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TABLE OF CONTENTS

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

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2004

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 March 20, 2010

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

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

        Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Act). Yes ý    No o

        The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2004, the last business day of the registrant's most recently completed second fiscal quarter, was $1,402,540,118 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

        There were 60,447,568 shares of the registrant's Common Stock, Par Value $.10 Per Share outstanding as of February 28, 2005.

        Document incorporated by reference: Portions of the registrant's definitive proxy statement of the Forest Oil Corporation annual meeting of shareholders to be held on May 10, 2005, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

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PART I

Items 1. and 2. Business and Properties.

General

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

        We operate in five business units: the Gulf Coast, Western United States ("Western"), Alaska, Canada, and International. We conduct exploration and development activities in each of our North American core areas and in our International locations; however, all of our estimated proved reserves and producing properties are located in North America. Discoveries of oil and gas have been made in our International business unit; however, no proven reserves have been recorded to date. At December 31, 2004, approximately 89% of our estimated proved oil and gas reserves were in the United States and approximately 11% were in Canada.

        In the following discussion, 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 Part II, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Forward-Looking Statements," below, for more details. We also use a number of terms used in the oil and gas industry. See the heading "Glossary of Oil and Gas Terms", below, for the definition of certain terms.

Business Strategy

        For 2004 and 2005, we established a four-point strategy to achieve our business objectives. The 2005 plan calls for continuing our focus on cost control, growth through operations, pursuit of acquisitions, and maintaining our financial flexibility. Our strategy is as follows:

Continue to Focus on Cost Control

        We strive to create a culture of cost discipline. At the beginning of 2004, we set out to lower our general and administrative costs by increasing the efficiency of corporate functions and implementing a bottom-up cost reduction strategy. As a result, our absolute overhead costs in 2004 decreased $4.7 million, compared to 2003, and the related per-unit costs decreased 20%. We also focused on maintaining discipline in our capital expenditures. During 2004, capital expenditures for exploration and development activities were reduced to $275 million, reflecting our spending discipline, and we reduced the portion of our capital invested in frontier areas to only 2% of total. Another critical area of our cost control efforts was lease operating expenses. Although lease operating expenses increased in 2004 as compared to 2003, primarily due to newly acquired fields, we were able to decrease the expenses by approximately 9% from the time we announced our lease operating expense action items in the third quarter of 2004.

Growth through Operations

        We focus on exploiting newly acquired and existing base assets to provide increases in production and proved reserves. Capital is allocated only to projects with attractive risk-weighted rate of return potential. Our operational activities to exploit our assets include development and infill drilling, workovers, stimulation treatments, waterfloods, and recompletions.

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Pursuit of Acquisitions

        We pursue strategic acquisitions that meet our criteria for investment returns and that are consistent with our operational focus. We believe this enables us to leverage our technical expertise and existing land and infrastructure positions. In 2004, we spent $425 million to acquire a total of 249 Bcfe of estimated proved reserves on properties primarily located within our Gulf Coast, Western, and Canadian business units. Also included in the acquisition of these producing fields was over 400,000 net acres, 68% of which was undeveloped. All of the 2004 acquisitions added assets to existing core areas. In general, our recent acquisition program has focused on acquisitions of properties in which we already held an interest or which are near our existing properties.

Maintain Financial Strength

        We seek to maintain financial flexibility and sufficient liquidity to capitalize on opportunities as they arise. We reduced our debt-to-book capitalization ratio from nearly 46% at the beginning of 2003 to 44% at December 31, 2003, and to less than 38% at December 31, 2004. We had approximately $55 million of cash on hand and $341 million available under our credit facility at December 31, 2004. In addition, none of our outstanding long-term debt is due until after 2007, and 69% is not due until after 2008.

        Hedging is a significant part of our strategy to partially mitigate commodity price risk. We have a formal, board-approved policy related to commodity hedging activities. As of February 28, 2005 we have hedged, via swaps and collar instruments, approximately 77 Bcfe of our 2005 production. The majority of our current hedges were executed in order to support the economics of recent acquisitions.

Acquisitions

        During 2004, we made approximately $425 million of oil and gas asset acquisitions (including $51 million of deferred tax gross up). Our largest acquisition was of The Wiser Oil Company ("Wiser") in June 2004, which included oil and gas assets valued at $347 million. At the time the acquisition was closed, the acquired assets included 186 Bcfe of estimated proved reserves, producing 64 MMcfe per day, as well as approximately 285,000 net undeveloped acres. The Wiser acquisition primarily enhanced the asset base of our Canadian and Western business units. The acquisition increased our Canadian business unit's estimated proved reserves and production in the Canadian Plains area. This acquisition also increased our Western business unit's estimated proved reserves and production by 29% and 26%, respectively, and enlarged our Permian Basin position. Finally, the Wiser acquisition added significant exploration acreage in the Gulf Coast area and Canada.

