in Part II, Item 7 under the caption "—Risk Factors." The financial results of our foreign operations are also subject to currency exchange rate risks.

        Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by our reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

        Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

        All forward-looking statements express or implied, included in this Form 10-K and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Forest or persons acting on its behalf may issue. Forest does not undertake to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-K with the Securities and Exchange Commission, except as required by law.

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Item 2. Properties

        Forest's principal proved reserves and producing properties are located in the United States in Alaska, Louisiana, Oklahoma, Texas, Utah, Wyoming and the Gulf of Mexico, and in Canada in Alberta, British Columbia and the Northwest Territories. In addition, we have acreage in various locations outside North America.

Reserves

        Information regarding Forest's proved and proved developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein is included in Note 14 of Notes to Consolidated Financial Statements. See also Part II, Item 7 "—Risk Factors—Estimates of oil and gas reserves are uncertain and inherently imprecise" for additional information regarding reserves.

        Since January 1, 2002 we have not filed any oil or natural gas reserve estimates or included any such estimates in reports to any Federal or foreign governmental authority or agency, other than the Securities and Exchange Commission (SEC) and the Department of Energy (DOE). There were no differences between the reserve estimates included in the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" dates of such reserve estimates.

        Forest's estimated proved reserves were 1,560 BCFE at December 31, 2002 compared to estimated proved reserves of 1,546 BCFE at December 31, 2001. Approximately 52% of our estimated proved reserves at December 31, 2002 were natural gas and our estimated proved developed reserves represented approximately 63% of total estimated proved reserves.

Production

        The following table shows our net liquids and natural gas production for the years ended December 31, 2002, 2001 and 2000:

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Average Sales Prices

        The following table sets forth production volumes and average sales prices per MCF of natural gas and per barrel of liquids for the years ended December 31, 2002, 2001 and 2000:

(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 36,050 MMCF, 42,870 MMCF and 53,078 MMCF for the years ended December 31, 2002, 2001 and 2000, respectively. Hedged oil and condensate volumes were 3,921,500 barrels, 3,742,500 barrels and 6,953,000 barrels for 2002, 2001 and 2000, respectively. Most of these arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net gains (losses) related to our cash flow hedges were ($1,742,000), $22,781,000 and $(129,091,000), respectively, for the years ended December 31, 2002, 2001 and 2000. Those arrangements that are not designated as cash flow hedges for accounting purposes are recorded as non-operating income or expense.

13

Productive Wells

        The following summarizes our total gross and net productive wells at December 31, 2002:

(1)

Productive wells are producing wells and wells capable of production, including injection wells, salt water disposal wells, service wells and wells that are shut-in.

(2)

The number of gross wells is the total number of wells in which a working interest is owned.

(3)

Includes 11 dual completions in the United States and eight dual completions in Canada. Dual completions are counted as one well. If either completion is an oil completion, the well is classified as an oil well.

(4)

The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

14

Developed and Undeveloped Acreage

        Forest held acreage as set forth below at December 31, 2002 and 2001. A majority of the developed acreage is subject to mortgage liens securing our bank indebtedness. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 4 of Notes to Consolidated Financial Statements.

(1)

Developed acres are those acres which are spaced or assigned to productive wells.

(2)

Undeveloped acres are considered to be those acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. It should not be confused with undrilled acreage held by production under the terms of a lease.

(3)

A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)

A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

        Approximately 10% of our net undeveloped acreage at December 31, 2002 is held under leases that have terms that will expire in 2003, if not extended by exploration or production activities, and approximately 0.5% of net undeveloped acreage will expire in 2004 if not extended by exploration or production activities.

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Drilling Activity

        During the years ended December 31, 2002, 2001 and 2000, Forest drilled gross and net exploratory and development wells as set forth below. This information does not include wells drilled under farmout agreements or any other wells in which we do not have a working interest.

(1)

A dry well (hole) is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

(2)

Productive wells are producing wells and wells capable of production, including wells that are shut-in.

(3)

The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

        At December 31, 2002 Forest and its subsidiaries had 4 exploratory wells (2.4 net) and 3 development wells (2.4 net) that were in the process of being drilled.

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Delivery Commitments

        A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool which is operated by ProMark on behalf of Canadian Forest. At December 31, 2002, the ProMark Netback Pool had entered into fixed price contracts to sell natural gas at the following quantities and weighted average prices:

        As operator of the netback pool, ProMark aggregates gas from producers for sale to markets across North America. Currently, over 30 producers have contracted with the netback pool including Canadian Forest. These producers have dedicated reserves and lands to the pool. The producers are paid a blended netback price which reflects all of the revenue from approved customers less the costs of delivery (including transportation, audit and shortfall makeup costs) and a ProMark marketing fee.

        Canadian Forest, as one of the producers in the ProMark Netback Pool, is obligated to supply its contract quantity. In 2002 Canadian Forest supplied 42% of the total netback pool sales quantity. In the 2003/2004 contract year, it is estimated that Canadian Forest will supply approximately 42% of the netback pool quantity. We expect that Canadian Forest's pro rata obligations as a gas producer will increase in 2005 and future years. In order to satisfy their supply obligations, the ProMark Netback Pool and Canadian Forest may be required to cover their obligations in the market.

        As the operator of the netback pool, ProMark is required to acquire gas in the event of a shortfall between the gas supply and market obligations. A shortfall could occur if a gas producer fails to deliver its dedicated share of the supply obligations of the netback pool. The cost of purchasing gas to cover any shortfall is a cost of the netback pool. The prices paid for shortfall gas would typically be spot market prices and may differ from the market prices received from netback pool customers. Higher spot prices would reduce the average netback pool price paid to the gas producers, including Canadian Forest. Shortfalls in gas produced may occur in the future. The Company does not believe that such shortfalls will be significant.

        In addition to its commitments to the ProMark Netback Pool, Canadian Forest is committed to sell natural gas at the following quantities and weighted average prices through its direct sales contracts:

        There were no long-term delivery commitments in the United States as of December 31, 2002.

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Item 3. Legal Proceedings

        Forest, in the ordinary course of business, is a party to various legal actions. While we believe that the amount of any potential loss would not be material to our consolidated financial position, the ultimate outcome of these proceedings is inherently difficult to predict with any certainty. In the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow in the reporting periods in which any such actions are resolved.

        On December 7, 2000, Forest completed a merger transaction with Forcenergy Inc, in which Forest was the surviving company. Prior to the merger with Forest, Forcenergy was a party to various claims and routine litigation arising in the normal course of its business. Prior to the merger, on March 21, 1999, Forcenergy and its wholly-owned subsidiary, Forcenergy Resources Inc., filed voluntarily under Chapter 11 of the U.S. Bankruptcy Code. Forcenergy continued to operate as a debtor-in-possession subject to the bankruptcy court's supervision and orders until its plan of reorganization (which was confirmed on January 19, 2000) became effective on February 15, 2000. Obligations of Forcenergy arising out of activities prior to March 21, 1999, the bankruptcy petition date, will be discharged in accordance with the plan of reorganization. Pursuant to the plan of reorganization, Forcenergy established a reserve of Forcenergy common stock to be distributed to claimants in the event their disputed claims are ultimately determined by the bankruptcy court to be allowed claims. The reserved shares of Forcenergy common stock became Forest common shares in accordance with the terms of the merger. If the shares in the reserve are inadequate to cover all allowed claims, then under the Forcenergy plan of reorganization Forest would be required to issue additional shares of common stock to the holders of these claims. Forest currently believes, however, that the shares in the reserve are adequate to cover all remaining disputed claims that may be subsequently allowed. We cannot give assurances, however, that this will be the case.

        On May 1, 2002, the State of Alaska approved the development and production phase of our Redoubt Shoal project (the Production Project). On May 30, 2002, Cook Inlet Keeper, a non-governmental third party, filed a challenge to the regulatory review and approval process for the Production Project. In July 2002, Forest was granted leave to intervene to defend the State of Alaska's approval of the Production Project. In August 2002, the Court entered a briefing schedule. That briefing has been completed, and the matter is now set for oral argument before the Court on April 17, 2003. Separately, Cook Inlet Keeper filed a motion in September 2002 asking the Court to stay Forest's development and production phase operations during the pendency of the briefing process and through the Court's final determination regarding the challenge. Forest filed an opposition, and the Court denied Cook Inlet Keeper's motion on December 4, 2002. Cook Inlet Keeper appealed that denial to the Alaska Supreme Court. Forest subsequently filed an opposition. On March 14, 2003, the Alaska Supreme Court remanded the matter to the trial Court for clarification of the Court's ruling, and postponed ruling on the petition for review until receipt of that clarification. While we intend to continue our vigorous opposition to Cook Inlet Keeper's challenge, the outcome of the litigation is inherently difficult to predict with any certainty. We can give no assurances as to the effect of any delays in the Production Project on Forest's financial condition and results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

        No matter was submitted to a vote of our shareholders during the fourth quarter of the fiscal year ended December 31, 2002.

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Item 4A. Executive Officers of Forest

        The following persons were serving as executive officers of Forest as of February 28, 2003.

19

(1)

The term of office of each officer is one year from the date of his or her election immediately following the last annual meeting of shareholders and until the officer's respective successor has been elected and qualified or until his or her earlier death, resignation or removal from office whichever occurs first. Each of the named persons has held the office indicated since the last annual meeting of Forest's shareholders.

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PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

Common Stock

        Forest has one class of common shares outstanding, its common stock, par value $.10 per share (Common Stock). Forest's Common Stock is traded on the New York Stock Exchange under the symbol "FST". On February 28, 2003, there were 48,165,013 outstanding shares of our Common Stock held by 710 holders of record. The number of holders does not include the shareholders for whom shares are held in a "nominee" or "street" name.

        The table below reflects the high and low intraday sales prices of the Common Stock on the New York Stock Exchange composite tape during each fiscal quarterly period of 2001 and 2002. There were no dividends declared on the Common Stock in 2001 or 2002. On February 28, 2003, the closing price of Forest Common Stock was $22.75.

Warrants

        Forest has three series of warrants outstanding, which are each quoted on the NASDAQ Bulletin Board. At February 28, 2003, Forest had outstanding 237,739 warrants expiring on February 15, 2004 (the 2004 Warrants), which were held by 421 holders of record. Each 2004 Warrant entitles the holder to purchase 0.8 shares of Common Stock for $16.67, or an equivalent per share price of $20.84. Forest's 2004 Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLW.OB." On February 28, 2003, or the last day of activity prior thereto, the closing price of the 2004 Warrants was $10.35. The table below reflects the high and low intraday sales prices of the 2004 Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2001 and 2002.

        At February 28, 2003, Forest also had outstanding 238,195 warrants expiring on February 15, 2005 (the 2005 Warrants), which were held by 422 holders of record. Each 2005 Warrant entitles the holder to purchase 0.8 shares of Common Stock for $20.83, or an equivalent per share price of $26.04. Forest's 2005 Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLZ.OB." On February 28, 2003, or the last day of activity prior thereto, the closing price of the 2005 Warrants was

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$4.05. The table below reflects the high and low intraday sales prices of the 2005 Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2001 and 2002.

        At February 28, 2003, Forest also had outstanding 1,752,355 subscription warrants (the Subscription Warrants), which were held by nine holders of record. Each Subscription Warrant entitles the holder to purchase 0.8 shares of Common Stock for $10.00, or an equivalent per share price of $12.50. The Subscription Warrants are detachable and expire on March 20, 2010 or earlier upon notice of expiration by Forest if, after March 20, 2004, the market price of the Common Stock has exceeded 300% of the exercise price, or $37.50 per share, for a period of 30 consecutive trading days. Forest's Subscription Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLL.OB". On February 28, 2003, or the last day of activity prior thereto, the closing price of the Subscription Warrants was $13.75. The table below reflects the high and low intraday sales prices of the Subscription Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2001 and 2002.

        The warrants were originally issued by Forcenergy in connection with its plan of reorganization under the Bankruptcy Code, and were converted into warrants to purchase Forest common stock pursuant to our merger with Forcenergy on December 7, 2000. The issuance of Forest common stock upon exercise of the warrants is exempt from registration under the Securities Act of 1933 pursuant to section 1145 of the Bankruptcy Code. During 2002, Forest issued 17,971 shares of common stock pursuant to the exercise of warrants.

Dividend Restrictions

        Forest's present or future ability to pay dividends is restricted by (i) the provisions of the New York Business Corporation Law, (ii) Forest's 8% Senior Notes due 2008, Forest's 8% Senior Notes due 2011 and Forest's 7³/4% Senior Notes due 2014, and (iii) our credit facilities dated as of December 7, 2000 with JPMorgan Chase and J.P. Morgan Bank Canada. The provisions in the indentures pertaining to the 8% Senior Notes due 2008 and 2011 and the 7³/4% Senior Notes due 2014, and the credit facilities limit our ability to make restricted payments, which include dividend payments.

        Forest has not paid dividends on its Common Stock during the past five years and does not presently anticipate that it will do so in the foreseeable future. The future payment of dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on Forest's earnings, capital requirements, financial condition and other relevant factors. There is no assurance that Forest will pay any dividends. For further information regarding our equity securities and our ability to pay dividends on our Common Stock, see Notes 4 and 7 of Notes to Consolidated Financial Statements.

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Item 6. Selected Financial and Operating Data

        The following table sets forth selected financial and operating data of Forest as of and for each of the years in the five-year period ended December 31, 2002. This data should be read in conjunction with Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and the Consolidated Financial Statements and Notes thereto.

        On December 7, 2000, Forest completed its merger with Forcenergy Inc (Forcenergy). The merger was accounted for as a pooling of interests for accounting and financial reporting purposes. Under this method of accounting, the recorded assets and liabilities of Forest and Forcenergy were carried forward to the combined company at their recorded amounts on the date of the merger. Income and expense amounts reported for the combined company for 2000 include amounts attributable to the operations of both Forest and Forcenergy for the entire year. Forcenergy was merged into Forest on the date of the merger and, accordingly, all amounts attributable to periods after the merger represent the operations of the combined entities. The results of operations of Forcenergy prior to December 31, 1999, the effective date of its reorganization and fresh-start reporting, are not included in the financial statements of the combined company. In conjunction with the merger with Forcenergy, Forest effected a 1-for-2 reverse stock split. Unless otherwise indicated, all share and per share amounts included herein give retroactive effect to this reverse stock split.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

        All expectations, forecasts, assumptions and beliefs about our future financial results, condition, operations, strategic plans and performance are forward-looking statements, as described in more detail in Part I, Item 1, under the heading "Forward-Looking Statements" of this Form 10-K. Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed under the heading "—Risk Factors" below and elsewhere in this Form 10-K. Historical statements made herein are accurate only as of the date of filing of this Form 10-K with the Securities and Exchange Commission and may be relied upon only as of that date.

        On December 7, 2000, Forest completed a merger with Forcenergy Inc (Forcenergy). The merger was accounted for as a pooling of interests for accounting and financial reporting purposes. Under this method of accounting, the recorded assets and liabilities of Forest and Forcenergy were carried forward to the combined company at their recorded amounts on the date of the merger. Income and expense amounts reported for the combined company for 2000 include amounts attributable to the operations of both Forest and Forcenergy for the entire year. Forcenergy was merged into Forest on the date of the merger and, accordingly, all amounts attributable to periods after the merger represent the operations of the combined entities.

        The following discussion and analysis should be read in conjunction with Forest's Consolidated Financial Statements and Notes thereto.

Results of Operations

        Net earnings for 2002 were $21,276,000 compared to net earnings of $103,743,000 in 2001. The decrease in earnings was the result of lower production volumes and lower average oil and gas sales prices, offset partially by lower operating expenses. Lower production volumes were primarily the result of property sales in the fourth quarter of 2001, hurricane downtime in the Gulf of Mexico and normal declines caused by reduced capital expenditures.

        Net earnings for 2001 were $103,743,000 compared to net earnings of $130,608,000 in 2000. The decrease in earnings was due primarily to higher deferred income tax expense in 2001. In 2000, the income tax expense was lower due to a credit for previously unrecognized deferred tax assets. Earnings before income taxes were higher in 2001 than in 2000 as a result of higher product prices, offset partially by higher operating expense and lower production volumes.

        Marketing and processing, net represents the net margin earned by ProMark as well as processing income earned in the United States. Marketing and processing, net increased 14% to $3,954,000 in 2002 from $3,465,000 in 2001. The increase was due primarily to gas plant income in the United States. Marketing and processing income increased 12% to $3,465,000 in 2001 from $3,094,000 in 2000. The increase was due primarily to an increase in volumes marketed by ProMark in 2001 as well as higher margins on arrangements where the profit was determined as a percentage of natural gas sales prices

        Oil and gas sales revenue decreased by 34% to $471,740,000 in 2002 from $714,852,000 in 2001, primarily as a result of lower product prices and production volumes. The average sales prices received for natural gas and liquids in 2002 decreased 28% and 9%, respectively, compared to the average sales prices in 2001. Production volumes decreased 16% on an MCFE basis in 2002 compared to 2001. Volume decreases were attributable primarily to the Gulf of Mexico Offshore business unit. The Gulf of Mexico properties were impacted by the sale of 50% of Forest's interests in the South Marsh Island and Vermilion areas in the fourth quarter of 2001, and also experienced hurricane downtime and normal production declines that were the result of reduced capital expenditures.

        Oil and gas sales revenue increased by 14% to $714,852,000 in 2001 from $624,925,000 in 2000 due primarily to higher oil and gas prices, offset partially by lower production volumes. The average sales prices for natural gas and liquids in 2001 increased 34% and 4%, respectively, compared to the average sales prices received in 2000. Production volumes for natural gas and liquids on an MCFE basis

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decreased 6% in 2001 compared to 2000. Volume decreases were attributable primarily to normal declines and property sales affecting Gulf of Mexico properties.

        Oil and gas production expense includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of workovers that are expensed rather than capitalized because they do not extend the life of the property, product transportation costs, production taxes and ad valorem taxes. In 2002, production expense decreased 15% to $158,699,000 from $186,250,000 in 2001. The decrease was due primarily to lower direct operating expense. In 2001 production expense increased 33% to $186,250,000 from $140,218,000 in 2000. The increase in 2001 was due primarily to increased workover activity, platform refurbishment in the Gulf of Mexico, pipeline maintenance in Alaska, general service cost increases, higher transportation costs and higher ad valorem tax expense.

        Production volumes and weighted average sales prices for the years ended December 31, 2002, 2001 and 2000 were as follows:

(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 36,050 MMCF, 42,870 MMCF and 53,078 MMCF in 2002, 2001 and 2000, respectively. Hedged oil and condensate volumes were 3,921,500 barrels, 3,742,500 barrels and 6,953,000 barrels in 2002, 2001 and 2000, respectively. Most of these arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net gains (losses) related to our cash flow hedges were $(1,742,000), $22,781,000 and $(129,091,000), respectively, for the years ended December 31, 2002, 2001 and 2000. Those arrangements that are not designated as cash flow hedges for accounting purposes are recorded as non-operating income or expense.

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        General and administrative expense was $39,126,000 in 2002 compared to $30,514,000 in 2001 and $35,580,000 in 2000. Total overhead costs (capitalized and expensed general and administrative costs) were $65,127,000 in 2002 compared to $51,988,000 in 2001 and $56,666,000 in 2000. The increases in 2002 were attributable primarily to increases in employee related expenses, legal expense and insurance expense, lower fixed rate overhead cost recoveries for production operations as a result of the Gulf of Mexico property sale and the related change in operatorship of those properties, and lower fixed rate overhead cost recoveries for drilling activities due to decreased capital spending in the 2002 period. The decreases in 2001 were due to operating synergies associated with the merger with Forcenergy and higher recoveries of overhead related to production operations and drilling activities. The percentage of overhead capitalized remained relatively constant, at approximately 40% during 2002 and 41% during 2001. The percentage of overhead capitalized increased to 41% of total overhead in 2001 compared to 37% in 2000. The increase in the capitalization rate in 2001 was due primarily to an increase in the relative numbers of exploration and development personnel compared to administrative personnel following the merger with Forcenergy. The following table summarizes total overhead costs incurred during the periods:

(1)

Includes $1,484,000, $1,376,000 and $1,386,000 in 2002, 2001 and 2000, respectively, related to marketing operations.

        Merger and seismic licensing costs of $9,836,000 in 2001 and $31,577,000 in 2000 include banking, legal, accounting, printing and other consulting costs related to the merger; severance paid to terminated employees; expenses for office closures, employee relocation, data migration and systems integration; and costs of transferring seismic licenses from Forcenergy to Forest.

        Depreciation and depletion expense was $186,221,000 in 2002 compared to $226,033,000 in 2001. The decrease was attributable primarily to lower production volumes. On a per-unit basis, the depletion rate was $1.26 per MCFE in 2002 compared to $1.29 per MCFE in 2001. Depreciation and depletion expense increased to $226,033,000 in 2001 from $212,480,000 in 2000 due primarily to a higher per-unit rate. The depletion rate increased to $1.29 per MCFE in 2001 compared to $1.15 per MCFE in 2000, due primarily to capital spending and higher estimates for future development costs during the first nine months of 2001, offset partially by a reduction in future development costs, credits to the full cost pool for property sales and increases in estimated proved reserves in the last three months of 2001.

        At December 31, Forest had the following costs of undeveloped properties which were not subject to depletion:

        No impairments were recorded in 2002. In 2001, Forest recorded impairments of oil and gas properties located outside North America of $18,072,000. Of this amount, approximately $10,000,000

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related to an unsuccessful well in Albania. Impairments were also recognized in other countries based on expiration of certain concessions and evaluations of the viability of projects in those countries. In 2000, Forest recorded an impairment of $5,876,000 related to unsuccessful exploratory wells drilled in Switzerland and Thailand.

        In 2001, there was an impairment of contract value of $3,239,000 related to the netback pool administered by ProMark. The unamortized portion of the contract values recorded in the 1996 acquisition of ProMark was reduced to more closely match the remaining cash flows.

        Other expense of $703,000 in 2002 consisted primarily of franchise taxes. Other expense of $9,592,000 in 2001 consisted primarily of a reserve of $8,305,000 for 100% of receivables due from Enron for physical sales of natural gas. Other income of $1,757,000 in 2000 consisted primarily of interest income earned by Forcenergy.

        Interest expense of $50,433,000 in 2002 increased $523,000 or 1% compared to 2001 due primarily to higher debt balances that were, on average, 19% higher, offset partially by lower interest rates on variable and fixed rate debt. Interest expense of $49,910,000 in 2001 decreased $10,359,000 or 17% compared to 2000 due to lower average debt balances that were, on average, 4% lower, lower rates on variable and fixed rate debt and a net gain of $1,163,000 recognized under interest rate swap agreements.

        Foreign currency translation gains (losses) were $332,000 in 2002, $(7,872,000) in 2001 and $(7,102,000) in 2000. The foreign currency translation gains and losses were the result of translation of the 8³/4% Notes issued by Canadian Forest and were attributable to the increases and decreases in the value of the Canadian dollar relative to the U.S. dollar during the periods. Forest was required to recognize the noncash foreign currency translation gains or losses related to the 8³/4% Notes because the debt was denominated in U.S. dollars and the functional currency of Canadian Forest is the Canadian dollar. All of the outstanding notes were redeemed on September 15, 2002.

        There was a realized loss on derivative instruments of $1,253,000 in 2002 and a realized gain on derivatives of $11,556,000 in 2001. The loss in 2002 was due primarily to a $1,823,000 net settlement of a call option related to two terminated interest rate swaps associated with our 8% Senior Notes. The gain in 2001 was due primarily to oil and natural gas prices being, in the aggregate, lower than the prices established in certain derivative contracts that did not qualify for hedge accounting. This gain was partially offset by a $2,255,000 writeoff of 100% of the asset value of energy swaps where Enron was the counterparty.

        There was a net unrealized loss on derivative instruments of $788,000 in 2002 compared to a net unrealized gain on derivative instruments of $376,000 in 2001. The loss in 2002 was attributable primarily to decreases in the estimated future value of existing commodity swaps and collars as a result of increases in commodity futures prices. The gain in 2001 represents primarily the excess of the fair value over the intrinsic value of oil and gas derivatives designated as hedges. These realized and unrealized gains on derivative instruments were recorded separately in non-operating income since the instruments do not qualify as cash flow hedges under the accounting rules governing hedging activities that were adopted in 2001.

        Forest recorded current income tax expense of $268,000 in 2002 compared to $2,365,000 in 2001 and $1,666,000 in 2000. The decrease in 2002 compared to 2001 is due primarily to decreases in pre-tax profitability and reduced state tax provisions. The increase in 2001 compared to 2000 is due primarily to increases in pre-tax profitability and higher state tax provisions.

        Deferred income tax expense was $14,049,000 in 2002, compared with $77,212,000 in 2001 and $4,400,000 in 2000. The decrease in 2002 compared to 2001 was due primarily to reduced pre-tax profitability. The increase in 2001 compared to 2000 was due primarily to increased pre-tax profitability and to the recognition in 2000 of the future income tax benefit of previously unrecognized deferred tax assets.

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        The extraordinary loss on extinguishment of debt of $3,210,000 in 2002 resulted from the repurchase of $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value, the repurchase of $22,210,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 107.8% of par value, and the redemption of $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value. The extraordinary loss on extinguishment of debt of $5,611,000 in 2001 resulted from the redemption of $129,152,000 and $8,820,000 principal amount of 8³/4% and 10¹/2% Senior Subordinated Notes, respectively, at 102.764% and 106% of par value, respectively.

Liquidity and Capital Resources

        Liquidity is a measure of a company's ability to access cash. We have historically addressed our long-term liquidity requirements through the use of bank credit facilities and cash provided by operating activities as well as through the issuance of debt and equity securities, when market conditions permit. The prices we receive for future oil and natural gas production and the level of production have significant impacts on operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production.

        We continually examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, preferred stock or other equity securities, the issuance of net profits interests, sales of non-strategic assets, prospects and technical information, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

        Working Capital.    Working capital is the amount by which current assets exceed current liabilities. It is normal for Forest to report working capital deficits at the end of a period. Such working capital deficits are principally the result of accounts payable related to exploration and development costs. Settlement of these payables is funded by cash flow from operations or, if necessary, by drawdowns on long-term bank credit facilities.

        Forest had a working capital deficit, exclusive of the effects of derivatives, of approximately $15,159,000 at December 31, 2002 compared to a deficit of approximately $56,230,000 at December 31, 2001. The decrease in the deficit was due primarily to a decrease in accounts payable due to lower exploration and development activity, offset by a decrease in accounts receivable as a result of lower production prices and decreased production.

        Cash Flow.    Historically, one of our primary sources of capital has been net cash provided by operating activities. Net cash provided by operating activities was $190,067,000 in 2002 compared to $498,013,000 in 2001. The decrease was due primarily to lower product prices and decreased production. Cash used for investing activities in 2002 was $356,643,000 compared to $421,196,000 in 2001. The decrease was due primarily to decreased exploration and development activity in 2002, offset partially by lower property sales in 2002 compared to 2001. Net cash provided by financing activities in 2002 was $171,563,000 compared to net cash used of $81,196,000 in 2001. The 2002 period included net bank debt borrowings of $75,389,000, proceeds from the settlement of interest rate swaps of $35,630,000 and net proceeds of $146,846,000 from the issuance of the 7³/4% Notes, offset by repurchases of the 10¹/2% Notes of $23,935,000 and repurchases and redemptions of the 8³/4% Notes of $66,248,000. The 2001 period included net repayments of bank debt of $313,560,000, cash used for redemption of 8³/4% Senior Subordinated Notes of $131,933,000, cash used for the purchase of treasury stock of $55,803,000, and net cash inflows of $420,550,000 from the issuance of two series of 8% Senior Notes.

        Net cash provided by operating activities was $498,013,000 in 2001 compared to $306,532,000 in 2000. The increase was due primarily to higher production revenue as a result of higher oil and gas prices. Cash used for investing activities in 2001 was $421,196,000 compared to $376,061,000 in 2000.

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The increase was due primarily to increased exploration and development activity in 2001, offset partially by an increase in property sales in 2001. Net cash used by financing activities in 2001 was $81,196,000 compared to $16,172,000 in 2000. The 2001 period included net repayments of bank debt of $313,560,000, cash used for redemption of 8³/4% Senior Subordinated Notes of $131,933,000, cash used for the purchase of treasury stock of $55,803,000, and net cash inflows of $420,550,000 from the issuance of two series of 8% Senior Notes. The 2000 period included net repayments of bank debt of $52,006,000 and net proceeds of $38,800,000 from Forcenergy's issuance of 14% Series A Cumulative Preferred Stock.

        Capital Expenditures.    Expenditures for property acquisition, exploration and development were as follows:

        Forest's anticipated expenditures for exploration and development in 2003 are estimated to range from $300,000,000 to $350,000,000. We intend to meet our 2003 capital expenditure financing requirements using cash flows generated by operations, sales of non-strategic assets and borrowings under existing lines of credit. There can be no assurance, however, that we will have access to sufficient capital to meet these capital requirements. The planned levels of capital expenditures could be reduced if we experience lower than anticipated net cash provided by operations or develop other needs for liquidity, or could be increased if we experience increased cash flow or access additional sources of capital.

        In addition, while we intend to continue a strategy of acquiring reserves that meet our investment criteria, no assurance can be given that we can locate or finance any property acquisitions.

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        Bank Credit Facilities.    We have credit facilities totalling $600,000,000, consisting of a $500,000,000 U.S. credit facility through a syndicate of banks led by JPMorgan Chase and a $100,000,000 Canadian credit facility through a syndicate of banks led by J.P. Morgan Bank Canada. The credit facilities mature in October 2005. Under the credit facilities, Forest, Canadian Forest and certain of their subsidiaries are subject to certain covenants and financial tests, including restrictions or requirements with respect to dividends, additional debt, liens, asset sales, investments, hedging activities, mergers and reporting responsibilities. These finanical covenants will affect the amount available and our ability to borrow amounts under the credit facility. In addition, if the rating on our bank credit facilities is downgraded below BB+ by Standard & Poor's Rating Services (S&P) and Ba1 by Moody's Investors Services (Moody's), the available borrowing amount under the credit facilities would be determined by a formula based on the value of certain oil and gas properties (a borrowing base) subject to semi-annual re-determination. As a result, the available borrowing amount could be increased or reduced under the borrowing base tests.

        Under the most restrictive of the financial covenants contained in our credit facilities, the unused borrowing amount under the credit facilities at December 31, 2002 was approximately $150,000,000 in addition to amounts outstanding. At February 28, 2003, under the most restrictive of these financial covenants, our unused borrowing amount under the credit facilities was approximately $168,000,000.

        At December 31, 2002, there were outstanding borrowings of $95,000,000 under the U.S. credit facility at a weighted average interest rate of 3.24% and there were no outstanding borrowings under the Canadian credit facility. At February 28, 2003, the outstanding borrowings under the U.S. credit facility were $145,000,000 at a weighted average interest rate of 3.06%, and there were no outstanding borrowings under the Canadian credit facility. At February 28, 2003, Forest had used the credit facilities for letters of credit in the amount of $6,162,000 U.S. and $976,000 CDN.

        Our U.S. credit facility is secured by a lien on, and a security interest in, a majority of our proved oil and gas properties and related assets in the United States and Canada, a pledge of 65% of the capital stock of Canadian Forest and its parent, 3189503 Canada Ltd., and a pledge of 100% of the capital stock of Forest Pipeline Company. Under certain circumstances, we could be obligated to pledge additional assets as collateral.

        Credit Ratings.    Our bank credit facilities and our senior notes are separately rated by two ratings agencies: Moody's and S&P. In addition, S&P has assigned Forest a general corporate credit rating. From time to time, our assigned credit ratings may change. In assigning ratings, the rating agencies evaluate a number of factors, such as our industry segment, volatility of our industry segment, the geographical mix and diversity of our asset portfolio, the allocation of properties and exploration and drilling activities among short-lived and longer-lived properties, the need and ability to replace reserves, our cost structure, our debt and capital structure, and our general financial condition and prospects.

        Our bank credit facilities include conditions that are linked to our credit rating. The fees and interest rates on our commitments and loans, as well as our collateral obligations, are affected by our credit ratings. For example, if our credit rating is downgraded from its current level, the amount of credit that is available under the credit facilities will be determined by a borrowing base. The available borrowing amount could be increased or be reduced under the borrowing base tests. If as a result of a downgrade of our credit rating a borrowing base is established at a level below our then outstanding borrowings under the credit facilities, we would be required to repay the excess of outstanding borrowings over the newly established borrowing base. If we were unable to pay such excess, it would cause an event of default.

        The agreements governing our senior notes do not include adverse triggers that are tied to our credit ratings. The terms of our senior notes include provisions that will allow us greater flexibility if the credit ratings improve to investment grade and other tests have been satisfied. In this event, we would have no further obligation to comply with certain restrictive covenants contained in the

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indentures governing the senior notes. Our ability to raise funds and the costs of such financing activities may be affected by our credit rating at the time any such activities are conducted.

        Dispositions of Assets.    As a part of our ongoing operations, we routinely dispose of non-strategic assets. Assets with marginal value or which are not consistent with our operating strategy are identified for sale or trade.

        During 2002, we disposed of properties with estimated proved reserves of approximately 3.4 BCF of natural gas and 738,000 barrels of oil for total proceeds of approximately $5,465,000. During 2001, we disposed of properties with estimated proved reserves of approximately 69.8 BCF of natural gas and 4,868,000 barrels of oil for total proceeds of approximately $152,872,000. Of this amount, approximately $118,000,000 related to properties located in the offshore Gulf of Mexico area in which we sold 50% of our interests to Unocal in connection with a strategic joint venture program. During 2000, Forest disposed of properties with estimated proved reserves of approximately 28.3 BCF of natural gas and 913,000 barrels of oil for total net proceeds of $17,304,000.

        Termination of Interest Rate Swaps.    During 2002, Forest terminated two interest rate swaps related to its 8% Senior Notes and one interest rate swap related to its 7³/4% Senior Notes. We received net proceeds of approximately $35,630,000 related to those terminations, which amount was used for general corporate purposes. From inception to September 30, 2002, the effective rates on Forest's 8% Senior Notes due 2008 and 2011 were reduced to 7.18% and 7.32%, respectively, as a result of the original swaps. From October 1, 2002, to maturity, the effective rates on the 8% Senior Notes due 2008 and 2011 will be reduced to 7.24% and 7.66%, respectively, as a result of amortization of the gain related to termination of those swaps. From date of issuance to December 27, 2002, the effective rate on Forest's 7³/4% Senior Notes was reduced to approximately 3.50% as a result of the original swap. From December 28, 2002, to maturity, the effective rate on the 7³/4% Senior Notes will be reduced to approximately 6.87% as a result of amortization of the gain related to termination of the swap.

        Securities Issued.    In the second quarter of 2002, we issued $150,000,000 principal amount of 7³/4% Senior Notes due 2014 at 98.09% of par for proceeds of $146,846,000 (net of related issuance costs). A portion of the net proceeds was used to repay all outstanding indebtedness under our U.S. credit facility and to repurchase $15,110,000 principal amount of our 10¹/2% Senior Subordinated Notes. The remaining net proceeds were used for general corporate purposes.

        In January 2003, we issued 7,850,000 shares of common stock at a price of $24.50 per share. Net proceeds from this offering (before any exercise of the underwriters' over-allotment option), were approximately $184,400,000 after deducting underwriting discounts and commissions and the estimated expenses of the offering. Forest used the net proceeds from the offering to repurchase, immediately following the closing of the offering, 7,850,000 shares from The Anschutz Corporation and certain of its affiliates. The shares repurchased were cancelled immediately upon repurchase. In February 2003, an additional 900,000 shares of common stock were issued pursuant to exercise of the underwriters' over-allotment option. The net proceeds of $21,168,000 were used for general corporate purposes.

        Securities Redeemed and Repurchased.    During 2002, we repurchased $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value; $22,210,000 principal amount of our 10¹/2% Senior Subordinated Notes at approximately 107.8% of par value; and redeemed $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value, resulting in an aggregate loss of $3,210,000. In January 2003 we redeemed the remaining $65,970,000 outstanding principal amount of our 10¹/2% Senior Subordinated Notes at 105.25% of par value, resulting in a loss of $3,972,000 recorded in the first quarter of 2003. During 2002 we purchased 21,894 shares of our common stock at an average price of $24.68 per share pursuant to our odd-lot stock buyback program.

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        Contractual Obligations.    The following table summarizes our contractual obligations as of December 31, 2002: