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TABLE OF CONTENTS

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

FORM 10-K

Commission File Number: 1-13515

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

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

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

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

        The aggregate market value of the voting stock held by non-affiliates as of June 30, 2003, the last business day of the registrant's most recently completed second fiscal quarter, was $1,023,721,464 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

        There were 53,733,381 shares of the registrant's Common Stock, Par Value $.10 Per Share outstanding as of February 27, 2004.

        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 13, 2004, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

PART I

        Throughout this Form 10-K, we make statements that may be deemed "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. See Item 1, Business—Forward-Looking Statements, below. Historical statements made herein are accurate only as of the date of filing this Form 10-K with the Securities and Exchange Commission and may be relied upon only as of that date.

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

Item 1. Business

The Company

        Throughout this Form 10-K we use the terms "Forest", "Company", "we", "our" and "us" to refer to Forest Oil Corporation and its subsidiaries. Forest is an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and liquids in North America and selected international locations. Forest was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969. On December 31, 2003, we had 458 employees. Our common stock, par value $.10 per share, is traded on the New York Stock Exchange under the symbol "FST."

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

        In 2003, we operated in five business units: the Gulf Coast, Western United States, Alaska, Canada and International. We conduct exploration and development activities in each of our North American core areas and in selected international locations. Our proved reserves and producing properties are all located in North America. At December 31, 2003, approximately 88% of our proved oil and gas reserves were in the United States and approximately 12% in Canada.

        For information with respect to our reserves, see Item 2, Properties, of this Form 10-K. For financial information relating to our geographic and operational segments, see Note 12 of Notes to Consolidated Financial Statements of this Form 10-K.

Exploration and Production Activities

        At December 31, 2003, we held interests in approximately 1,989 net oil and gas wells in the United States and Canada. During 2003, we drilled a total of 129 gross wells, 25 of which were injection wells. Of the remaining 104 wells, 23 were exploration and 81 were development. Our 2003 drilling program achieved an 82% success rate. During 2003, we sold 149 BCFE or an average of 409 MMCFE per day. Approximately 87% of our total production in 2003 was in the United States and approximately 13% in

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Canada. Our operations conducted through our U.S. and Canadian business units are summarized below.

2003 Exploration and Production
Activities in North America

(1)

Our Gulf Coast business unit was formed in the first quarter of 2003 by combining our Gulf of Mexico Offshore Region and our Gulf Coast Onshore Region to achieve greater efficiencies.

(2)

During the fourth quarter of 2003, we recorded significant downward revisions of our estimated proved reserves, primarily in the Redoubt Shoal Field in the Cook Inlet, Alaska. See Item 2, Properties—Reserves, of this Form 10-K.

        International Business Unit.    Forest also evaluates oil and gas opportunities in countries outside North America. We currently hold concessions in South Africa, Gabon, Switzerland, Germany, Albania, Italy and Romania, as well as overriding royalty interests in certain other areas. Although we have had some successful wells in South Africa, to date Forest has not recorded any proved reserves related to its international concessions. The book value of these international interests at December 31, 2003 represents approximately 1% of our total assets.

        During 2003, we entered into participation agreements in connection with our exploration activities in South Africa and Germany. Pursuant to these agreements, Forest receives partial cost reimbursements and is carried for drilling costs in exchange for a reduced interest in the concessions.

        During 2003, the International business unit drilled three wells in South Africa, of which one was tested, and one well in Gabon which was not productive.

Sales and Markets

        Oil and Gas Operations.    Forest's U.S. production of natural gas is generally sold at the wellhead in the areas where it is produced or at nearby "pooling points". Our U.S. natural gas production is

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typically sold on a month to month basis in the spot market using published indices. The credit-worthiness of various purchasers is an important consideration in choosing purchasers at a given delivery point. We believe that the loss of one or more of our current natural gas spot purchasers would not have a material adverse effect on Forest's business in the United States because any individual spot purchaser could be readily replaced by another spot purchaser who would pay approximately the same sales price. Sales to BP Energy Company and Occidental Petroleum Corporation, purchasers of natural gas in the Gulf Coast, represented approximately 10% each of our total revenue in 2003.

        Natural gas production in Canada has been sold by Canadian Forest Oil Ltd. ("Canadian Forest") either through a netback pool (the "Canadian Netback Pool") administered by Producers Marketing, Ltd. (ProMark) on behalf of Canadian Forest, or through Canadian Forest's direct sales contracts or under spot contracts. In 2003, Canadian Forest sold approximately 71% of its natural gas production through the Canadian Netback Pool. As described below, on March 1, 2004, the assets of ProMark were sold to a third party.

        Our U.S. production of oil and natural gas liquids is typically sold under short-term contracts at prices based upon posted field prices. Canadian oil and natural gas liquids are typically sold under short-term contracts at prices based upon posted prices at Alberta pipeline and processing hubs, netted back to the field. Except in Alaska, our liquids production is generally sold at the wellhead. Our Alaskan oil production, which represented approximately 14% of our total 2003 production, is currently being sold at the terminal to one local refiner, Tesoro Alaska Petroleum Company and its affiliate. The oil is transported to a terminal by a pipeline company that is 40% owned by Forest. The primary term of our contract with this refiner expires on December 31, 2004, but will be renewed automatically from year to year thereafter unless terminated by either party upon written notice 60 days prior to expiration. Sales to this purchaser represented 15% of our total revenue in 2003.

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

        Canadian Netback Pool Sales. The Canadian Netback Pool, which was formerly administered by ProMark, matches major end users with providers of gas supply through firm transportation arrangements, and uses a netback pricing mechanism to establish the average, or "blended," wellhead price paid to producers. Under this netback arrangement, producers receive the blended well head price less related transportation and other direct costs. The administrator charges a marketing fee to the pool participant producers for marketing and administering the gas supply pool.

        The Canadian Netback Pool gas sales in 2003 averaged 69 MMCF per day, of which Canadian Forest supplied approximately 29 MMCF per day or 42%. Approximately 22% of the volumes sold in the Canadian Netback Pool in 2003 were sold at fixed prices. The remainder of the volumes sold were priced in a variety of ways, including prices based on published indices. The weighted average price realized by Canadian Forest for volumes sold through the Canadian Netback Pool in 2003 was $4.51 CDN per MCF, compared to an average price of $5.31 CDN per MCF for volumes sold through other channels.

        On March 1, 2004, we sold the gas marketing business of ProMark to Cinergy Canada, Inc. (Cinergy). Immediately prior to the closing, ProMark was amalgamated with Canadian Forest. Following the closing, all employees of ProMark became employees of Cinergy. Under the terms of a contract administration agreement, Cinergy will administer the Canadian Netback Pool. In addition, the parties entered into a separate agreement under which Cinergy will purchase all of Canadian Forest's natural gas that is not otherwise subject to existing contracts for a period of five years. Canadian Forest's obligation to deliver gas to the pool is not expected to change as a result of the sale. For further information concerning the ProMark sale, see Note 3 of Notes to Consolidated Financial Statements of this Form 10-K.

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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 acreage position and property base, 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. Some of these 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 a variety of factors such as the price of competitive fuels, the spot price at the Henry Hub, and local competition for pipeline capacity in the specific markets in which such gas is produced. Declines in crude oil prices or natural gas prices adversely impact Forest's activities. Our financial position and resources may also adversely affect our competitive position. Lack of available funds or financing alternatives can prevent us from executing our operating strategy and from deriving the expected benefits therefrom. For further information concerning Forest's financial position, see Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in this Form 10-K.

Regulation

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

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

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        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 enact price controls in the future.

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

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

        The Outer Continental Shelf Lands Act (OCSLA) requires that all pipelines operating on or across the Outer Continental Shelf (the OCS) provide open-access, non-discriminatory service. Commencing in April 2000, FERC issued Order No. 639 and subsequent orders (collectively, Order No. 639), which imposed certain reporting requirements applicable to "gas service providers" operating on the OCS concerning their prices and other terms and conditions of service. The purpose of Order No. 639 is to provide regulators and other interested parties with sufficient information to detect and to remedy discriminatory conduct by such service providers. FERC has stated that these reporting rules apply to OCS gatherers and has clarified that they may also apply to other OCS service providers including platform operators performing dehydration, compression, processing and related services for third parties. The U.S. District Court overturned the FERC's reporting rules as exceeding its authority under OCSLA. The FERC has recently appealed this decision, which was affirmed on appeal through petitions to the U.S. Supreme Court and are pending. We cannot predict whether and to what extent these regulations might be reinstated, and what effect, if any, they may have on our financial condition or operations. The rules, if reinstated, may increase the frequency of claims of discriminatory service, may decrease competition among OCS service providers and may lessen the willingness of OCS gathering companies to provide service on a discounted basis.

        Certain operations that we conduct are on federal oil and gas leases, which are administered by the Bureau of Land Management (BLM) and the Minerals Management Service (MMS). These leases contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). Many onshore leases contain stipulations limiting activities that may be conducted on the lease. The stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban any surface activity. For offshore operations, lessees must obtain MMS approval for exploration,

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development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling. Lessees must also comply with detailed BLM or MMS regulations, as applicable, governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of OCS wells, calculation of royalty payments and the valuation of production for this purpose and removal of facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the BLM or MMS, as applicable, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

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

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

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

        Oil and natural gas exported from Canada is subject to regulation by the National Energy Board (NEB), an independent federal regulatory agency and the government of Canada. Exporters are free to negotiate with purchasers, provided that the export contracts must meet certain criteria prescribed by the NEB. Natural gas exports for a term of less than two years or for a term two to 20 years (in quantities of more than 30,000 cubic meters per day), must be made pursuant to a NEB order. Oil exports may be made pursuant to export contracts with terms not exceeding one year, in the case of light crude, and not exceeding two years, in the case of heavy crude, provided that an order approving any export has been obtained from the NEB. Any natural gas or oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the government of Canada. The provinces in which our operations are located, mainly Alberta and British Columbia, also regulate the volume of natural gas which may be removed for consumption elsewhere.