        During 2003, we made approximately $424 million (including $33 million of deferred tax gross up) of oil and gas acquisitions of properties located in the Gulf of Mexico, Gulf Coast, South Texas, and the Permian Basin with estimated proved reserves totaling 322 Bcfe. The largest acquisition in 2003 was of oil and gas properties in South Louisiana and the Gulf of Mexico in the fourth quarter from Union Oil Company of California ("Unocal"). In this transaction, we paid $207 million in cash to acquire approximately 141 Bcfe of estimated proved reserves producing 66 MMcfe per day as well as approximately 93,000 net undeveloped acres.

Recent Acquisition

        On February 28, 2005, we announced that we had agreed to purchase all of the stock of a private company whose primary asset is an operated average working interest of 83% in the Buffalo Wallow Field in Texas and approximately 33,000 gross acres primarily in Hemphill and Wheeler Counties, Texas. Forest will pay an estimated $200 million in cash for the stock and assume an estimated $30 million of debt (net of working capital). The closing is subject to customary closing conditions and

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is expected to occur on March 31, 2005. The Buffalo Wallow Field has estimated proved reserves of 120 Bcfe.

Property Sales

        As a part of our ongoing program to upgrade the quality of our properties, we dispose of non-strategic assets. Assets located outside our focus areas or those with marginal value, high operating costs, or high abandonment liabilities are identified for sale or trade. During 2004, we sold assets, including oil and gas properties with estimated proved reserves of approximately 85 Bcfe, for total cash proceeds of approximately $106 million. These sales included offshore platforms with near-term abandonment obligations. During 2003, we disposed of assets, including oil and gas properties with estimated proved reserves of approximately 21 Bcfe.

Business Unit Exploration and Production Activities

        At December 31, 2004, we held interests in approximately 3,600 net oil and gas wells in the United States and Canada and sold 172.4 Bcfe of oil and gas, or an average of 471 MMcfe per day during 2004. Approximately 86% of our total production was in the United States, and 14% was in Canada. The sales volumes and estimated proved reserves for our business units in the United States and Canada are summarized below.

⁽¹⁾

Gulf Coast production and estimated proved reserves are located in South Texas, Louisiana Gulf Coast, and Offshore Gulf of Mexico.

⁽²⁾

Western production and estimated proved reserves are located in Western Oklahoma, Utah, Wyoming, West Texas, and New Mexico.

⁽³⁾

Alaska production and estimated proved reserves are primarily located onshore and offshore Cook Inlet.

⁽⁴⁾

Canada production and estimated proved reserves are primarily located in Alberta and British Columbia.

        The following table shows expenditures for exploration and development and property acquisitions, for each of our business units during 2004.

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Gulf Coast

        The Gulf Coast business unit had a production increase of 16% on an Mcfe basis in 2004 compared to 2003. Production was increased through a combination of acquisitions, exploitation, and two successful deep shelf exploratory discoveries at South Timbalier 72 and West Cameron 112. Net undeveloped acreage in South Texas and Louisiana increased from 3,000 acres to 90,000 acres as the result of the Wiser acquisition. In 2005, capital expenditures in this business unit will be focused on exploiting the onshore fields, with emphasis on the recently acquired fields, and exploration of onshore Gulf Coast and offshore Gulf of Mexico deep shelf.

Western

        The Western business unit had a production increase of 42% on a per Mcfe basis in 2004 compared to 2003. Production was increased through a combination of acquisitions and exploitation of these acquisitions, as well as an increased drilling program that totaled 70 gross wells. The Permian Basin area production has been the primary focus of the business unit with production increasing from 7.2 Bcfe in 2003 to 17.8 Bcfe in 2004. In 2005, capital expenditures in this business unit will be focused in four areas: waterflooding and development drilling in the central Permian Basin, exploratory gas drilling in the Delaware Basin of the Permian Basin, infill drilling in the Mid-Continent, and exploratory drilling in the Rocky Mountains.

Canada

        The Canadian business unit had a production increase of 27% on a per Mcfe basis in 2004 compared to 2003. Production was increased through a combination of acquisitions, exploitation of these acquisitions, and exploratory success in the Foothills/Wild River area in Central Alberta. The production increase was accomplished despite the divestiture of $69 million in properties. In 2005, capital expenditures in this business unit will be focused in the Wild River, Narraway, Copton, and Hayter areas.

Alaska

        The Alaska business unit had a production decrease of 23% on a per Mcfe basis in 2004 compared to 2003. Production decreased as capital expenditures in this business unit decreased to $22 million in 2004 from $69 million in 2003. In 2005, capital expenditures in this business unit are forecasted to increase as it focuses on the onshore Cook Inlet natural gas exploration program. So far in 2005, we have announced new gas discoveries at West Foreland and Three Mile Creek. Forest's Cook Inlet onshore land position near these discoveries currently includes in excess of 96,000 net acres. Our net undeveloped acreage position in and around the Cook Inlet now totals approximately 1.2 million net acres.

International

        The International business unit was able to limit its work commitments in 2004 and to high-grade the portfolio to focus primarily on South Africa, Gabon, and Italy. Partners were previously obtained for exploration activities in both Gabon and South Africa, which reduced the need for Forest's capital to be invested in these activities. In 2005, the business unit's activity will be focused on securing gas contracts and drilling a deepwater prospect in South Africa, and drilling a shallow oil prospect in Gabon with a full carry of the costs by our partners.

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Reserves

        The following table shows our estimated quantities of proved reserves as of December 31, 2004, 2003, and 2002. All estimated proved reserves are currently located in North America. See Note 13 to the Consolidated Financial Statements for additional information regarding estimated proved reserves.

        Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and the interpretation thereof. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as change in product prices, may require revision of such estimates. Accordingly, oil and gas quantities ultimately recovered will vary from reserve estimates. See Part II, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors," for a description of some of the risks and uncertainties associated with our business and reserves.

        Forest annually files estimates of its oil and gas reserves with the U.S. Department of Energy ("DOE"). During 2004, we filed estimates of our oil and gas reserves as of December 31, 2003 with the DOE, which were consistent with the reserve data reported for the year ended December 31, 2004 in Note 13 to the Consolidated Financial Statements.

Independent Audit of Reserves

        For financial reporting purposes, including this Form 10-K, Forest uses reserve estimates prepared by its internal staff of engineers. A substantial portion of our reserves are audited by independent petroleum engineers engaged by Forest. Our reserve audit procedures require the independent reserve engineers to prepare their own independent estimates of proved reserves for fields comprising at least 80% of Forest's year-end SEC PV10% value for each country in which Forest owns fields for which proved reserves have been booked. The fields selected each year comprise the top 80% of Forest's fields based on the SEC PV10% value of such fields and a minimum of 80% of the SEC PV10% value of the fields added during the year through discoveries, extensions, and acquisitions. Forest may also include fields that fall outside of the top 80% of the SEC PV10% value that represent material volumes of proved reserves, have experienced material revisions to prior estimates of proved reserve volumes or value, or have experienced changes as a result of new operational activity. The procedures prohibit exclusions of any fields, or any part of a field, that comprises part of the top 80% of the SEC PV10% value.

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        Under these procedures, the independent reserve engineers prepare independent estimates of net proved reserve volumes using generally accepted engineering and evaluation principles, reserve definitions and cost, and price parameters specified by the Securities and Exchange Commission ("SEC"). These estimates are compared to Forest's own estimates in the aggregate for each country.

        For the year-end 2004, we engaged three independent petroleum engineering firms to perform reserve audit services. Ryder Scott Company audited our estimates of the reserves attributable to certain properties in the United States and Canada, except certain properties acquired by us in the Permian Basin and South Texas, which were audited by DeGolyer and MacNaughton. Also, certain Canadian properties that we acquired in connection with an acquisition completed in 2004 were audited by Gilbert Laustsen Jung Associates Ltd. Together, these firms independently reviewed estimates relating to properties constituting approximately 84% of our reserves, as of December 31, 2004, based on the reserve volumes.

Exploration, Production, and Drilling Data

        During 2004, we engaged in approximately 300 operational projects, including drilling a total of 148 gross wells, 4 of which were injection wells. Of the remaining 144 wells, 46 were exploration and 98 were development. Our 2004 drilling program achieved a 90% success rate.

Productive Wells

        The following table summarizes productive wells as of December 31, 2004, all of which are located in the United States and Canada:

⁽¹⁾

The large variance between gross and net non-operated wells is primarily a result of our ownership interest in approximately 1,827 gross gas wells in the San Juan Basin with an average working interest of approximately .89% and our ownership interest in approximately 1,510 gross oil wells in the Prudhoe Bay area with an average working interest of approximately .02%.

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Drilling Activity

        The following table summarizes the number of wells drilled during 2004, 2003, and 2002, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest. As of December 31, 2004, we had 12 gross (7 net) wells in progress.

⁽¹⁾

A non-productive well 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; also known as a dry well (dry hole).

Acreage

        The following table summarizes developed and undeveloped acreage in which we owned a working interest as of December 31, 2004 and 2003. A majority of our developed acreage is subject to mortgage liens securing our bank credit facilities in the United States and Canada. Acreage related to royalty,

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overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests.

        At December 31, 2004, approximately 14% and 5% of our net undeveloped acreage in the United States and Canada was held under leases that have terms which will expire in 2005 and 2006, respectively, if not extended by exploration or production activities. In addition, 26% and 44% of our total International net undeveloped acreage could be relinquished during 2005 and 2006, respectively, in Italy, Gabon, Romania, and South Africa as part of contractual commitments. The table above includes approximately 675,000 net acres in Blocks 2A and 2C in South Africa as of December 31, 2004, which are being relinquished in the first quarter of 2005. The decreased net acreage shown for South Africa for 2004 is due to a 100% relinquishment of Block 1. The decreased net acreage in Gabon and Romania in 2004 is a result of the assignment of working interests to partners who have farmed into these permit areas. In addition, we formally relinquished our contract areas in Switzerland, Germany, and Albania during 2004.

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Production, Average Sales Prices, and Average Production Costs

        The following table reflects production, sales price, and production expense information for the years ended December 31, 2004, 2003, and 2002.

⁽¹⁾

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Average sales prices have been adjusted to reflect effects of energy swaps and collars. See Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk" concerning certain of our hedging activities.

Marketing and Delivery Commitments

        The credit-worthiness of potential 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 our business because any individual spot purchaser could be readily replaced by another spot purchaser. In 2004, sales to BP Energy Company, Occidental Energy Marketing, Tesoro Alaska Petroleum Company, and Louis Dreyfus Energy represented approximately 15%, 11%, 11%, and 11%, respectively, of our total revenue.

United States

        In the United States, Forest's production of natural gas is generally sold in the areas where it is produced or at nearby "pooling points." Our natural gas production is typically sold on a month-to-month basis in the spot market referencing published indices. Our production of oil and natural gas liquids is typically sold under short-term contracts at prices based upon posted field prices and is typically sold at the wellhead. There were no long-term delivery commitments in the United States as of December 31, 2004.

Canada

        In Canada, our natural gas production is sold by our subsidiary, Canadian Forest Oil Ltd. ("Canadian Forest"), either through a joint venture with other producers (the "Canadian Netback Pool"), which is a long-term commitment, or under direct sales contracts or spot contracts. See Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk," below, for further details. Our Canadian liquids production is generally sold at the wellhead under short-term market based contracts at prices posted at Alberta pipeline processing hubs that are netted back to the field.

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Competition

        Forest encounters competition in all aspects of our business, including acquisition of properties and oil and gas leases, marketing oil and gas, obtaining services and labor, and securing drilling rigs and other equipment necessary for drilling and completion of wells. A large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources. Our ability to increase reserves in the future will be dependent on our ability to generate successful prospects on our existing properties, to acquire new producing properties, and to acquire additional leases and prospects for future development and exploration. Factors that affect our ability to acquire properties include, among others, availability of desirable acquisition targets, available funds, and internal standards for minimum projected return on investment. Because of the nature of our oil and gas assets and management's experience in exploiting our reserves and acquiring properties, management believes that we effectively compete in our markets.

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 related to permits for the drilling of wells, bonding requirements in order to drill or operate wells, 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, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws sometimes 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.

        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 Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). In addition to permits required from other agencies, such as the Environmental Protection Agency ("EPA"), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling, and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of Outer Continental Shelf ("OCS") wells, the valuation of production, and the removal of facilities. 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 connection with its administration of offshore leases in the Gulf of Mexico, the MMS annually evaluates each lessee's plugging and abandonment liabilities. If we do not satisfy the MMS's financial tests and requirements, we could be required to post supplemental bonds. In the past, Forest has not been required to post supplemental bonds. We cannot assure you that we will continue to remain on

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the list of MMS lessees exempt from the supplemental bonding requirements and cannot predict or quantify the amount of any such supplemental bonds or the associated annual premiums, which could be substantial. 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.

        Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission ("FERC"), and the courts. We cannot predict when or whether any such proposals may become effective. 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. Federal authorities do not regulate the price of oil and gas in export trade. Legislation exists, however, that regulates the quantities of oil and natural gas which may be removed from the provinces and exported from Canada. We do not expect that any of these controls and regulations will affect Forest in a manner significantly different from other oil and natural gas companies of similar size with operations in Canada.

        The provinces in which we operate have legislation and regulation which govern land tenure, royalties, production rates, and environmental protection. The royalty regime in the provinces in which we operate is a significant factor in the profitability of our production. Crown royalties are determined by government regulation and are typically calculated as a percentage of the value of production. The value of the production and the rate of royalties payable depends on prescribed reference prices, well productivity, geographical location, and the type or quality of the product produced.

Environmental Regulation

        As a lessee and operator of onshore and offshore oil and natural gas properties in the United States and Canada, we are subject to stringent federal, state, provincial, and local laws and regulations relating to environmental protection as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of oilfield generated substances.

        We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration and production of oil and gas. 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 operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability without regard to fault or the legality of the original conduct that could require us to

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remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure to prevent future contamination. We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

        While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect 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.

        We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States, Canada, and other relevant international jurisdictions. 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 cleanup 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.

        For further information regarding certain environmental matters, see Part I, Item 3—"Legal Proceedings," below.

Employees

        As of December 31, 2004, we had 496 employees. None of our employees is currently represented by a union for collective bargaining purposes.

Geographical Data

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

Offices

        Our principal office is located in leased space at 1600 Broadway, Denver, Colorado 80202, telephone 303.812.1400. We plan to relocate our principal office in August 2005 to 707 17th Street, Denver, Colorado 80202. We also lease field offices and subsidiary offices, including office space in Anchorage, Alaska; Odessa, Texas; Lafayette and Metairie, Louisiana; Calgary, Alberta, Canada; and Cape Town, South Africa. We believe that our facilities are adequate for our current operations.

Title To Properties

        Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Under the terms of our bank credit facilities in the United States and Canada, we have granted the lenders a lien on our properties. In addition, our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Forest's general practice is to conduct a title examination on all material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to insure that production from our properties, if obtained, will be salable for the account of Forest.

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Available Information

        Forest's website address is www.forestoil.com. Available on our website, free of charge, are Forest's Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, reports on Forms 3, 4, and 5 filed on behalf of directors and officers, as well as amendments to these reports. These materials are available as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.

        Also posted on our website, and available in print upon written request of any shareholder addressed to the Secretary of Forest, at 1600 Broadway, Suite 2200, Denver, Colorado 80202, are charters for our Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee. Copies of the Code of Business Conduct and Ethics and the Proper Business Practices Policy are also posted on Forest's website.

Glossary of Oil and Gas Terms

        The terms defined in this section are used throughout this Form 10-K.

        Bbl.    Barrel (of oil or natural gas liquids).

        Bcf.    Billion cubic feet (of natural gas).

        Bcfe.    Billion cubic feet equivalent.

        Bbtu.    One billion British Thermal Units.

        Developed acreage.    The number of acres which are allocated or held by producing wells or wells capable of production.

        Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

        Dry hole; dry well.    A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

        Equivalent volumes.    Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

        Exploratory well.    A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.

        Farmout.    An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

        Full cost pool.    The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general corporate overhead, or similar activities are not included.

        Gross acres or gross wells.    The total acres or wells, as the case may be, in which a working interest is owned.

        Liquids.    Describes oil, condensate, and natural gas liquids.

        MBbls.    Thousands of barrels.

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        Mcf.    Thousand cubic feet (of natural gas).

        Mcfe.    Thousand cubic feet equivalent.

        MMBtu.    One million British Thermal Units, a common energy measurement.

        MMcf.    Million cubic feet.

        MMcfe.    Million cubic feet equivalent.

        NGL.    Natural gas liquids.

        Net acres or net wells.    The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers.

        NYMEX.    New York Mercantile Exchange.

        Present value or PV10% or "SEC PV10%."    When used with respect to oil and gas reserves, present value or PV-10 or SEC PV10% means the estimated future gross revenue to be generated from the production of net proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service, accretion, and future income tax expense or to depreciation, depletion, and amortization, discounted using monthly end-of-period discounting at a nominal discount rate of 10% per annum.

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

        Proved developed reserves.    Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

        Proved reserves.    Estimated quantities of crude oil, natural gas, and natural gas liquids which, upon analysis of geologic and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

        Proved undeveloped reserves.    Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.

        Undeveloped Acreage.    Acreage 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 estimated proved reserves.

        Working interest.    An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property and a share of production.

Item 3. Legal Proceedings.

        Forest, in the ordinary course of business, is a party to various lawsuits, claims, and proceedings, including the matter 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.

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Environmental Matters

        Forest is involved in a number of governmental proceedings in the ordinary course of business, including the environmental matter described below.

        Forest owns and operates a platform located in the Cook Inlet, Alaska. For a period of time, discharges from the platform exceeded the limits allowed by the EPA discharge permit. Forest believes that it is now in compliance with those limits. We believe that the proceeding related to the past discharges could result in total monetary penalties that should not exceed $500,000.

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, 2004.

Item 4A. Executive Officers of Forest.

        The following persons were serving as executive officers of Forest as of March 1, 2005.

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*

Denotes less than one year.

⁽¹⁾

Officer(s) are elected to serve for one-year terms at meetings immediately following the last annual meeting, or until their death, resignation, or removal from office, whichever first occurs.

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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, 2005, there were 60,447,568 outstanding shares of our Common Stock held by 687 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 2003 and 2004. There were no dividends declared on the Common Stock in 2003 or 2004. On March 11, 2005, the closing price of Forest Common Stock was $40.27.

Warrants

        Forest's warrants are quoted on the NASDAQ Bulletin Board. At December 31, 2004, Forest had two series of warrants outstanding including warrants that expired on February 15, 2005 (the "2005 Warrants") and subscription warrants (the "Subscription Warrants"). For a discussion of the 2005 Warrants, see Note 6 to the Consolidated Financial Statements of this Form 10-K.

        At February 28, 2005, Forest had outstanding 1,752,355 Subscription Warrants, which were held by 12 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. Forest may elect to give the notice of expiration if the market price of the Common Stock closes at 300% of the exercise price of the Subscription Warrants, or $37.50 per share, for a period of 30 consecutive trading days. The Subscription Warrants are quoted on the NASDAQ Bulletin Board under the symbol "FTYLL.OB." On March 11, 2005, or the last day of activity prior thereto, the closing price of the Subscription Warrants was $21.00. 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 2003 and 2004.

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        During 2004, 267,508 warrants to purchase shares of Common Stock were exercised in cash and cashless exercises, and through February 28, 2005 warrants to purchase 102,137 shares of Common stock were exercised in cash and cashless exercises. The warrants were originally issued by Forcenergy Inc in connection with its reorganization under the federal bankruptcy code. Upon the merger of Forcenergy and Forest, the warrants became warrants to acquire shares of Forest Common Stock. The issuance of the warrants and shares of Common Stock upon exercise were exempt from registration under the Securities Act of 1933 pursuant to section 1145 of the federal bankruptcy code.

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 United States and Canadian bank credit facilities dated as of September 29, 2004. The provisions in the indentures pertaining to these Senior Notes and in the bank credit facilities limit our ability to make restricted payments, which include dividend payments. At December 31, 2004, the most restrictive limitation limited our payment of dividends to an aggregate of $254 million.

        Forest has not paid dividends on its Common Stock during the past five years. 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 to the 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," below.

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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, 2004. This data should be read in conjunction with Part II, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations," below, and the Consolidated Financial Statements and Notes thereto.

⁽¹⁾

Discontinued operations relate to the sale of the business assets of our Canadian marketing subsidiary on March 1, 2004. The results for this business' operations have been reported as discontinued operations in the selected financial data for all periods presented.

⁽²⁾

Cumulative effect of change in accounting principle for 2003 relates to the adoption of SFAS No. 143 on January 1, 2003. See Note 1 to the Consolidated Financial Statements.

⁽³⁾

Includes the effects of hedging.

⁽⁴⁾

Does not include estimated discounted asset retirement obligations of $14.1 million and $63.7 million related to assets placed in service during the years ended December 31, 2004 and December 31, 2003, respectively.

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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 below 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 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 the Notes to Consolidated Financial Statements.

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.

2004 Highlights

        Highlights of Forest's performance in 2004 were:

•

Production: Total production increased to 172.4 Bcfe, a 16% increase from 2003.



•

Increased Reserves: Forest's year-end estimated proved reserves are 1,334 Bcfe, 3% higher than year-end 2003, notwithstanding 172.4 Bcfe of production in 2004 and oil and gas property sales of 84.6 Bcfe.



•

Lower G&A: 2004 overhead was $56.1 million, and G&A expense was $32.1 million, 11% lower than 2003, or 21% on a per Mcfe basis.



•

Exploration Track Record: Forest had continuing success in 2004 with its Foothills/Wild River project in Canada and completed two successful exploratory test wells in the deep Gulf of Mexico shelf area as well as two gas discoveries in onshore Cook Inlet, Alaska.



•

Acquisition Accomplishments: Forest invested $425 million to acquire 249 Bcfe of estimated proved reserves.



•

Reduced Leverage: Forest ended the year with a total debt-to-book capitalization ratio of less than 38%.

2005 Outlook

        We anticipate a favorable market environment in 2005 based on our outlook for continuing growth in the U.S. economy and emerging energy consumers such as China and India. In our view, the economic growth and the resultant increased demand for oil and gas should continue to support relatively high commodity prices. Within this environment, we anticipate strong financial performance by Forest. Our inventory of exploitation and exploration projects is at a high level, which should provide us good visibility of future production additions. Our 2005 plan anticipates cash flow from operations greater than our exploration and development spending levels, which will be used, in part, to fund acquisitions.

        We face numerous challenges in 2005. In particular, our Gulf of Mexico assets are mature and experience inherent high production declines. It will be difficult to stem this decline and manage expected operational cost increases. We will continue to pursue asset acquisition opportunities aggressively. However, competition for these assets has been and will continue to be intense. Due to a higher commodity price environment, we anticipate service costs as well as costs of equipment and raw

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materials such as steel will be higher in 2005 than in 2004. Our challenge will be to add reserves, through drilling and acquisitions, and operate our productive assets cost-efficiently in a manner that achieves attractive returns for our shareholders.

Recent Acquisition

        On February 28, 2005, we announced that we had agreed to purchase all of the stock of a private company whose primary asset is an operated average working interest of 83% in the Buffalo Wallow Field in Texas and approximately 33,000 gross acres primarily in Hemphill and Wheeler Counties, Texas. Forest will pay an estimated $200 million in cash for the stock and assume an estimated $30 million of debt (net of working capital). The closing is subject to customary closing conditions and expected to occur on March 31, 2005. The Buffalo Wallow Field has estimated proved reserves of 120 Bcfe. Forest expects to initially fund the cash purchase price by borrowing under its bank credit facilities.

Results of Operations

        Net earnings for 2004 were $122.6 million compared to net earnings of $88.4 million in 2003 and $21.3 million in 2002. The increase in earnings in 2004 compared to 2003 was the result of increased average oil and gas sales prices, increased sales volumes, and reduced G&A expense, offset partially by increased oil and gas production expense and increased depletion expense. The increase in earnings in 2003 compared to 2002 was due primarily to the combination of increased average oil and gas sales prices, increased sales volumes, and decreased oil and gas production expense. Discussion of the components of the changes in our annual results follows.

Oil and Gas Sales

        Sales volumes, weighted average sales prices, and oil and gas sales revenue for the years ended December 31, 2004, 2003, and 2002 are included in Part I, Items 1 and 2—"Business and Properties–Production, Average Sales Prices, and Average Production Costs."

        The increase in oil and gas sales revenue in 2004 compared to 2003 was the result of a 16% increase in production and a 20% increase in price realizations per Mcfe. The increase in our sales volumes was due primarily to acquisitions made during the fourth quarter of 2003 and the second quarter of 2004.

        The increase in oil and gas sales revenue in 2003 compared to 2002 was the result of a 34% increase in price realizations per Mcfe, combined with a 4% increase in sales volumes. The increase in sales volumes was attributable primarily to acquisitions made during 2003.

Oil and Gas Production Expense

        Oil and gas production expense (commonly referred to as lease operating expense) includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of expensed workovers, product transportation costs from the wellhead to the sales point, and production and ad

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valorem taxes. The components of oil and gas production expense for the years ended December 31, 2004, 2003, and 2002 were as follows:

        In 2004, lease operating expense ("LOE") was $238.2 million or $1.38 per Mcfe, as compared to $154.2 million or $1.03 per Mcfe in 2003. LOE from the properties acquired in late 2003 and during 2004 accounted for approximately 60% of the increase. The acquired properties had higher initial LOE due to deferred maintenance of the properties at the time of acquisition, and a portion of the acquired properties had higher product transportation rates than compared to our historical average rates. Forest also spent approximately $14.5 million more in 2004 on workovers than it did in 2003; approximately $4.9 million of the increase related to the properties acquired in 2003 and 2004. Production and ad valorem taxes increased 60% over 2003 due to higher oil and gas sales revenue and assessed property values.

        The LOE reduction in 2003 compared to 2002, on both an absolute and a per-unit basis, reflects cost reduction measures employed throughout Forest's operations, offset somewhat by increases in production taxes and ad valorem taxes.

General and Administrative Expense; Overhead

        The following table summarizes the components of total overhead costs incurred during the periods:

        The decrease in overhead costs from 2002 through 2004 were attributable primarily to cost reduction measures in corporate areas. The percentage of overhead capitalized remained relatively constant, ranging between 40% and 43%. The percentage of overhead capitalized in 2004 (43%) was up slightly over 2003 (40%) due to a greater reduction in general corporate costs which are capitalized at lower rates.

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Depreciation and Depletion; International Impairments

        Depreciation and depletion expense for the years ended December 31, 2004, 2003, and 2002 was as follows:

        The increases in depletion expense on an equivalent unit of production basis of $.48 in 2004 and $.29 in 2003 were due primarily to downward revisions in estimated proved reserves in the fourth quarter of 2003. See discussion of the revision to the estimated proved reserves in Note 13 to the Consolidated Financial Statements.

        The following costs of undeveloped properties were not subject to depletion at the periods indicated:

        The increase in the total undeveloped properties from 2003 to 2004 was due primarily to the additional undeveloped properties acquired in 2004 in conjunction with the purchase of Wiser. See Note 2 to the Consolidated Financial Statements for additional information on the Wiser acquisition. In 2004, Forest recorded impairments of oil and gas properties located outside of North America of $4.0 million ($2.4 million net of taxes) related to evaluations of projects in Albania, Germany, and Italy. In 2003, we recorded impairments of $16.9 million ($10.5 million net of taxes), related primarily to evaluations of projects in Albania, Italy, Romania, Switzerland, and Tunisia. Of this amount, approximately $10.3 million related to our interest in a project in Albania. No impairments were recorded in 2002.

Accretion of Asset Retirement Obligations

        Accretion expense of approximately $17.3 million in 2004 and $13.8 million in 2003 was related to the accretion of Forest's asset retirement obligation pursuant to SFAS No. 143, adopted January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Using a cumulative effect approach to adopt SFAS No. 143, Forest recorded an after tax credit of approximately $5.9 million in the first quarter of 2003.

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Other (Income) Expense, Net

        The components of other (income) expense, net for the years ended December 31, 2004, 2003, and 2002 were as follows:

        The foreign currency exchange gain in 2004 is related to the repayment of Canadian intercompany debt denominated in U.S. dollars. Franchise taxes are paid to the states of Texas and Louisiana based on capital investment deployed in these states, determined by apportioning total capital as defined by law. Forest's share of income or loss of equity method investee relates to our 40% ownership of a pipeline company that transports crude oil in Alaska. Losses on extinguishment of debt relate to redemptions of our 8³/4% and 10¹/2% Senior Subordinated Notes for amounts in excess of par value.

Interest Expense

        Interest expense of $57.8 million in 2004 was 17% greater than 2003, due to higher average debt balances. Interest expense of $49.3 million in 2003 was 2% less than 2002, primarily because the effects of greater average debt balances were more than offset by decreased average interest rates on variable and fixed rate debt and by amortization of gains recognized on termination of interest rate swaps.

Current and Deferred Income Tax Expense

        Forest recorded current income tax expense before discontinued operations and cumulative effect of change in accounting principle of $3.0 million in 2004 compared to $.7 million in 2003 and $.2 million in 2002. The increase in each of the years was due primarily to current taxes required to be paid under the Federal Alternative Minimum Tax and, in 2004, to state income taxes.

        Deferred income tax expense before discontinued operations and cumulative effect of change in accounting principle was $75.8 million in 2004 compared to $53.9 million in 2003 and $11.8 million in 2002. The increase in each of the years was due primarily to increased net income before income taxes. In 2004 and 2003, the increase was partially offset by a decrease in Canadian taxes of $2.4 million and $7.3 million, respectively, due to a Canadian federal income tax rate reduction from 28% to 21% over a five year period beginning in 2003.

        In total, Forest's effective income tax rates for the years ended December 31, 2004, 2003, and 2002, were 39.0%, 37.7%, and 36.4%, respectively. These rates were based on a U.S. federal statutory rate of 35.0% in each of the three years. Differences between the U.S. federal statutory rate and the effective rate were primarily due to foreign and state statutory rates and permanent book to tax differences. Reference should be made to Note 5 to the Consolidated Financial Statements for a reconciliation of the statutory rate to our effective rate for each period presented.

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Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary were sold to Cinergy Canada, Inc. ("Cinergy") for $11.2 million CDN. Under the terms of the purchase and sale agreement, Cinergy will continue to market natural gas on behalf of Canadian Forest for five years through February 2009 (unless subject to prior contractual commitment), and will also administer the netback pool that we formerly administered. We could receive additional contingent payments related to this sale over the next five years if Cinergy meets certain earnings goals with respect to the acquired business. The subsidiary's results of operations have been reported as discontinued operations in the consolidated statements of operations for all years presented. The components of (loss) income from discontinued operations for the years ended December 31, 2004, 2003, and 2002 are as follows:

Liquidity and Capital Resources

        In 2005, as in 2004, we expect our cash flow from operations to provide our primary source of liquidity to meet operating expenses and fund capital expenditures other than large acquisitions. Any remaining cash flow from operations will be available for acquisitions, debt repayment, or other corporate purposes.

        The prices we receive for our oil and natural gas production have a significant impact on operating cash flows. While significant price declines in 2005 would adversely affect the amount of cash flow generated from operations, we utilize a hedging program to partially mitigate that risk. As of February 28, 2005, Forest has hedged approximately 77 Bcfe of its 2005 production primarily to support the economics of recent acquisitions of oil and gas properties. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our 2005 production. Depending on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions. For further information concerning our 2005 and 2006 hedging contracts, see Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk—Hedging Program."

        Another source of liquidity is our $600 million revolving bank credit facilities, which we entered into in September 2004 which mature in September 2009. At February 28, 2005, we had $8.8 million of cash on hand, $66.4 million of indebtedness under the bank credit facilities, and an unused borrowing base of $427 million. We use the credit facilities to fund daily operating activities and acquisitions in the United States and Canada as needed.

        We believe that our available cash, cash provided by operating activities, and funds available under our bank credit facilities will be sufficient to fund our operating, interest, and general and administrative expenses, our capital expenditure budget, and our short-term contractual obligations at current levels for the foreseeable future.

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        The capital markets have been our principal source of funds to finance large acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, ready access to capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under "Risk Factors" below.

Historical Cash Flow

        Net cash provided by operating activities, net cash used by investing activities, and net cash (used) provided by financing activities for the years ended December 31, 2004, 2003, and 2002 were as follows:

        The increase in net cash provided by operating activities in 2004 compared to 2003 of approximately $186.0 million was due primarily to an increase in net income and depreciation expense (a non-cash expense) totaling $152.1 million. The decrease in cash used by investing activities in 2004 of $203.3 million was due primarily to a decrease in capital expenditures of $265.6 million and an increase in proceeds from the sale of oil and gas properties of $83.5 million, which were offset by an increase in cash used for the acquisitions of oil and gas properties of $141.7 million. Net cash used by financing activities in 2004 of $68.3 million included the net repayment of bank borrowings of $206.9 million, offset partially by net proceeds from the issuance of common stock and the exercise of options and warrants of approximately $140.0 million in the aggregate.

        The increase in net cash provided by operating activities in 2003 compared to 2002 was due primarily to higher average oil and gas prices. The increase in cash used by investing activities in 2003 was due primarily to increased investments in oil and gas properties as well as acquisitions in the fourth quarter of 2003. Net cash provided by financing activities in 2003 included net bank borrowings of $197.5 million, net proceeds from the issuance of common stock, and the exercise of options and warrants of approximately $326.5 million in the aggregate, offset partially by cash used for the redemption of the 10¹/2% Senior Subordinated Notes and the repurchase of common stock of $254.1 million in the aggregate.

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Capital Expenditures

        Expenditures for property acquisitions, exploration, and development were as follows:

⁽¹⁾

Does not include estimated discounted asset retirement obligations of $14.1 million and $63.7 million related to assets placed in service during the years ended December 31, 2004 and 2003.

⁽²⁾

Total capital expenditures include both cash expenditures and accrued expenditures. In addition, the property acquisitions include a gross up for deferred income taxes of approximately $50.6 million in 2004 and $32.7 million in 2003. See Note 2 to the Consolidated Financial Statements for the allocation of purchase consideration for various acquisitions in 2004 and 2003.

        Forest's anticipated expenditures for exploration and development in 2005 are estimated to range from $350 million to $400 million. Some of the factors impacting the level of capital expenditures in 2005 include crude oil and natural gas prices, the volatility in these prices, the cost and availability of the oil field services, and weather disruptions.

Dispositions of Oil and Gas Properties

        As part of our ongoing operations, we routinely dispose of non-strategic assets. Assets with marginal value or which are not consistent with our operating strategy are identified for sale or trade. During 2004, we sold assets, including oil and gas assets with estimated proved reserves of approximately 84.6 Bcfe, for total proceeds of approximately $106.4 million. During 2003, we disposed of oil and gas assets with estimated proved reserves of approximately 21 Bcfe for total proceeds of approximately $14.4 million.

Bank Credit Facilities