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

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2001

or

For the transition period from                              to                             

Commission File Number: 1-13515

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

Registrant's telephone number, including area code: 303-812-1400

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

        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 /x/    No / /

        The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $809,351,067 as of February 28, 2002 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

        There were 46,823,509 shares of the registrant's Common Stock, Par Value $.10 Per Share outstanding as of February 28, 2002.

        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, 2002, are incorporated by reference into Part III of this Form 10-K.

        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. o

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. All expectations, forecasts, assumptions and beliefs about our future financial results, operations, plans, strategies and performance are forward-looking statements, as described in more detail in Part I, Item 1, under the heading "—Forward-Looking Statements". Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part II, Item 7 of this Form 10-K under the heading "—Risk Factors." 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 exploration, development, acquisition, production and marketing of natural gas and liquids. Forest was incorporated in New York in 1924, the successor to a company formed in 1916, and has been a publicly held company since 1969. On December 31, 2001, we had 493 employees. Our common stock, par value $.10 per share, is traded on the New York Stock Exchange under the symbol "FST." At February 28, 2002, The Anschutz Corporation (Anschutz), a private Denver-based corporation, owned approximately 32.5% of our outstanding common stock.

        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.

        Forest's estimated proved reserves were 1,546 BCFE at December 31, 2001 of which approximately 54% was natural gas. As of December 31, 2001, our estimated proved developed reserves were approximately 61% of total estimated proved reserves.

        Forest's principal reserves and producing properties are all located in North America. We conduct our oil and gas operations through six business units. In the United States, we have business units operating in four areas: offshore Gulf of Mexico, onshore Gulf Coast, the Western United States and Alaska. Our fifth business unit is located in Canada, where our oil and gas operations are conducted by our wholly owned subsidiary, Canadian Forest Oil Ltd. (Canadian Forest). Our sixth business unit oversees our interests in other countries, principally South Africa, Gabon, Italy, Germany, Albania and Romania. Activities outside North America have, to date, been exploratory in nature and are conducted through our wholly owned subsidiary, Forest Oil International Corporation. In addition, we conduct marketing and trading activities in Canada through Producers Marketing Ltd. (ProMark), a subsidiary of Canadian Forest.

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        For financial information relating to our geographic and operational segments, see Note 12 of Notes to Consolidated Financial Statements of this Form 10-K.

        All of our proved oil and gas reserves and producing properties are located in North America. At December 31, 2001 and 2000, and for the years then ended, the composition of our reserves and production was as follows:

        In 2001, as part of our effort to reposition our property portfolio, we completed property sales for a total of $153 million. These sales included the sale of 50% of our interest in properties in the South Marsh Island and Vermilion areas in the central Gulf of Mexico to Unocal Corporation in the fourth quarter of 2001 for adjusted cash proceeds of approximately $118 million. Unocal will operate the jointly owned properties, working with Forest to exploit and explore these properties and other leases within a defined area of mutual interest in the Gulf of Mexico.

        In 2002, we plan to dedicate almost half of our planned capital spending to development of our Redoubt Shoal discovery in Cook Inlet, Alaska, which is not expected to produce until late 2002. We expect that our 2001 divestitures, combined with our efforts to transition our portfolio to focus on longer-lived assets, will cause our overall 2002 production levels to decrease compared to 2001 levels. Commencing in 2003, our goal is to achieve a more optimal balance in our production portfolio between Alaska, the Gulf of Mexico, Canada and the lower 48 states in the U.S.

Exploration and Production Activities

        During 2001, we drilled or participated in a total of 120 wells of which 108 were exploration and 12 were development, including 111 working interest wells and 9 wells drilled under farmouts or in which we retained an overriding royalty or back-in interest. Our 2001 drilling program achieved an 86% success rate. At December 31, 2001, we held interests in approximately 1,102 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 2001, the offshore Gulf of Mexico was Forest's leading business unit for oil and gas production revenue, contributing approximately $435 million in oil and gas sales revenue from production of 94 BCFE or 258 MMCFE per day. At December 31, 2001, this business unit accounted for 26% of our total estimated proved reserves. Forest participated in drilling 46 wells in the offshore Gulf of Mexico during 2001, of which 38 wells were completed. During the fourth quarter of 2001 we sold 50% of our interest in properties in the South Marsh Island and Vermilion areas to Unocal and also entered into a joint exploration agreement with Unocal in these areas. Unocal took over operation of the joint properties on January 1, 2002.

        Onshore Gulf Coast.    Our Onshore Gulf Coast business unit includes interests in properties located in Texas and the Gulf Coast of Louisiana. In 2001, this business unit contributed $62 million in oil and gas

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sales revenue from production of 15 BCFE. In 2001, average production from Onshore Gulf Coast was 41 MMCFE per day. At December 31, 2001, this business unit accounted for 14% of our total estimated proved reserves. In 2001 Forest participated in drilling 12 wells, of which 11 were completed.

        Alaska.    Our Alaska operations are located primarily in the Cook Inlet area, consisting of production from McArthur River Field, West McArthur River Unit and Trading Bay Field. Development drilling, pipeline installation and facility construction are underway at our Redoubt Shoal discovery. In 2001, the Alaskan business unit contributed approximately $82 million in oil and gas sales revenue from production of 21 BCFE. Average production from Alaska in 2001 was 58 MMCFE per day. At December 31, 2001, 27% of our total estimated proved reserves were in Alaska. In 2001, Forest participated in drilling 11 wells in Alaska, all of which were successfully completed. In 2002, we have dedicated almost half of our capital budget to the development of the Redoubt Shoal Field. In 2003, we are targeting Alaska to contribute a greater proportion of our oil and gas production.

        Western United States.    Our Western business unit is comprised primarily of our interests in Oklahoma, Utah, Wyoming and West Texas. In 2001, the Western business unit contributed $78 million in oil and gas sales revenue from production of 23 BCFE, an average of approximately 63 MMCFE per day. The Western business unit accounted for 19% our estimated proved reserves at December 31, 2001. In 2001, the Western Business unit participated in drilling 27 wells, of which 26 were completed.

        Canada.    Our Canadian operations include interests in the Plains region in Alberta, the Foothills region of Alberta and British Columbia, and the Northwest Territories. In 2001, our Canadian operations contributed approximately $57 million in oil and gas sales revenue from production of 19 BCFE. Average production was 52 MMCFE per day in 2001. At December 31, 2001, the Canadian business unit accounted for 14% of Forest's total estimated proved reserves. During 2001, the Canadian business unit participated in drilling 20 wells and completed 15 wells.

        International.    Forest evaluates oil and gas opportunities in countries outside North America. We currently hold concessions in South Africa, Gabon, Switzerland, Germany, Albania, Italy, Romania and Thailand. To date, Forest has not recorded any proved reserves related to its international concessions. In 2001, we recorded impairments of approximately $18 million related to international projects, consisting primarily of $10 million related to drilling an unsuccessful well in Albania. The book value of these international interests at December 31, 2001 represents approximately 3% of our total assets.

        In 2001, we began commercialization efforts for the Ibhubesi gas discovery, located offshore South Africa. We are currently negotiating with several potential customers for the sale of natural gas from the Ibhubesi discovery. Even though the discovery well tested 190 MCFE per day, we do not expect to record any reserves for the Ibhubesi discovery until we have entered into gas sales agreements. We have dedicated considerable resources to the exploration of properties in South Africa.

        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; however, we cannot assure you that these measures will adequately address all of these risks.

Merger with Forcenergy Inc

        On December 7, 2000, Forest completed a merger with Forcenergy Inc (Forcenergy). Pursuant to the terms of the merger agreement, Forcenergy stockholders received 0.8 of a Forest common share for each share of Forcenergy common stock they owned and 34.307 Forest common shares for each $1,000 stated value amount of Forcenergy preferred stock. In addition, each warrant to purchase Forcenergy common stock was exchanged for a warrant to purchase 0.8 shares of Forest common stock. The merger was accounted for under the pooling of interests method of accounting.

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        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.

Sales and Markets

        No single customer accounted for more than 10% of our total revenue in 2001 or 2000.

        Oil and gas operations.    Forest's U.S. production is generally sold at the wellhead to oil and natural gas purchasing companies in the areas where it is produced. Liquids are typically sold under short-term contracts at prices based upon posted field prices. Natural gas in the United States is generally sold month to month on the spot market using published indices.

        Currently, nearly all of our U.S. natural gas is sold at the wellhead at spot market prices. The term "spot market" as used herein refers to contracts with a term of six months or less or contracts which call for a redetermination of sales prices every six months or sooner. We believe that the loss of one or more of our current natural gas spot purchasers should 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.

        Our Alaskan oil production, which represented approximately 12% of our total 2001 production, is sold primarily to one purchaser. The contract with this purchaser runs through December 31, 2002 and is renewed automatically from year to year thereafter until terminated by either party upon sixty days prior written notice.

        In Canada, 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. Canadian Forest's natural gas production is sold either through the ProMark Netback Pool which is operated by ProMark, the marketing subsidiary of Canadian Forest, or into the spot market. Canadian Forest sold approximately 63% of its natural gas production through the ProMark Netback Pool in 2001.

        From time to time we enter into energy swaps and collars to hedge the price of spot market volumes against price fluctuations. For more details about our hedging activities, see Part II, Item 7a, "—Commodity Price Risk."

        In December 2001, one of our purchasers, Enron Corp. and certain of its subsidiaries (Enron), filed for protection under Chapter 11 of the Bankruptcy Code. We do not believe that this event will have a material adverse effect on our business; however, during the fourth quarter of 2001, we fully reserved our Enron-related assets. In this respect, we incurred a charge of approximately $8.3 million to reserve for 100% of the accounts receivable for physical sales of natural gas to Enron and recorded an impairment of approximately $2.5 million representing 100% of the derivative asset value for contracts where Enron was the counterparty.

        Marketing and trading activities.    The ProMark Netback Pool matches major end users with providers of gas supply through arranged transportation channels, 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.

        The ProMark Netback Pool gas sales in 2001 averaged 82 MMCF per day, of which Canadian Forest supplied approximately 32 MMCF per day or 39%. Approximately 19% of the volumes sold in the ProMark Netback Pool in 2001 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

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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 a trading book perspective. 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 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 will 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 significant 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

        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 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

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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 April 1992, the FERC issued Order No. 636 and subsequent orders (collectively, Order No. 636), which require interstate pipelines to provide transportation services separate, or "unbundled", 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, among other things, (i) lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for releases of pipeline capacity of less than one year, (ii) permits pipelines to charge different maximum cost-based rates for peak and off-peak times, (iii) encourages auctions for pipeline capacity, (iv) requires pipelines to implement imbalance management services, and (v) restricts the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders.

        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 what further action the FERC will take on these matters, nor can we predict whether and to what extent the FERC's regulations will survive judicial review and, if so, whether the FERC's actions will achieve the stated goal of increased competition in natural gas markets. However, we do not believe that we will be treated 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 recently overturned the FERC's reporting rules as exceeding its authority under OCSLA. The FERC has indicated an appeal is likely. 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

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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. 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 exports are subject to regulation by the National Energy Board (NEB), an independent federal regulatory agency. Exports may be made pursuant to export orders with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude. Natural gas exported from Canada is also subject to regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB. Natural gas exports for a term of less than two years must be made pursuant to an NEB order, or, in the case of exports for a longer duration (to a maximum of 25 years) pursuant to an export license from the NEB with government of Canada approval.

        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.

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        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. 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 will make use of technology such as the Internet to facilitate the transfer of data, reports and royalty payments. Implementation is expected to be October 2002.

        Concurrent with the implementation of the registry, the government of Alberta will be imposing a new NGL royalty system for products situated in the residue gas stream. It is the goal of this policy to maintain royalty neutrality and as such, there should 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 (RTCRP) 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. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible.

        Canadian Forest has drilled several wells in the Foothills areas, which qualify for the Alberta Deep Gas Royalty Holiday Program. Wells qualify at a depth drilled in excess of 2500 meters. Canadian Forest is in receipt of credits from this program and will continue to monitor receipts for the remaining wells.

        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 Canadian territories. The Yukon, Northwest Territories and Nunavut governments recently signed a Northern Cooperation Accord for the purpose of cooperating to seek jurisdiction over the oil and gas resources in these territories. If jurisdiction over the oil and gas resources in these territories were to be transferred to the territorial governments, 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

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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 finalizing the commercial discovery licenses and production licenses for the wells to be produced. Until the particulars for these licenses and the related spacing units are finalized, Canadian Forest's share of production cannot be finally determined.

        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 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 which are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. These laws and regulations may, in certain circumstances, impose "strict liability" for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. These laws and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. 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 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 under rules it issued in August 1998 pertaining to offshore facilities

9

covered by OPA. 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. 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 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.

        Forest generates wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended (commonly referred to as RCRA) and comparable state statutes. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes. Moreover, certain oil and gas exploration and production wastes generated by Forest that are currently exempt from treatment as "hazardous waste" may in the future be designated as "hazardous wastes" and therefore be subject to more rigorous and costly operating and disposal requirements.

        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, RCRA, and analogous state laws, and we potentially could be required to remediate such properties.

        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. A breach of such legislation may result in the imposition of fines and penalties.

        In Alberta, environmental compliance has been governed by the Alberta Environmental Protection and Enhancement Act (AEPEA) since September 1, 1993. In addition to replacing a variety of older

10

statutes which related to environmental matters, AEPEA also imposes certain environmental responsibilities on oil and natural gas operators in Alberta and in certain instances also imposes greater penalties for violations.

        British Columbia's Environmental Assessment Act became effective June 30, 1995. This legislation rolls the previous processes for the review of major energy projects into a single environmental assessment process which contemplates public participation in the environmental review.

        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 and to implement appropriate compliance procedures. We also employ an environmental director whose responsibilities include causing our operations to be carried out in accordance with applicable environmental guidelines and implementing adequate 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 may contain "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, 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."

        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;



•

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

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•

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 and the interpretation of such data by our reservoir engineers. As a result, estimates made by different engineers often vary from one another. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions could 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 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 any obligation 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 reserves and producing properties are located in the United States in the Gulf of Mexico, Louisiana, Texas, Oklahoma, Utah, Wyoming and Alaska and in Canada in Alberta and the Northwest Territories.

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 13 of Notes to Consolidated Financial Statements.

        Since January 1, 2001 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.

Production

        The following table shows our net liquids and natural gas production for the years ended December 31, 2001, 2000 and 1999:

13

Average Sales Prices

        The following table sets forth the average sales prices per MCF of natural gas and per barrel of liquids for the years ended December 31, 2001, 2000 and 1999:

(1)

Energy swaps were transacted to hedge the price of spot market volumes against price fluctuations. Certain of these arrangements have been designated as cash flow hedges. Hedged natural gas volumes were 42,870 MMCF, 53,078 MMCF and 32,481 MMCF for the years ended December 31, 2001, 2000 and 1999, respectively. Hedged oil and condensate volumes were 3,742,500 barrels, 6,953,000 barrels and 2,075,000 barrels for 2001, 2000 and 1999, respectively. The aggregate net realized gains (losses) under our hedging arrangements were $22,781,000, $(129,091,000) and $(8,684,000), respectively, for the years ended December 31, 2001, 2000 and 1999 and were accounted for as increases (reductions) to oil and gas sales. We also realized a gain of $11,556,000 in 2001 related to derivative instruments that did not qualify as cash flow hedges under the provisions of SFAS No. 133 adopted January 1, 2001. This gain was recorded as other income rather than oil and gas revenue and has not been given effect in the average sales prices shown above.

14

Productive Wells

        The following summarizes our total gross and net productive wells at December 31, 2001:

(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 22 dual completions in the United States and six 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.

15

Developed and Undeveloped Acreage

        Forest held acreage as set forth below at December 31, 2001 and 2000. 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 3 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.

        Undeveloped acreage decreased at December 31, 2001 compared to December 31, 2000 primarily as a result of the sale of interests in Tunisia and Australia. Approximately 1% of our net undeveloped acreage at December 31, 2001 is held under leases that have terms that will expire in 2002, if not extended by production activities, and approximately 1.5% of net undeveloped acreage will expire in 2003 if not extended by production.

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Drilling Activity

        Forest drilled gross and net exploratory and development wells during the years ended December 31, 2001, 2000 and 1999 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, 2001 Forest and its subsidiaries had 22 exploratory wells (11.0 net) and 14 development wells (6.5 net) that were in the process of being drilled.

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Delivery Commitments

        At December 31, 2001, the ProMark Netback Pool had entered into fixed price contracts to sell natural gas at the following quantities and weighted average prices:

        Canadian Forest, as one of the producers in the ProMark Netback Pool, is obligated to deliver a portion of this gas. In 2001 Canadian Forest supplied 39% of the gas for the ProMark Netback Pool. Approximately 63% of Canadian Forest's natural gas production was sold through the ProMark Netback Pool in 2001.

        In addition to its commitments to the ProMark Netback Pool, Canadian Forest has term contracts to sell .6 BCF of natural gas annually from 2002 through 2006 at prices increasing ratably from $3.68 CDN per MCF in 2002 to $4.27 CDN per MCF in 2006.

        There were no long-term delivery commitments in the United States as of December 31, 2001.

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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 ultimate 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 ultimate 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. 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.

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, 2001.

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Item 4A.    Executive Officers of Forest

        The following persons were serving as executive officers of Forest as of February 28, 2002.

20

(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, except for Mr. Clark as noted above.

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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, 2002, there were 46,823,509 outstanding shares of our Common Stock held by 1,825 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 closing sales prices of the Common Stock on the New York Stock Exchange composite tape during each fiscal quarterly period of 2000 and 2001. On December 7, 2000, Forest completed a 1-for-2 reverse stock split, and periods prior to December 2000 have been restated giving retroactive effect to this stock split. There were no dividends declared on the Common Stock in 2000 or 2001. On February 28, 2002, the closing price of Forest Common Stock was $25.69.

Warrants

        Forest has three series of warrants outstanding, which are each quoted on the NASDAQ Bulletin Board. At February 28, 2002, Forest had outstanding 232,517 warrants expiring on February 15, 2004 (the 2004 Warrants), which were held by 509 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. On February 28, 2002, the closing price of the 2004 Warrants was $13.75. The table below reflects the high and low closing sales prices of the 2004 Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2000 and 2001.

        At February 28, 2002, Forest also had outstanding 232,922 warrants expiring on February 15, 2005 (the 2005 Warrants), which were held by 510 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. On February 28, 2002, the closing price of the 2005 Warrants was $6.90. The table below reflects the high and

22

low closing sales prices of the 2005 Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2000 and 2001.

        At February 28, 2002, Forest also had outstanding 1,773,885 subscription warrants (the Subscription Warrants), which were held by 13 holders of record. 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 the exercise price for a period of 30 consecutive trading days. 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. On February 28, 2002, the closing price of the Subscription Warrants was $15.00. The table below reflects the high and low closing sales prices of the Subscription Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2000 and 2001.

        During 2001, Forest issued 706 shares of common stock pursuant to the exercise of warrants. 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.

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) certain restrictive provisions in the Indentures executed in connection with Canadian Forest's 8³/4% Senior Subordinated Notes due September 15, 2007, which are guaranteed by Forest, Forest's 10¹/2% Senior Subordinated Notes due 2006, Forest's 8% Senior Notes due 2008 and Forest's 8% Senior Notes due 2011, and (iii) our credit facilities dated as of December 7, 2000 with JPMorgan Chase and J.P. Morgan Bank Canada.

        Forest has not paid dividends on its Common Stock during the past five years and does not 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 3 and 6 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, 2001. 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. 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, and income of the combined company includes income of Forest and Forcenergy for the entire year. 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.

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Item 6.    Selected Financial and Operating Data (Continued)

25

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.

        The following discussion and analysis should be read in conjunction with Forest's 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, and income of the combined company includes income of Forest and Forcenergy for the entire year. 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.

Results of Operations

        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.

        Net earnings for 2000 were $130,608,000 compared to net earnings of $19,043,000 in 1999. The improvement in earnings was due primarily to higher production volumes resulting from the merger with Forcenergy and higher product prices.

        Marketing and processing revenue increased by 5% to $303,527,000 in 2001 from $288,133,000 in 2000 and the related marketing and processing expense increased by 5% to $300,062,000 in 2001 from $285,039,000 in the previous year. The earnings contribution reported for marketing and processing activities increased 12% to $3,465,000 in 2001 from $3,094,000 in 2000. The increase is due primarily to an increase in volumes marketed by ProMark in 2001 as well as higher margins on arrangements where the margin was determined on a percentage of natural gas prices.

        Marketing and processing revenue increased by 73% to $288,133,000 in 2000 from $166,283,000 in 1999, and the related marketing and processing expense increased by 75% to $285,039,000 in 2000 from $162,617,000 in the previous year. The gross margin for marketing and processing activities decreased to $3,094,000 in 2000 from $3,666,000 in 1999. The decrease in the margin was due primarily to lower margins on processing activities in the United States.

        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 received for natural gas and liquids in 2001 increased 33% and 4%, respectively, compared to the average sales prices received in 2000. Production volumes for natural gas and liquids on an MCFE basis 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 sales revenue increased by 222% to $624,925,000 in 2000 from $193,841,000 in 1999 due primarily to higher production volumes resulting from the merger with Forcenergy and higher oil and gas

26

prices. The average sales prices received for natural gas and liquids in 2000 increased 48% and 66%, respectively, compared to the average sales prices received in 1999. Production volumes on an MMCFE basis were 107% higher in 2000 compared to 1999.

        Oil and gas production expense includes costs incurred to operate and maintain wells and related equipment and facilities, including product transportation costs, production taxes and ad valorem taxes. In 2001 production expense increased 33% to $186,250,000 from $140,218,000 in 2000. On an MCFE basis, production expense was $1.08 per MCFE in 2001 compared to $.77 in 2000. The increase in the per-unit rate 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.

        Oil and gas production expense increased 185% to $140,218,000 in 2000 from $49,145,000 in 1999. On an equivalent basis, production expense was $.77 per MCFE in 2000 compared to $.56 per MCFE in 1999. The increases in expense and per-unit rates were primarily the result of higher operating costs associated with Forcenergy properties, higher production taxes and increased workover activity.

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        Production volumes and weighted average sales prices for the years ended December 31, 2001, 2000 and 1999 were as follows:

(1)

Energy swaps were transacted to hedge the price of spot market volumes against price fluctuations. Certain of the arrangements have been designated as cash flow hedges. Hedged natural gas volumes were 42,870 MMCF, 53,078 MMCF and 32,481 MMCF in 2001, 2000 and 1999, respectively. Hedged oil and condensate volumes were 3,742,500 barrels, 6,953,000 barrels and 2,075,000 barrels in 2001, 2000 and 1999, respectively. The aggregate net realized gains (losses) under energy swap agreements were $22,781,000, $(129,091,000) and $(8,684,000), respectively, for the years ended December 31, 2001, 2000 and 1999 and were accounted for as increases (reductions) to oil and gas sales. We also realized a gain of $11,556,000 in 2001 related to derivative instruments that did not qualify as cash flow hedges under the provisions of SFAS No. 133 adopted January 1, 2001. This gain was recorded as other income rather than oil and gas revenue and has not been given effect in the average sales prices shown below.

        General and administrative expense decreased 14% to $30,514,000 in 2001 compared to $35,580,000 in 2000. General and administrative expense was $.18 per MCFE and $.20 per MCFE in 2001 and 2000, respectively. The decrease in the rate for the year was due primarily to operating synergies associated with the merger with Forcenergy, as well as higher recoveries of overhead related to exploration and

28

development activities and production operations. General and administrative expense increased 132% to $35,580,000 in 2000 compared to $15,362,000 in 1999. General and administrative expense was $.20 per MCFE and $.17 per MCFE in 2000 and 1999, respectively. The increase in the rate was due primarily to general and administrative expenses related to Forcenergy operations in 2000.

        Total overhead costs decreased 8% in 2001 compared to 2000 and increased 134% in 2000 compared to 1999. The decrease in 2001 was due to operating synergies and higher overhead recoveries; the increase in 2000 compared to 1999 was due primarily to addition of Forcenergy operations. The amount of overhead capitalized increased to 41% of total overhead in 2001 compared to 37% in 2000 and 1999. 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 $1,376,000, $1,386,000 and $2,059,000 in 2001, 2000 and 1999, respectively, related to marketing and processing 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 increased 6% 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. Depreciation and depletion expense increased 141% to $212,480,000 in 2000 from $88,190,000 in 1999 due primarily to increased production as a result of the merger with Forcenergy and an increased per-unit rate. The depletion rate increased to $1.15 per MCFE in 2000 compared to $.96 per MCFE in 1999, due primarily to higher finding costs in 2000 and higher estimated future development costs in the inflationary environment for oilfield services at that time.

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

        The decrease during 2001 compared to 2000 was due primarily to wells in progress in Alaska at December 31, 2000 for which reserves were recorded in 2001, offset partially by costs incurred for wells in progress and lease acquisitions in Canada and exploration activities in South Africa. The increase in 2000

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compared to 1999 was due primarily to wells in progress in Alaska and exploration activities in South Africa, offset partially by surrendered and abandoned leases in the United States and Canada.

        In 2001, Forest recorded an impairment of international oil and gas properties of $18,072,000. Of this amount, approximately $10,000,000 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.

        Writedowns of the full cost pools in the United States and Canada may be required if oil and gas prices decline, undeveloped property values decrease, estimated proved reserve volumes are revised downward or estimated future development costs in the respective full cost pools increase such that the book values of our properties exceed the discounted future net cash flows from the reserves attributable to each of the cost pools. Additional impairments of international oil and gas properties may also be required in the future.

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

        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. Other income of $2,629,000 in 1999 consisted primarily of a gain from the sale of gas processing facilities in Canada.

        Interest expense of $49,910,000 in 2001 decreased $10,359,000 or 17% compared to 2000 due to lower average debt balances, lower rates on variable and fixed rate debt and a net gain of $1,163,000 recognized under interest rate swap agreements. Interest expense of $60,269,000 in 2000 increased $19,396,000 or 47% compared to 1999 due primarily to the merger with Forcenergy.

        Foreign currency translation gains (losses) were $(7,872,000) in 2001, $(7,102,000) in 2000 and $10,561,000 in 1999. Foreign currency translation gains and losses relate to translation by Canadian Forest of the 8³/4% Senior Subordinated Notes, and are attributable to the increases and decreases in the value of the Canadian dollar relative to the U.S. dollar during the period. The value of the Canadian dollar was $.6279 per $1.00 U.S. at December 31, 2001 compared to $.6672 at December 31, 2000, $.6924 at December 31, 1999 and $.6535 at December 31, 1998. Forest is required to recognize the noncash foreign currency translation gains or losses related to the 8³/4% Senior Subordinated Notes because the debt is denominated in U.S. dollars and the functional currency of Canadian Forest is the Canadian dollar.

        The realized gain on oil and gas derivative instruments of $11,556,000 in 2001 was due primarily to oil and natural gas prices being, in the aggregate, lower than the prices established in the related derivative contracts. This gain was partially offset by a $2,255,000 writeoff of 100% of the asset value of derivative contracts where Enron was the counterparty. There was a net unrealized gain on derivative instruments of $376,000 in 2001 representing primarily the excess of the fair value over the intrinsic value of options designated as hedges. The realized and unrealized gains on derivative instruments were recorded separately in non-operating income since the instruments do not qualify as hedges under the provisions of SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," which Forest adopted on January 1, 2001.

        Forest recorded current income tax expense of $2,365,000 in 2001 compared to current tax expense of $1,666,000 in 2000 and a current tax benefit of $2,921,000 in 1999. The increases in 2001 and 2000 are due primarily to increased pre-tax profitability and higher state tax provisions. Deferred income tax expense was $77,212,000 in 2001 compared to $4,400,000 in 2000 and $407,000 in 1999. The increase in 2001 was due primarily to increased pre-tax profitability and to the recognition in 2000 of the future income tax

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benefit of previously unrecognized deferred tax assets. The increase in 2000 compared to 1999 was due primarily to increased pre-tax profitability.

        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. The extraordinary loss on extinguishment of debt of $598,000 in 1999 resulted from redemption of $8,631,000 remaining principal amount of 11¹/4% Senior Subordinated Notes at 103.792% of par value.

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 issuance of debt and equity securities, when market conditions permit, and through the use of bank credit facilities and cash provided by operating activities. 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 continue to 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 of Forest, 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.

        Securities Issued.    In June 2001, we issued $200,000,000 principal amount of 8% Senior Notes due 2008 at par for proceeds of $199,500,000 (net of related issuance costs). The net proceeds were used to repay a portion of our U.S. credit facility.

        In October 2001, we issued an additional $65,000,000 principal amount of 8% Senior Notes due 2008 at 99% of par for proceeds of $63,550,000 (net of related issuance costs). The net proceeds were initially used to repay a portion of our U.S. credit facility. Subsequently, borrowings were made under the U.S. credit facility to repurchase approximately $58,000,000 principal amount of our 8³/4% Senior Subordinated Notes.

        In December 2001, we issued $160,000,000 principal amount of 8% Senior Notes due 2011 at par for proceeds of $157,500,000 (net of related issuance costs). The net proceeds were used to repay a portion of our U.S. credit facility, to repurchase approximately $8,820,000 principal amount of our 10¹/2% Senior Subordinated Notes and for general corporate purposes.

        Securities Repurchased.    During 2001, we repurchased 2,074,300 shares of our common stock at an average price of $26.90 per share, $129,152,000 principal amount of 8³/4% Senior Subordinated Notes and $8,820,000 principal amount of 10¹/2% Senior Subordinated Notes.

        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. 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. As of December 31, 2001, under the most restrictive of these covenants and financial tests, our available borrowing amount under the credit facilities was estimated to be approximately $385,000,000. If the rating on our bank credit facilities is downgraded, the available borrowing amount under the credit facilities would be determined by a borrowing base subject to semi-annual re-determination. Reduction of the borrowing base could result in a

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substantial reduction in the available borrowing amount. In addition, we could be obligated to pledge additional assets as collateral.

        Our U.S. credit facility is secured by a lien on, and a security interest in, a portion 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.

        At December 31, 2001, the outstanding borrowings under the U.S. credit facility were $19,000,000 and there were no outstanding borrowings under the Canadian Forest credit facility. At March 1, 2002, the outstanding borrowings under the U.S. credit facility were $61,000,000 with an average effective interest rate of 3.123%, and there were outstanding borrowings under the Canadian credit facility of $1,246,000 with an average effective interest rate of 3.875%. At March 1, 2002, Forest had used the credit facilities for letters of credit in the amount of $4,523,000 U.S. and $3,112,000 CDN.

        Credit Ratings.    Currently, our credit facilities, our senior subordinated notes and our senior notes are separately rated by two ratings agencies, Moody's Investor Services and Standard & Poor's (S&P's). In addition, S&Ps 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 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 rating. For example, if our credit rating is downgraded from its current level, we will be subject to tests to determine our borrowing base and the amount of credit that is available. The agreements governing our senior subordinated notes and our senior notes do not include adverse triggers that are tied to our credit rating. 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 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.

        Contractual Obligations.    The following table summarizes our contractual obligations as of December 31, 2001:

(1)

Long-term debt consists of our U.S. and Canadian lines of credit, subordinated notes and senior subordinated notes. For a more detail discussion of our long-term debt, see Item 7a, Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk and Note 3 of Notes to Consolidated Financial Statements.

(2)

Consists primarily of leases for office space.

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(3)

Consists primarily of firm commitments for gathering, processing and pipeline capacity. Commitments in areas that have secondary markets may be mitigated in the future if firm capacities are no longer required. ProMark, on behalf of the ProMark Netback Pool, has firm commitments for pipeline capacity of approximately $56,712,000. Canadian Forest, as one of the producers in the ProMark Netback Pool, supplied 39% of the gas to the ProMark Netback Pool in 2001.

(4)

Purchase commitments associated with ProMark's trading activities were excluded from the table as all purchase commitments are immediately offset by sales commitments. For a more detailed discussion of ProMark's trading activities, see Part II, Item 7a, Qualitative and Quantitative Disclosures About Market Risk—Commodity Price Risk and Note 8 of Notes to Consolidated Financial Statements.

(5)

Consists of unconditional obligations under work programs in Albania and Gabon. In addition to these unconditional obligations, we are committed to make $55,589,000 of capital expenditures over the next six years pursuant to the terms of other foreign concessions. Nonperformance under any concession agreement could result in the loss of concession rights.

        Forest also makes delay rental payments to lessors during the primary terms of oil and gas leases to delay drilling of wells, usually for one year. Although we are not obligated to make such payments, discontinuing them would result in the loss of the oil and gas lease. Our total maximum commitment under these leases, through 2012, totaled $4,912,000 as of December 31, 2001.

Commercial Commitments.

        Guarantees.    We hold a 30% equity interest in an affiliate that owns and operates a petroleum pipeline system within the Cook Inlet area of Alaska. In our capacity as a shareholder, we have provided a guarantee for our proportionate interest of the obligations of this affiliate under a credit facility. At December 31, 2001, the maximum amount available under the credit facility was $24,000,000 and $10,500,000 was outstanding. Our proportionate share of the amount outstanding was $3,150,000. This credit facility will expire in January 2003. In addition, in our capacity as a shareholder, we may have other contingent obligations in the event the affiliate experiences cash deficiencies or is unable to meet its indemnification requirements or its obligations to the operator of the pipeline. We are unable to predict or quantify the amount of these obligations.

        Surety Bonds.    In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including governmental agencies. As of February 28, 2002, we have obtained surety bonds from a number of insurance and bonding institutions covering certain of our operations in the United States and Canada in the aggregate amount of approximately $24,200,000. In connection with their administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee's plugging and abandonment liabilities. The MMS reviews this information and applies certain financial tests including, but not limited to, current asset and net worth tests. The MMS determines whether each lessee is financially capable of paying the estimated costs of such plugging and abandonment liabilities. We annually provide the MMS with our financial information. If we do not satisfy the MMS requirements, we could be required to post supplemental bonds. In the past, Forest has not been required to post supplemental bonds; however, we cannot assure you that we will satisfy the financial tests and remain on the list of MMS lessees exempt from the supplemental bonding requirements. We cannot predict or quantify the amount of any such supplemental bonds or the annual premiums related thereto, but the amount could be substantial.

        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 for capitalized exploration and development costs. Settlement of these payables is funded by cash flow from operations or, if necessary, by drawdowns on long-term bank

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credit facilities. For cash management purposes, drawdowns on the credit facilities are not made until the due dates of the payables.

        Forest had a working capital deficit of approximately $38,333,000 at December 31, 2001 compared to a deficit of approximately $1,109,000 at December 31, 2000. The increase in the deficit was due primarily to a decrease in accounts receivable as a result of lower oil and gas prices, offset partially by an increase in other short-term assets, primarily derivative instruments.

        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 $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. 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.