        In addition, each province has regulations that govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from private lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are

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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.

        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 (25-75%) to a maximum of $2 million CDN of Alberta Crown royalties payable for each producer. Canadian Forest is eligible for ARTC credits only on eligible properties acquired and wells drilled after the change of control that occurred when Canadian Forest was acquired by Forest. Production from properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible.

        In British Columbia, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the quantity of oil produced and the value of the oil. Oil produced from newly discovered pools may be exempt from the payment of a royalty for the first 36 months of production. The royalty payable on natural gas is determined by a sliding scale based on the greater of the amount obtained by the producer and a prescribed minimum price. The minimum royalty for natural gas produced in association with oil is 8% and for other natural gas is 15%.

        The federal government has jurisdiction over the exploration and development of oil and gas resources in the Northwest Territories of Canada. The federal regulatory regime reflects the extended timelines and increased capital expenditures inherent in working in the northern environment, providing for work commitments and work deposits coupled with the suspension and/or reimbursement of rentals and royalties at earlier developmental stages. This regime is subject to change as development in the Northwest Territories evolves toward a more conventional model. It is also possible that jurisdiction over the oil and gas resources in these territories could be transferred to the territorial governments. We are unable to predict whether any evolution or transfer of jurisdiction to the territorial governments would affect our activities in the Northwest Territories.

        Our right to produce oil and gas from the Northwest Territories is subject to conversion of certain instruments (i.e., exploration licenses or significant discovery licenses) into production licenses. The right to such conversion is subject to an application process and regulatory approval. In addition, the right to produce may be dependent on the negotiation of a pooling agreement or the imposition of a forced pooling order. Until the finalization of such agreement or order, it is not possible to finally determine our production in such lands.

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

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        The Oil Pollution Act of 1990 (OPA) and regulations thereunder impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. A "responsible party" includes the owner or operator of a pipeline, vessel or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages from oil spills. OPA also requires operators of offshore OCS facilities to demonstrate to the MMS that they possess at least $35 million in financial resources that are available to pay for costs that may be incurred in responding to an oil spill. This financial responsibility amount can increase up to a maximum of $150 million if the MMS determines that a greater amount is justified based on specific risks posed by the operations or if the worst case oil-spill discharge volume possible at a facility exceeds applicable threshold volumes established by the MMS. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages, while the liability limits for onshore facilities are $350 million. Few defenses exist to the liability imposed by OPA.

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

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

        In Canada, the oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation that provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized with oil and gas industry operations. In

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addition, wells and facility sites must be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of fines and penalties, the revocation of licenses and authorizations or civil liability for pollution damage.

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

        We have established guidelines to be followed to comply with U.S. and Canadian environmental laws and regulations. We employ an environmental department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance against the costs of clean-up operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. In addition, any oil and gas activities conducted by us outside of North America are potentially subject to similar foreign governmental controls and restrictions pertaining to the environment. To date we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

        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.

        For further information regarding certain environmental matters, see Item 3, Legal Proceedings, in this Form 10-K.

Available Information

        Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to reports filed pursuant to Sections 13(a) and 15(d) of the Securities Exchange Act of 1934 are available on our website, www.forestoil.com, as soon as reasonably practicable after such reports are electronically filed with the Securities and Exchange Commission. In addition our corporate governance guidelines, code of ethics, and charters for the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee are also available on our website. Copies of the foregoing information is available to shareholders upon written request addressed to the attention of the Secretary of Forest at 1600 Broadway Street, Suite 2200, Denver, Colorado 80202.

Forward-Looking Statements

        The information in this Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts or present facts, that address activities, events, outcomes and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K, in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors.

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

•

estimates of our oil and gas reserves;



•

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;



•

the impact of political and regulatory developments;



•

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



•

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

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

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

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

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

Item 2. Properties

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

Reserves

        Information regarding Forest's proved and proved developed oil and gas reserves and the standardized measure of discounted future net cash flows and changes therein is included in Note 13 of Notes to Consolidated Financial Statements. See also Part II, Item 7, Management's Discussion and

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Analysis of Financial Condition and Results of Operations—Risk Factors—Estimates of oil and gas reserves are uncertain and inherently imprecise, for additional information regarding estimates of proved reserves.

        Since January 1, 2003 we have not filed any oil or natural gas reserve estimates or included any such estimates in reports to any Federal or foreign governmental authority or agency, other than the Securities and Exchange Commission (SEC) and the Department of Energy (DOE). There were no differences between the reserve estimates included in the SEC report, the DOE report and those included herein, except for production and additions and deletions due to the difference in the "as of" dates of such reserve estimates.

        Forest's estimated proved reserves were 1,296 BCFE at December 31, 2003 compared to estimated proved reserves of 1,560 BCFE at December 31, 2002. Approximately 62% of our estimated proved reserves at December 31, 2003 were natural gas and our estimated proved developed reserves represented approximately 75% of total estimated proved reserves.

        Forest's year-end 2003 estimates of proved reserves were independently reviewed by two independent petroleum engineering firms. Ryder Scott Company independently reviewed our estimates of the reserves attributable to certain properties in the United States and Canada, except the properties acquired by us on December 31, 2003 in the Permian Basin and South Texas, which were independently reviewed by DeGolyer and MacNaughton.

        In conducting an independent review of Forest's estimates of proved reserves each petroleum engineering firm prepared independent estimates of reserves for specific fields. The estimates prepared by each petroleum engineering firm were presented to Forest by field for oil, gas and natural gas liquids. The estimates prepared by the engineering firms were then compared to the estimates prepared by Forest in the aggregate on a gas equivalent basis. Together, these firms independently reviewed estimates relating to properties constituting approximately 88% of our reserves based on their discounted value and volumes. In the aggregate, for the properties reviewed, the estimates of proved reserve quantities prepared by the two independent petroleum engineering firms as part of their reviews were lower than Forest's estimates by approximately 8%. Upon consummation of their reviews, Ryder Scott Company and DeGolyer and MacNaughton each provided Forest with their opinions that Forest's estimates of proved reserves for the properties reviewed by them complied with the definitions and disclosure guidelines of the SEC.

        2003 Reserve Revisions.    During 2003 we revised downward our estimate of proved reserves by a total of approximately 473 BCFE. The downward revision of our estimates was due to information received from production results, drilling activity and other events that occurred primarily in the latter part of 2003. The revisions are not expected to have a material impact on our near-term hydrocarbon production volumes.

        Approximately 62% of the total revisions was attributable to the downward revision of our estimate of proved oil reserves in the Redoubt Shoal Field in the Cook Inlet, Alaska. We reduced our estimate of proved oil reserves associated with our Redoubt Shoal Field in Alaska from our 2002 year-end estimate by approximately 49 million barrels, or approximately 85% of the estimated proved oil reserves of this field as of December 31, 2002. Of this revision, approximately 36 million barrels were classified as proved undeveloped as of December 31, 2002. Our estimate of proved oil reserves attributable to the Redoubt Shoal Field was approximately 8 million barrels as of December 31, 2003. On December 31, 2003, Forest's net daily oil production at the Redoubt Shoal Field was approximately 1,650 barrels per day from three wells. On that date one well was shut in for pump repair.

        Production results in 2003 from Redoubt Shoal, which began production in December 2002, were lower than those originally estimated. In addition, data from wells drilled in 2003 in Redoubt Shoal,

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when integrated with pre-existing data, reflected significantly lower oil in place than the estimates at December 31, 2002, lower overall recovery efficiencies and economic cutoffs. During the second half of 2003 Forest undertook an integrated field study of the Redoubt Shoal Field examining the production performance, field data and well data for 2003 activity. The revision was a result of the study, after applying economic cutoffs. In addition to preparing and reporting its own internal estimates of proved reserves at Redoubt Shoal, Forest also engaged Ryder Scott Company to prepare independent estimates of proved reserves at Redoubt Shoal as of the end of 2003, 2002 and 2001.

        Cumulative investment in exploration, delineation and development of the Redoubt Shoal Field by Forest and its predecessor, Forcenergy Inc (Forcenergy), through December 31, 2003 was approximately $310 million. As of December 31, 2003, we estimated total future development capital expenditures, excluding abandonment, for the Redoubt Shoal Field to be approximately $53 million. This amount includes the remaining cost of implementing the water injection project described below.

        Forest's future development plans for the Redoubt Shoal Field currently include the implementation of a water injection project for the purpose of maintaining the average Hemlock reservoir pressure, conserving the natural energy of the reservoir and assisting oil recovery.

        Implementation of the water injection project is currently planned to begin within the next two years. Our current plans call for the drilling of two oil wells and one water injection well and the conversion of three wells from production to water injection, over several years.

        We also had downward revisions in our estimated proved reserves for other properties in the fourth quarter of 2003 totaling approximately 143 BCFE. These revisions were in addition to 36 BCFE of downward revisions to estimated proved reserves taken previously in 2003. These downward revisions are due to a variety of factors, including recent production performance and revised field development plans.

Production

        The following table shows our net liquids and natural gas production for the years ended December 31, 2003, 2002 and 2001:

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Average Sales Prices

        The following table sets forth production volumes and average sales prices per MCF of natural gas and per barrel of liquids for the years ended December 31, 2003, 2002 and 2001:

(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 49,990 MMCF, 36,050 MMCF, and 42,870 MMCF for the years ended December 31, 2003, 2002 and 2001, respectively. Hedged oil and condensate volumes were 4,597,500 barrels, 3,921,500 barrels, and 3,742,500 barrels for 2003, 2002 and 2001, respectively. These arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the effective portion of the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net gains (losses) related to our cash flow hedges were $(72,863,000), ($1,742,000), and $22,781,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Those arrangements that are not designated as cash flow hedges for accounting purposes are recorded as non-operating income or expense. Average sales prices have been adjusted to reflect effects of energy swaps and collars.

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Productive Wells

        The following summarizes our total gross and net productive wells at December 31, 2003:

(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 6 dual completions in the United States and 8 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.

Developed and Undeveloped Acreage

        Forest held acreage as set forth below at December 31, 2003 and 2002. A majority of the developed acreage is subject to mortgage liens securing our bank indebtedness. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Note 4 of Notes to Consolidated Financial Statements in this Form 10-K.

(1)

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

(2)

Undeveloped acres are 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.

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        Approximately 5% and 13% of our North American net undeveloped acreage at December 31, 2003 is held under leases that have terms that will expire in 2004 and 2005, respectively, if not extended by exploration or production activities.

        In addition, 36% and 13% of our International net undeveloped acreage is expected to be relinquished in 2004 and 2005, respectively, as part of contractual commitments in South Africa, Gabon and Albania.

Drilling Activity

        During the years ended December 31, 2003, 2002 and 2001, Forest drilled gross and net exploratory and development wells as set forth below. This information does not include wells drilled under farmout agreements, royalty interests ownership 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, 2003 Forest had 5 exploratory wells (2.3 net) and 8 development wells (3.1 net) that were in the process of being drilled.

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Delivery Commitments

        A significant portion of Canadian Forest's natural gas production in 2003 was sold through the Canadian Netback Pool which was administered by ProMark on behalf of Canadian Forest. The gas marketing business of ProMark was sold to Cinergy on March 1, 2004. Canadian Forest will continue to sell a significant portion of its natural gas production into the Canadian Netback Pool, which Cinergy will administer pursuant to a contract administration agreement. Also, under our agreement with Cinergy, Canadian Forest will sell and Cinergy will purchase for a period of five years all of Canadian Forest's natural gas that is not otherwise subject to the Canadian Netback Pool or existing contracts. Cinergy will pay for the natural gas based on published indices less applicable transportation costs. At December 31, 2003, the natural gas quantities and weighted average contract prices related to the fixed price contracts of the Canadian Netback Pool were as follows:

        As a producer in the Canadian Netback Pool, Canadian Forest will be paid a netback price that reflects all of the revenue from approved customers less the costs of delivery (including transportation, audit and shortfall makeup costs) and an administrator marketing fee.

        In 2003 Canadian Forest supplied 42% of the Canadian Netback Pool sales quantity; the amount supplied represented 71% of Canadian Forest's 2003 natural gas production. In order to satisfy its supply obligations to the Canadian Netback Pool, Canadian Forest may be required to cover its obligations in the market.

        The administrator of the Canadian Netback Pool, now Cinergy, is required to acquire gas in the event of a shortfall between the gas supply and market obligations. A shortfall could occur if a gas producer fails to deliver its contractual share of the supply obligations of the Canadian Netback Pool. The cost of purchasing gas to cover any shortfall is a cost of the Canadian Netback Pool. The prices paid for shortfall gas would typically be spot market prices and may differ from the prices received from customers of the Canadian Netback Pool. Higher spot prices would reduce the average price paid to the gas producers in the Canadian Netback Pool, including Canadian Forest.

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

        There were no long-term delivery commitments in the United States as of December 31, 2003.

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Item 3. Legal Proceedings

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

        Alaska Proceeding.    In May, 2002, Cook Inlet Keeper, a non-governmental third party, filed a challenge in the Superior Court in Anchorage, Alaska (the trial court) to the regulatory review and approval process for Forest's development and production phase of our Redoubt Shoal project (the Production Project). On February 2, 2004, the trial court ruled that certain legislation which became law in 2003 mooted Cook Inlet Keeper's challenge and, therefore, affirmed the State's approval of the Production Project. While we will continue our vigorous opposition to Cook Inlet Keeper's challenge, the outcome of the litigation is inherently difficult to predict with any certainty. However, the Company does not believe that this legal matter could have a material effect on the results of future periods in the event of an unfavorable outcome.

        Environmental Matters.    The Company is involved in a number of governmental proceedings in the ordinary course of business, including the environmental matters described below. Forest believes that the potential penalty for each of the proceedings described below could involve penalties in excess of $100,000. Forest believes, however, that mitigating circumstances will result in total monetary penalties of $150,000 to $300,000 for all three proceedings combined.

        Forest owns and operates a platform located in the Cook Inlet, Alaska. Discharges from the platform have on occasion exceeded the limits allowed by the EPA discharge permit. Forest recently received permission from the State of Alaska to inject the effluent into a disposal well rather than discharge it into the Cook Inlet.

        Forest also owns a non-operating working interest in the King Salmon platform in the Cook Inlet in Alaska. In September 2002, while injecting oil based drilling mud and cuttings into the annulus of the well, the operator observed an oil sheen on the water near the platform and ceased further injections. The U.S. Coast Guard initiated an enforcement action based on the apparent discharges into the Cook Inlet. In addition, the State of Alaska Department of Environmental Conservation has indicated that it may also initiate an enforcement action.

        In addition, Forest received a Findings of Violation for alleged violations of the Clean Water Act involving discharges from 1999 to 2002 from facilities in the Gulf of Mexico that were previously operated by Forcenergy. All alleged violations have been remedied.

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, 2003.

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Item 4A. Executive Officers of Forest

        The following persons were serving as executive officers of Forest as of March 1, 2004.

18

19

(1)

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

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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 27, 2004, there were 53,733,381 outstanding shares of our Common Stock held by 799 holders of record. The number of holders does not include the shareholders for whom shares are held in a "nominee" or "street" name.

        The table below reflects the high and low intraday sales prices of the Common Stock on the New York Stock Exchange composite tape during each fiscal quarterly period of 2002 and 2003. There were no dividends declared on the Common Stock in 2002 or 2003. On February 27, 2004, the closing price of Forest Common Stock was $25.95.

Warrants

        Forest's warrants are quoted on the NASDAQ Bulletin Board. At December 31, 2003, Forest had three series of warrants outstanding.

        2004 Warrants.    At December 31, 2003, Forest had outstanding 236,030 warrants expiring on February 15, 2004 (the 2004 Warrants), which were held by 422 holders of record. Each 2004 Warrant entitled the holder to purchase 0.8 shares of Common Stock for $16.67, or an equivalent per share price of $20.84. From January 1, 2004 through February 15, 2004, 210,337 warrants were exercised via both cash and cashless exercise provisions pursuant to which 151,938 shares of Common Stock were issued. On February 15, 2004, the remaining 2004 Warrants expired unexercised.

        2005 Warrants.    At February 27, 2004, Forest had outstanding 237,394 warrants expiring on February 15, 2005 (the 2005 Warrants), which were held by 425 holders of record. Each 2005 Warrant entitles the holder to purchase 0.8 shares of Common Stock for $20.83, or an equivalent per share price of $26.04. Forest's 2005 Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLZ.OB." On February 27, 2004, or the last day of activity prior thereto, the closing price of the 2005 Warrants was $2.31. The table below reflects the high and low intraday sales prices of the 2005 Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2002 and 2003.

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        Subscription Warrants.    At February 27, 2004, Forest also had outstanding 1,752,355 subscription warrants (the Subscription Warrants), which were held by 10 holders of record. Each Subscription Warrant entitles the holder to purchase 0.8 shares of Common Stock for $10.00, or an equivalent per share price of $12.50. The Subscription Warrants expire on March 20, 2010 or earlier upon notice of expiration by Forest if, after March 20, 2004, the market price of the Common Stock has exceeded 300% of the exercise price, or $37.50 per share, for a period of 30 consecutive trading days. Forest's Subscription Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLL.OB". On February 27, 2004, or the last day of activity prior thereto, the closing price of the Subscription Warrants was $13.00. The table below reflects the high and low intraday sales prices of the Subscription Warrants on the NASDAQ Bulletin Board during each fiscal quarter in 2002 and 2003.

        Forest's warrants were originally issued by Forcenergy in connection with its plan of reorganization under the Bankruptcy Code, and were converted into warrants to purchase Forest common stock pursuant to our merger with Forcenergy on December 7, 2000. The issuance of Forest common stock upon exercise of the warrants is exempt from registration under the Securities Act of 1933 pursuant to section 1145 of the Bankruptcy Code. During 2003, Forest issued 1,573 shares of common stock pursuant to the exercise of warrants.

Dividend Restrictions

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

        Forest has not paid dividends on its Common Stock during the past five years and does not presently anticipate that it will do so in the foreseeable future. The future payment of dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on Forest's earnings, capital requirements, financial condition and other relevant factors. There is no assurance that Forest will pay any dividends. For further information regarding our equity securities and our ability to pay dividends on our Common Stock, see Notes 4 and 6 of Notes to Consolidated Financial Statements.

        For equity compensation plan information, see Part III, Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, of this Form 10-K.

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PART II

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, 2003. 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 on the date of the merger. Income and expense amounts reported for the combined company for 2000 include amounts attributable to the operations of both Forest and Forcenergy for the entire year. Forcenergy was merged into Forest on the date of the merger and, accordingly, all amounts attributable to periods after the merger represent the operations of the combined entities. The results of operations of Forcenergy prior to December 31, 1999, the effective date of its reorganization and fresh-start reporting, are not included in the financial statements of the combined company. In conjunction with the merger with Forcenergy, Forest effected a 1-for-2 reverse stock split. Unless otherwise indicated, all share and per share amounts included herein give retroactive effect to this reverse stock split.

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(1)

Does not include estimated discounted asset retirement obligations of $63.7 million related to assets placed in service during the year ended December 31, 2003.

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

        All expectations, forecasts, assumptions and beliefs about our future financial results, condition, operations, strategic plans and performance are forward-looking statements, as described in more detail in Part I, Item 1, Business—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.

Overview

        We are an independent oil and gas company engaged in the acquisition, exploration, development and production of natural gas and liquids in North America and selected international locations. 2003 was a year mixed with successes and significant disappointments and a year in which we changed our corporate leadership and strategies.

2003 Highlights:

        The successes included:

•

better production performance (149 BCFE in 2003 vs. 144 BCFE in 2002),



•

significantly higher revenue (primarily as a result of higher production and oil and gas prices),



•

lower lease operating expenses ($4.5 million lower in 2003 than 2002 despite a $6 million increase in production and ad valorem taxes),



•

significantly higher net income (resulting from higher production, higher realized oil and gas prices and lower expenses),



•

continued drilling success on deep shelf prospects in the Gulf of Mexico, and



•

acquisitions totaling 322 BCFE of estimated proved reserves in properties located in the Gulf of Mexico, Gulf Coast, South Texas and the Permian Basin. These properties were acquired for a total of $391 million (net of taxes) or $1.22 per MCFE and will add to our production in 2004.

        Despite these successes, we experienced disappointing production performance and drilling results in a number of areas, the most significant of which was the Redoubt Shoal Field in the Cook Inlet of Alaska. The total downward revisions of estimated proved reserves taken in 2003 was 473 BCFE, of which approximately 62% was attributable to a downward revision of our estimated proved oil reserves at Redoubt Shoal Field. Proved reserves were 1,296 BCFE at year-end 2003, a year over year reduction of approximately 17%. See "—2003 Reserve Revisions" below.

        In 2003 we also experienced a leadership change and revised our strategies. In the third quarter of 2003, we named a new chief executive officer and split the CEO and Chairman of the Board positions, also naming a new non-executive Chairman. Our new leadership revised our strategies late in the third quarter. We established a four-point plan to achieve increased value for our investors, consisting of:

•

a focus on cost control,



•

reduced exposure to frontier exploration in favor of lower risk exploitation,



•

pursuit of asset acquisitions as an integral part of our investment program, and

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•

a focus on our financial strength to fund growth.

        We implemented our plan in the fourth quarter and acquired 244 BCFE of proved reserves in that quarter. These acquisitions now make up almost 20% of our proved reserve base.

        One of these strategies, the focus on our financial strength to fund growth, could be a distinct challenge. Over time, we would like to achieve a debt/capitalization percentage of 30-40%. As of December 31, 2003 our debt/capitalization percentage was 44%. When appropriate, we intend to access capital markets, including equity markets, to finance larger acquisitions and help us achieve our debt/capitalization goals.

2003 Reserve Revisions:

        During 2003 we revised downward our estimates of proved reserves by a total of approximately 473 BCFE. The downward revision of our estimates was due to information received from production results, drilling activity and other events that occurred primarily in the latter part of 2003. The revisions are not expected to have a material impact on our near-term hydrocarbon production volumes.

        Approximately 62% of the total revisions was attributable to the downward revision of our estimate of proved oil reserves in the Redoubt Shoal Field in the Cook Inlet, Alaska. We reduced our estimate of proved oil reserves associated with our Redoubt Shoal Field in Alaska from our 2002 year-end estimate by approximately 49 million barrels, or approximately 85% of the estimated proved oil reserves of this field as of December 31, 2002. Of this revision, approximately 36 million barrels were classified as proved undeveloped as of December 31, 2002. Our estimate of proved oil reserves attributable to the Redoubt Shoal Field was approximately 8 million barrels as of December 31, 2003.

        Cumulative investment in exploration, delineation and development of the Redoubt Shoal Field by Forest and its predecessor, Forcenergy, through December 31, 2003 was approximately $310 million. As of December 31, 2003, we estimated total future development capital expenditures, excluding abandonment, for the Redoubt Shoal Field to be approximately $53 million.

        We also had downward revisions in our estimated proved reserves for other properties in the fourth quarter of 2003 totaling approximately 143 BCFE. These revisions were in addition to 36 BCFE of downward revisions to estimated proved reserves taken previously in 2003. These downward revisions are due to a variety of factors, including recent production performance and revised field development plans.

        As a result of the revisions:

•

Our global borrowing base under our credit facilities was reduced from $575 million at December 31, 2003 to $480 million at March 4, 2004.



•

The rating agencies may downgrade our credit rating. In February 2004, following announcement of our downward reserve revisions, Forest was placed on "credit watch" by both rating agencies. A downgrade in our credit rating would increase the cost of amounts borrowed under our credit facility and could increase the cost and/or reduce the availability of any additional long-term debt.



•

There could be an increase in the cost or amount of credit support (insurance, letters of credit, bonds) required by our counterparties. We could also be required to agree to stricter debt covenants that would restrict our operating flexibility.

        We do not believe that the revisions to our estimates of proved reserves or the effects on our liquidity or financial condition will create an event of non-compliance with any of our debt covenants. See "Liquidity and Capital Resources" below.

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        As a result of the revisions, we are subject to writedowns of our U.S. and Canadian full cost pools under "ceiling test" limitations pursuant to full cost accounting at higher commodity price thresholds than we were prior to the revisions. If we were to record writedowns, shareholders' equity could be reduced significantly.

2004 Outlook:

        In executing our plan in 2004, we face a number of uncertainties and challenges. First, while we hedge the price risk for a portion of our production, oil and gas prices, which have a significant impact on our cash flow remain volatile and uncertain. Also, net income will be adversely impacted by the higher depletion expense resulting from our downward revisions to our estimate of proved reserves in 2003. While we believe that there will be a large number of oil and gas acquisition opportunities in 2004 and that we have the skills to make sound acquisitions, we also believe that the competition for these opportunities will be significant. In addition, we have made and will make changes in 2004 to our organization to enhance productivity. While we believe that these changes, over time, will improve our performance, they could, in the short run, negatively impact performance. The borrowing base under our bank facility has been reduced due to the downward revision of our estimates of proved reserves in 2003. We believe, however, that we have adequate liquidity to accomplish our exploration and development spending plan and to also make a meaningful amount of oil and gas property acquisitions. Forest's anticipated expenditures for exploration and development in 2004 are estimated to range from $275 million to $325 million.

        Overall, our outlook for 2004 is a positive one. We have changed our direction with four key strategies. The execution of tactics to accomplish these strategies is well underway. We made two sizeable acquisitions in the fourth quarter of 2003 and we are actively pursuing others. We will reduce frontier exploration spending, and we plan to pursue some high-impact exploration spending. We will continue to emphasize cost control in all areas, including general and administrative costs. If the current favorable oil and gas price environment continues, we expect to generate cash flow in 2004 in excess of our expected capital expenditures. In summary, we will continue to take the necessary actions to accomplish our overall objective to enhance shareholder value and to seek prudent growth.

Results of Operations

        Net earnings for 2003 were $88.4 million compared to net earnings of $21.3 million in 2002. The increase in earnings was due primarily to the combination of higher average oil and gas sales prices, higher sales volumes, and lower oil and gas production expense.

        Net earnings for 2002 were $21.3 million compared to net earnings of $103.7 million in 2001. The decrease in earnings was the result of lower sales volumes and lower average oil and gas sales prices, offset partially by lower operating expenses. Lower sales volumes were primarily the result of property sales in the fourth quarter of 2001, hurricane downtime in the Gulf of Mexico in 2002 and normal declines caused by reduced capital expenditures.

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Oil and Gas Sales

        Sales volumes, weighted average sales prices, and oil and gas sales revenue for the years ended December 31, 2003, 2002 and 2001 were as follows:

(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 49,990 MMCF, 36,050 MMCF and 42,870 MMCF in 2003, 2002 and 2001, respectively. Hedged oil and condensate volumes were 4,597,500 barrels, 3,921,500 barrels, and 3,742,500 barrels in 2003, 2002 and 2001, respectively. These arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the effective portion of the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net gains (losses) related to our cash flow hedges were $(72,863,000), $(1,742,000) and $22,781,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Those arrangements that are not designated as cash flow hedges for accounting

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purposes are recorded as non-operating income or expense. Average sales prices have been adjusted to reflect effects of energy swaps and collars.

        The increase in oil and gas sales revenue in 2003 compared to 2002 was the result of increased price realizations for both oil and gas, combined with higher sales volumes. In the United States, increases in our sales volumes were attributable primarily to acquisitions made during 2003. In Canada, our sales volumes decreased in 2003 due primarily to higher royalty volumes in the current higher price environment, plant maintenance and the effects of property divestitures in 2002.

        The decrease in oil and gas sales revenue in 2002 compared to 2001 was primarily the result of lower product prices and production volumes. Volume decreases were due primarily to the Gulf Coast business unit. Our Gulf of Mexico properties were impacted by the sale of 50% of Forest's interests in the South Marsh Island and Vermilion areas in the fourth quarter of 2001, and also experienced hurricane downtime and normal production declines that were the result of reduced capital expenditures.

Oil and Gas Production Expense

        The components of oil and gas production expense for the years ended December 31, 2003, 2002 and 2001 were as follows: