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

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FORM 10-K

(Mark One)

ý	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004

or

o	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                                to                                 

Commission File Number: 1-13515

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FOREST OIL CORPORATION
(Exact Name of Registrant as Specified in Its Charter)

State of incorporation: New York		I.R.S. Employer Identification No. 25-0484900
1600 Broadway - Suite 2200 - Denver, Colorado (Address of Principal Executive Offices)		80202 (Zip Code)

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

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

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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.

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TABLE OF CONTENTS

PART I
Items 1. and 2.		Business and Properties
Item 3.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
Item 4A.		Executive Officers of Forest
PART II
Item 5.		Market for Registrant's Common Equity and Related Stockholder Matters
Item 6.		Selected Financial and Operating Data
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk
Item 8.		Financial Statements and Supplementary Data
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.		Controls and Procedures
Item 9B.		Other Information
PART III
Item 10.		Directors and Executive Officers of the Registrant
Item 11.		Executive Compensation
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.		Certain Relationships and Related Transactions
Item 14.		Principal Accounting Fees and Services
PART IV
Item 15.		Exhibits, Financial Statement Schedules
		Signatures

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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.

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

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

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

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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:

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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.

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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.

			Year Ended December 31,
			2004								2003
			Developed Acreage				Undeveloped Acreage				Developed Acreage				Undeveloped Acreage
Location
			Gross		Net		Gross		Net		Gross		Net		Gross		Net
United States:
	Gulf Coast		1,012,383		465,126		596,744		346,087		1,058,316		482,651		416,177		306,648
	Western		232,080		131,602		179,529		100,091		312,958		98,636		251,999		114,926
	Alaska		301,990		31,124		1,380,538		1,150,656		305,030		37,379		1,438,220		1,208,798
			1,546,453		627,852		2,156,811		1,596,834		1,676,304		618,666		2,106,396		1,630,372
Canada			185,369		103,964		1,378,226		826,340		209,189		102,887		1,419,937		794,722
International:
	South Africa		—		—		4,774,825		2,927,066		—		—		8,986,446		5,167,647
	Gabon		—		—		2,409,276		963,710		—		—		2,409,276		2,409,276
	Romania		—		—		1,073,693		536,846		—		—		1,073,693		1,073,693
	Italy		—		—		756,857		756,857		—		—		940,926		743,230
	Switzerland		—		—		—		—		—		—		1,850,000		925,000
	Germany		—		—		—		—		—		—		1,050,807		315,241
	Albania		—		—		—		—		—		—		855,123		320,670
			—		—		9,014,651		5,184,479		—		—		17,166,271		10,954,757
Total Acreage			1,731,822		731,816		12,549,688		7,607,653		1,885,493		721,553		20,692,604		13,379,851

        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.

			United States							Canada						Total Company
			2004			2003		2002		2004		2003		2002		2004		2003		2002
Natural Gas:
	Sales price received (per Mcf)		$	6.10		5.27		3.18		4.23		3.09		2.05		5.82		4.98		3.01
	Effects of energy swaps and collars (per Mcf)(1)			(.56	)	(.52	)	.14		—		—		—		(.48	)	(.45	)	.12
	Average sales price (per Mcf)(1)		$	5.54		4.75		3.32		4.23		3.09		2.05		5.34		4.53		3.13
	Natural gas sales volumes (Mcf)			91,420		84,368		78,543		15,946		12,609		13,525		107,366		96,977		92,068
Liquids:
	Oil and Condensate:
	Sales price received (per Bbl)		$	39.24		29.08		24.30		35.49		28.57		23.37		38.88		29.03		24.21
	Effects of energy swaps and collars (per Bbl)(1)			(7.84	)	(4.04	)	(1.90	)	—		—		—		(7.09	)	(3.71	)	(1.72	)
	Average sales price (per Bbl)(1)		$	31.40		25.04		22.40		35.49		28.57		23.37		31.79		25.32		22.49
	Natural gas liquids:
	Average sales price (per Bbl)(1)		$	26.05		18.58		11.57		28.08		20.88		13.35		26.56		19.62		12.27
	Total liquids:
	Average sales price (per Bbl)(1)		$	30.75		24.65		21.40		33.25		25.65		19.63		31.05		24.77		21.16
	Liquids sales volumes (Bbls)			9,550		7,686		7,477		1,287		1,015		1,180		10,837		8,701		8,657
Average sales price (per Mcfe)(1)			$	5.38		4.52		3.41		4.66		3.47		2.47		5.28		4.39		3.28
Total sales volumes (Mcfe)				148,720		130,484		123,405		23,668		18,699		20,605		172,388		149,183		144,010
Total production costs (per Mcfe)			$	1.45		1.07		1.17		.94		.77		.67		1.38		1.03		1.10

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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.

Name		Age		Years with Forest		Office(1)
H. Craig Clark		48		4		President and Chief Executive Officer, and a member of the Board of Directors. Mr. Clark joined Forest in September 2001 as President and Chief Operating Officer. He was appointed President and Chief Executive Officer on July 31, 2003. Mr. Clark was previously employed by Apache Corporation in Houston, Texas, an independent energy company, from 1989 to 2001. He served in various management positions during this period, including Executive Vice President—U.S. Operations and Chairman and Chief Executive Officer of ProEnergy, an affiliate of Apache.
David H. Keyte		48		17		Executive Vice President and Chief Financial Officer since November 1997. Mr. Keyte served as our Vice President and Chief Financial Officer from December 1995 to November 1997 and our Vice President and Chief Accounting Officer from December 1993 until December 1995.
Cecil N. Colwell		54		16		Senior Vice President—Worldwide Drilling since May 2004. Between 2000 and May 2004, Mr. Colwell served as our Vice President—Drilling, and from 1988 to 2000 he served as our Drilling Manager-Gulf Coast.
Leonard C. Gurule		48		2		Senior Vice President—Alaska since September 2003. From 1987 to 2000, he served in various capacities at Atlantic Richfield Co. Between 2000 and September 2003, Mr. Gurule served on the boards of several local community and non-profit organizations and managed his own investment portfolio.

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J.C. Ridens		49		1		Senior Vice President—Gulf Coast since April 2004. From 2001 to 2004, Mr. Ridens was employed by Cordillera Energy Partners, LLC, as Vice President of Operations and Exploitation. From 1996 to 2001, he served in various capacities at Apache Corporation.
R. Scot Woodall		43		5		Senior Vice President—Western United States since March 2004. Mr. Woodall joined Forest in October 2000 and previously served as Production and Engineering Manager for the Western Region. From 1993 to September 2000, he served as Operations and Engineering Manager—Rocky Mountain Division, at Santa Fe Snyder Corporation.
Matthew A. Wurtzbacher		42		6		Senior Vice President—Corporate Planning and Development since May 2003. From December 2000 to May 2003, Mr. Wurtzbacher served as our Vice President—Corporate Planning and Development, and from June 1998 to December 2000 he served as Manager—Operational Planning and Corporate Engineering.
Cyrus D. Marter IV		41		3		Vice President, General Counsel and Secretary since January 2005. Mr. Marter served as Senior Counsel for Forest from June 2002 until October 2004, at which time he became Associate General Counsel. Prior to joining Forest, Mr. Marter was a partner in the law firm of Susman Godfrey L.L.P. in Houston, Texas.
Shelby "Ray" Hornsby		50		*		Controller—Operations Accounting. Mr. Hornsby joined Forest in September 2004. Mr. Hornsby was employed by Redstone Resources, Inc., as a Consultant and Chief Financial Officer from May 2002 to August 2004. From October 2000 to May 2002, he served as a consultant to Forest. He served in various capacities at Central Resources, Inc., from 1992 to 2000, and was Vice President, Finance and Chief Financial Officer from 1994 to 2000.
Victor A. Wind		31		*		Controller—Financial Accounting. Mr. Wind joined Forest in January 2005. Mr. Wind was previously employed by Evergreen Resources, Inc. from July 2001 to December 2004. He served in various management positions during this period, including Director of Financial Reporting and Controller. From 1997 to 2001, he served in various capacities at BDO Seidman, L.L.P.

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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.

			Years Ended December 31,
			2004			2003		2002		2001		2000
			(In Thousands except Per Share Amounts, Volumes and Prices)
FINANCIAL DATA
Revenue:
	Oil and gas sales		$	909,780		655,193		471,740		714,852		623,624
	Processing income, net			3,118		1,985		1,128		(85	)	213
	Total revenue			912,898		657,178		472,868		714,767		623,837
Net earnings from continuing operations				123,126		90,228		21,083		106,437		117,151
(Loss) income from discontinued operations, net of tax(1)				(575	)	(7,731	)	193		(2,694	)	13,457
Cumulative effect of change in accounting principle, net of tax(2)				—		5,854		—		—		—
Net earnings			$	122,551		88,351		21,276		103,743		130,608
Net earnings attributable to common stock			$	122,551		88,351		21,276		103,743		126,440
Basic earnings per share:
	Earnings attributable to common stock from continuing operations		$	2.16		1.82		.45		2.23		2.44
	(Loss) income from discontinued operations, net of tax			(.01	)	(.15	)	—		(.05	)	.29
	Cumulative effect of change in accounting principle, net of tax			—		.12		—		—		—
	Earnings attributable to common stock		$	2.15		1.79		.45		2.18		2.73
Diluted earnings per share:
	Earnings attributable to common stock from continuing operations		$	2.12		1.79		.44		2.16		2.36
	(Loss) income from discontinued operations, net of tax			(.01	)	(.15	)	—		(.05	)	.28
	Cumulative effect of change in accounting principle, net of tax			—		.11		—		—		—
	Earnings attributable to common stock		$	2.11		1.75		.44		2.11		2.64
Total assets			$	3,122,505		2,683,548		1,924,681		1,796,369		1,752,378
Long-term debt			$	888,819		929,971		767,219		594,178		622,234
Other long-term liabilities			$	437,924		294,670		44,576		37,950		31,241
Shareholders' equity			$	1,472,147		1,185,798		921,211		923,943		858,966
OPERATING DATA
Annual production:
	Gas (MMcf)			107,366		96,977		92,068		108,394		113,842
	Liquids (MBbls)			10,837		8,701		8,657		10,600		11,427
Average sales price(3):
	Gas (per Mcf)		$	5.34		4.53		3.13		4.32		3.23
	Liquids (per Bbl)		$	31.05		24.77		21.16		23.31		22.46
Capital expenditures, net of asset sales(4)			$	605,133		716,554		352,812		416,316		372,688

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⁽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:

			Years Ended December 31,
			2004			% Change		2003		% Change		2002
			(In Thousands)
Direct operating expense and workovers			$	193,461		55	%	125,212		(5	)%	131,153
Product transportation				13,635		43	%	9,536		(33	)%	14,174
Production and ad valorem taxes				31,098		60	%	19,422		45	%	13,372
	Total oil and gas production expense		$	238,194		55	%	154,170		(3	)%	158,699
Oil and gas production expense (per Mcfe)			$	1.38		34	%	1.03		(6	)%	1.10

        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:

			Years Ended December 31,
			2004			% Change		2003		% Change		2002
			(In Thousands)
Total overhead costs			$	56,114		(8	)%	60,841		(4	)%	63,642
Overhead costs capitalized				23,969		(2	)%	24,519		(6	)%	26,000
	Total overhead costs expensed		$	32,145		(11	)%	36,322		(4	)%	37,642
General and administrative expense per Mcfe				.19		(21	)%	.24		(8	)%	.26
Total number of employees at end of year				496		8	%	458		—	%	456

        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:

		Years Ended December 31,
		2004			% Change		2003		% Change		2002
		(In Thousands)
Net cash provided by operating activities		$	568,013		49	%	381,984		100	%	190,772
Net cash used by investing activities			(455,901	)	(31	)%	(659,181	)	85	%	(356,613	)
Net cash (used) provided by financing activities			(68,269	)	(125	)%	274,549		61	%	170,828

        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:

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⁽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

        On September 28, 2004, Forest entered into bank credit facilities totaling $600 million, consisting of a $550 million United States credit facility through a syndicate of banks led by JPMorgan Chase and a $50 million Canadian credit facility through a syndicate of banks led by JPMorgan Chase Bank, Toronto Branch. The credit facilities mature in September 2009. Subject to the agreement of Forest and the applicable lenders, the size of the credit facilities may be increased by $200 million in the aggregate.

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        Availability under the credit facilities will be based either on certain financial covenants included in the credit facilities or on the loan value assigned to Forest's oil and gas properties. Forest's current corporate credit ratings are Ba3 with a negative outlook from Moody's and BB- with a stable outlook from S&P. If Forest's corporate credit rating by Moody's is "Ba1" or higher and "BB+" or higher by S&P, the credit facilities may be governed by certain financial covenants. Alternatively, if Forest's corporate credit rating is "Ba2" or lower by Moody's or "BB" or lower by S&P, availability under the credit facilities will be governed by a borrowing base ("Global Borrowing Base"). Availability under the credit facilities currently is governed by the Global Borrowing Base. The Global Borrowing Base is currently set at $500 million, with $480 million allocated to the United States credit facility and $20 million allocated to the Canadian credit facility.

        The determination of the Global Borrowing Base is made by the lenders taking into consideration the estimated value of Forest's oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. This process involves reviewing Forest's estimated proved reserves and their valuation. While the Global Borrowing Base is in effect, it is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, Forest and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the Global Borrowing Base redetermined. A revision to Forest's reserves may prompt such a request on the part of the lenders, which could possibly result in a reduction in the Global Borrowing Base and availability under the credit facilities. If outstanding borrowings under either of the credit facilities exceed the applicable portion of the Global Borrowing Base, Forest would be required to repay the excess amount within a prescribed period. If we are unable to pay the excess amount, it would cause an event of default.

        At December 31, 2004, the unused borrowing amount under the Global Borrowing Base was approximately $341 million. On February 28, 2005, our unused borrowing amount was approximately $427 million.

        At December 31, 2004, there were outstanding borrowings of $152 million under the U.S. credit facility at an average interest rate of 3.66%, and there were no borrowings under the Canadian credit facility. At February 28, 2005, there were outstanding borrowings of $64 million under the U.S. credit facility at a weighted average interest rate of 3.9%, and there were $2.4 million of outstanding borrowings under the Canadian credit facility at an average interest rate of 4.25%. We also had used the U.S. and Canadian credit facilities for letters of credit in the amount of $6.5 million at December 31, 2004 and February 28, 2005.

        The credit facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions. The credit facilities also include several financial covenants. Availability, interest rates, security requirements, and other terms of borrowing under the credit facilities will vary based on Forest's credit ratings and financial condition, as governed by certain financial tests. In particular, any time that availability is not governed by the Global Borrowing Base, the amount available and Forest's ability to borrow under the credit facilities is determined by certain financial covenants. Also, even when availability is governed by the Global Borrowing Base, certain financial covenants can still affect the amount available and Forest's ability to borrow amounts under the credit facilities.

        The credit facilities are collateralized by a portion of Forest's assets. Forest is required to mortgage, and grant a security interest in, 75% of the present value of the proved oil and gas properties of the Company and its subsidiaries. Forest has also pledged the stock of several subsidiaries to the lenders to secure the credit facilities. Under certain circumstances, Forest could be obligated to pledge additional assets as collateral. If Forest's corporate credit ratings by Moody's and S&P improve and meet pre-established levels, the collateral requirements would not apply and, at Forest's request, the banks would release their liens and security interests on Forest's properties.

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Credit Ratings

        Our senior notes are separately rated by two ratings agencies: Moody's and S&P. In addition, Moody's and S&P have assigned Forest a general corporate credit rating.

        Our bank credit facilities include conditions that are linked to our credit rating. The fees and interest rates on our commitments and loans, as well as our collateral obligations, are affected by our credit ratings. If the ratings on our senior notes are changed by either rating agency, the primary effect on us will be a change in the cost of our debt. Our ability to raise funds and the costs of such financing activities may be affected by our credit rating at the time any such activities are conducted.

Common Stock Offerings

        In June 2004, we issued 5.0 million shares of common stock at a price of $24.40 per share. Net proceeds from this offering were approximately $117.1 million after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds from the offering were used to fund a portion of the Wiser acquisition.

        In October 2003, Forest issued 5.1 million shares of common stock at a price of $23.10 per share. Net proceeds from this offering were approximately $112.6 million after deducting underwriting discounts and commissions and estimated offering expenses. We issued 7.9 million shares of common stock at a price of $24.50 per share in January 2003. Net proceeds from this offering (before any exercise of the underwriters' over-allotment option) were approximately $184.4 million after deducting underwriting discounts and commissions and the estimated expenses of the offering. An additional .9 million shares of common stock were issued in February 2003 pursuant to exercise of the underwriters' over-allotment option for net proceeds of $21.2 million.

Debt Offerings

        In July 2004, we issued $125 million in principal amount of 8% Senior Notes, due 2011, at 107.75% of par for proceeds of $133.3 million (net of related offering costs). The net proceeds were used to reduce outstanding borrowings under our U.S. credit facility.

Note Redemptions

        In July 2004, we redeemed, at 101.583% of par value, $125 million in principal amount of 9¹/2% Senior Subordinated Notes due 2007 that were issued by Wiser. The note redemption was funded using borrowings under our U.S. credit facility.

        In January 2003, we redeemed the remaining $66.0 million outstanding principal amount of our 10¹/2% Senior Subordinated Notes at 105.25% of par value, resulting in a loss of $4.0 million recorded in the first quarter of 2003.

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Contractual Obligations

        The following table summarizes our contractual obligations as of December 31, 2004:

		2005			2006		2007		2008		2009		After 2009		Total
		(In Thousands)
Bank debt(1)		$	—		—		—		—		152,000		—		152,000
Other long-term debt(2)			—		—		—		265,000		—		435,000		700,000
Operating leases(3)			6,811		6,216		5,039		4,241		3,800		18,225		44,332
Unconditional purchase obligations(4)			1,329		779		657		559		475		404		4,203
Other liabilities(5)			29,391		13,379		16,104		15,220		17,123		171,024		262,241
Derivative liabilities(6)			80,523		20,890		—		—		—		—		101,413
Approved capital projects(7)			12,018		—		—		—		—		—		12,018
Total contractual obligations		$	130,072		41,264		21,800		285,020		173,398		624,653		1,276,207

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Bank debt consists of $152 million related to our United States and Canadian credit facilities. For a more detailed discussion of our long-term debt, see Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk—Interest Rate Risk," and Note 4 to the Consolidated Financial Statements.

⁽²⁾

Other long-term debt consists of the principal obligations on our senior notes, but does not include anticipated interest payments. For a more detailed discussion of our long-term debt, see Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk—Interest Rate Risk," and Note 4 to the Consolidated Financial Statements.

⁽³⁾

Consists primarily of leases for office space and leases for well equipment rentals.

⁽⁴⁾

Consists primarily of firm commitments for gathering, processing, and pipeline capacity. Gathering, processing, and pipeline capacity commitments in areas that have secondary markets may be mitigated in the future if firm capacities are no longer required.

⁽⁵⁾

Other liabilities represent current and noncurrent liabilities that are comprised of benefit obligations and asset retirement obligations, for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See "Critical Accounting Estimates and Polices" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

⁽⁶⁾

Derivative liabilities represent liabilities for oil and gas commodity derivatives that were valued as of December 31, 2004. The ultimate settlement amounts of the our derivative liabilities are unknown because they are subject to continuing market risk. See "Critical Accounting Policies, Estimates, Judgments, and Assumptions" below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

⁽⁷⁾

Consists of our net share of budgeted expenditures under Authorizations for Expenditure ("AFE") that were approved by us and our joint venture partners as of December 31, 2004. Includes AFEs for which Forest is the operator as well as those operated by others.

        In addition to the above commitments, we are obligated to make approximately $4.9 million of capital expenditures over the next four years pursuant to the terms of foreign concession arrangements. Forest also makes delay rental payments to lessors during the primary terms of oil and gas leases to delay drilling or production of wells, usually for one year. Although we are not obligated to make such payments, discontinuing them would result in the loss of the oil and gas lease. Our total maximum commitment under these leases, through 2015, totaled approximately $7.8 million as of December 31, 2004.

Off-balance Sheet Arrangements

        We have no off-balance sheet arrangements.

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Other Obligations

        We hold a 40% equity interest in an affiliate that owns a petroleum pipeline system within the Cook Inlet area of Alaska. In our capacity as a shareholder, we have agreed to fund our proportionate share of the operating costs and expenses of this affiliate. We may have contingent obligations in the event the affiliate experiences cash deficiencies. In addition, we may have other contingent obligations if the affiliate is unable to meet its indemnification requirements or its obligations to the operator of the pipeline. We are unable to predict or quantify the amount of these obligations, although we have obtained insurance to mitigate the impacts of certain possible outcomes.

Surety Bonds

        In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including governmental agencies. As of February 28, 2005, we had obtained surety bonds from a number of insurance and bonding institutions covering certain of our operations in the United States and Canada in the aggregate amount of approximately $19.1 million. See Part I, Items 1 and 2—"Business and Properties—Regulation" for further information.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Critical Estimates

        The following items are estimates used in the preparation of our financial statements that management deems to be "critical" in nature because either (i) the accounting estimate requires us to make assumptions about matters that are highly uncertain at the time the accounting estimate is made, and different estimates could have reasonably been used for the accounting estimate in the current period, or (ii) in our judgment changes in the accounting estimate that are reasonably likely to occur from period to period would have a material impact on the presentation of Forest's financial condition, changes in financial condition, or results of operations.

Oil and Gas Reserve Estimates

        Our estimate of proved reserves is based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production, and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a "ceiling" limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

        Reference should be made to "Independent Audit of Reserves" included under Part I, Items 1 and 2—"Business and Properties" of this document as well as "Estimates of oil and gas reserves are uncertain and inherently imprecise" under Part II, Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Fair Values of Derivatives

        The fair market value of all derivative instruments is recognized as an asset or liability on our balance sheet. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is: (i) a cash flow hedge or (ii) a fair value hedge, and upon whether or not the derivative qualifies as an effective hedge. Changes in the fair value of effective cash flow hedges are recognized in other comprehensive income until the hedged item is recognized in earnings. For fair value hedges, to the extent the hedge is effective there is no effect on the statement of operations, because changes in the fair value of the derivative instrument offset changes in the fair value of the hedged item. For derivative instruments that do not qualify as fair value hedges or cash flow hedges, changes in fair value are recognized in earnings as other income or expense.

        The estimated fair values of the Company's derivative instruments require substantial judgment. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control. Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated, because energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

        Due to the volatility of oil and natural gas prices, the fair values of our derivative instruments are subject to large fluctuations in estimated fair value from period to period. For example, a hypothetical increase or decrease in the forward oil and natural gas prices used to calculate the fair value of the derivative instruments of $1.00 per barrel and $.25 per Mmbtu, respectively, would change the fair values of our derivative instruments by approximately $18 million. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains or losses recognized in conjunction with our commodity derivative contracts will likely differ from those estimated at December 31, 2004 and will depend exclusively on the price indexes of the commodities on the specified settlement dates provided by the derivative contracts. As the majority of our commodity derivative contracts qualify as cash flow hedges under SFAS 133 (See Note 8 to the Consolidated Financial Statements), while the use of different estimates in the calculation of the fair values of the commodity derivative contracts may materially affect our balance sheet, it would not materially affect our reported earnings or cash flows.

Valuation of Deferred Tax Assets

        We use the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax bases (temporary differences). Future income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on future income tax assets and liabilities of a change in tax rates is included in operations in the period in which the change is enacted. The amount of future income tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.

        In assessing the value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this

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assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2004. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward periods are reduced.

Asset Retirement Obligations

        The Company has significant obligations to remove tangible equipment and restore locations at the end of the oil and gas production operations. Forest's removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future restoration and removal costs, or asset retirement obligations, is difficult and requires management to make estimates and judgments, because most of the removal obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

        Inherent in the calculation of the present value of our asset retirement obligations ("ARO") under SFAS 143 are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time will be reflected as accretion expense in the consolidated statement of operations.

Critical Policies

        The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the full-cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in our financial statements. We have elected to follow the full-cost method, which is described below.

Full-Cost Method of Accounting

        Under the full-cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities is capitalized, with a corresponding asset retirement obligation liability recorded. Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are accounted for prospectively in the depletion calculations. Assuming consistent production year over year, our depletion expense will be significantly higher or lower if we significantly decrease or increase our estimates of remaining proved reserves.

        Investments in unproved properties are not depleted pending the determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and

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geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized in the appropriate full cost pool, or reported as impairment expense in the Consolidated Statements of Operations, as applicable.

        Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed on a country-by-country basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves, as adjusted for asset retirement obligations and the effect of cash flow hedges. This ceiling is compared to the net book value of the oil and gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash writedown is required. A ceiling test impairment could cause Forest to record a significant non-cash loss for a particular period; however, future DD&A expense would be reduced.

        At December 31, 2004, the spot price that Forest used for its Canadian low gravity oil in computing its cost center ceiling was temporarily depressed to a level at which Forest's capitalized costs in its Canadian cost center would have exceeded the cost center ceiling, as described above, by approximately $10 million. Subsequent to December 31, 2004 and before the release of these annual financial statements, the spot price of Canadian low gravity oil increased to levels such that Forest's Canadian cost center ceiling exceeded its capitalized costs. As such, no impairment adjustment to the Canadian cost center was necessary as of December 31, 2004.

        In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs are charged against earnings as impairments.

        Under the alternative "successful efforts method" of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, dry holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property by property basis under the successful efforts method. Impairments are assessed on a property by property basis and are charged to expense when assessed.

        In general, the application of the full cost method of accounting results in higher capitalized costs and higher depletion rates compared to the successful efforts method.

        The full cost method is used to account for our oil and gas exploration and development activities, because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

Impact of Recently Issued Accounting Pronouncements

        In May 2004, the Financial Accounting Standards Board ("FASB") issued Staff Position ("FSP") No. 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004" ("FSP 109-2"). FSP 109-2 provides guidance under FASB Statement of Accounting Standard ("SFAS") No. 109, "Accounting for Income Taxes," with respect to recording the potential impact of the repatriation provisions of the American Jobs Creation

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Act of 2004 (the "Jobs Act") on enterprises' income tax expense and deferred tax liability. The Jobs Act was enacted on October 22, 2004. FSP 109-2 states that an enterprise is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. We continue to evaluate the impact of the repatriation provisions. Accordingly, as provided for in FSP 109-2, we have not adjusted our tax expense or deferred tax liability to reflect the repatriation provisions of the Jobs Act.

        In December 2004, the FASB issued SFAS No. 123(R) "Share-Based Payment", which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123(R) is effective for public companies for interim or annual periods beginning after June 15, 2005, supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends SFAS No. 95, Statement of Cash Flows. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS 123 will no longer be an alternative to financial statement recognition. SFAS 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce Forest's future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future.

        We are required to adopt SFAS 123(R) in our third quarter of fiscal 2005, beginning July 1, 2005. Under SFAS 123(R), we must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive options, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoption of SFAS 123(R); the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. We are evaluating the requirements of SFAS 123(R), and we expect that the adoption of SFAS 123(R) will have a material impact on our consolidated results of operations and earnings per share. We have not yet determined the method of adoption or the effect of adopting SFAS 123(R), and we have not determined whether the adoption will result in amounts that are similar to the current pro forma disclosures under SFAS 123.

        Forest has an Employee Stock Purchase Plan (the "ESPP") that allows eligible employees to annually purchase the Company's common stock at a discount. The provisions of SFAS 123(R) will cause the ESPP to be a compensatory plan. However, the change in accounting for the ESPP is not expected to have a material impact on Forest's financial position, future results of operations, or liquidity. Historically, the ESPP compensatory amounts have been nominal. See Note 6 to the Consolidated Financial Statements for additional information regarding the ESPP.

        In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions" ("SFAS 153"). SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, "Accounting for Nonmonetary Transactions," and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for the fiscal periods beginning after June 15, 2005. We are currently evaluating the effect that the adoption of

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SFAS 153 will have on our consolidated results of operations and financial condition but do not expect it to have a material impact.

        In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") No. 106 regarding the application of SFAS No. 143, "Accounting for Asset Retirement Obligations," by oil and gas producing entities that follow the full cost accounting method. SAB No. 106, effective in the fourth quarter of 2004, states that after adoption of SFAS No. 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. Forest has accounted for its asset retirement obligations in this manner since the adoption of SFAS No. 143 and, therefore, SAB No. 106 will have no effect on the Company's financial statements or its ceiling test computation.

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 described below, under the heading "Risk Factors."

        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 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

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further production and development drilling. Accordingly, reserve estimates may differ significantly 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, expressed 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.

Risk Factors

        Oil and gas price declines could adversely affect Forest's revenue, cash flows, and profitability.    Prices for oil and natural gas fluctuate widely. Forest's revenues, profitability, and future rate of growth depend substantially upon the prevailing prices of oil and natural gas. Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of oil and natural gas that Forest can produce economically. Any substantial or extended decline in the prices of or demand for oil and natural gas would have a material adverse effect on our financial condition and results of operations.

        We cannot predict future oil and natural gas prices. Factors that can cause price fluctuations include: relatively minor changes in the supply of and demand for oil and natural gas; market uncertainty; the level of consumer product demand; weather conditions; domestic and foreign governmental regulations; the price and availability of alternative fuels; political and economic conditions in oil producing countries, particularly those in the Middle East; the foreign supply of oil and natural gas; the price of oil and gas imports; or general economic conditions.

        We may not be able to obtain adequate financing to execute our operating strategy.    We have historically addressed our long-term liquidity needs through the use of bank credit facilities, cash provided by operating activities, and the issuance of debt and equity securities when market conditions permit. We continue to examine alternative sources of long-term capital such as bank borrowings or the issuance of debt securities; the issuance of common stock, preferred stock or other equity securities; sales of properties; the issuance of non-recourse production-based financing or net profits interests; sales of prospects and technical information; and joint venture financing.

        The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, and the value and performance of Forest. We may be unable to execute our operating strategy if we cannot obtain capital from these sources.

        Availability under our bank credit facility is based on a global borrowing base that is redetermined semi-annually, and may be redetermined at other times during a year at the option of the Company or the lenders. The global borrowing base may be reduced if oil and gas prices decline or we have downward revisions in our estimate of proved reserves. See "Leverage will materially affect our operations," below.

        In addition, if availability under our credit facilities is reduced as a result of a borrowing base limitation or the covenants and financial tests contained in the agreements, our ability to fund our planned capital expenditures could be adversely affected. After utilizing our available sources of

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financing, we could be forced to raise additional debt or equity proceeds to fund such expenditures. We cannot assure you that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

        A curtailment of capital spending could adversely affect our ability to replace production and our future cash flow from operations.

        Estimates of oil and gas reserves are uncertain and inherently imprecise.    Estimating our proved reserves involves many uncertainties, including factors beyond our control. Petroleum engineers consider many factors and make assumptions in estimating oil and gas reserves and future net cash flows. Lower oil and gas prices generally cause lower estimates of proved reserves. Ultimately, actual production, revenues, and expenditures relating to our reserves will vary from any estimates, and these variations may be material. Also, we may revise estimates of proved reserves to reflect production history, results of exploration and development, and other factors, many of which are beyond our control. See Note 13, items (D) and (F), to the Consolidated Financial Statements, below, for further discussion of a downward revision of our reserves in 2003. We could incur writedowns of our United States and Canadian full cost pools under "ceiling test" limitations pursuant to full cost accounting as a result of lower oil and gas "spot" prices in the future or downward future reserve revisions. If we were to record writedowns, shareholders' equity could be reduced significantly.

        Also, you should not assume that the present value of future net cash flows referred to in this Form 10-K is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual current and future prices and costs may differ materially from those used in the SEC net present value estimate; and as a result, net present value estimates using actual prices and costs may be significantly less than the SEC estimate that is provided in this Form 10-K.

        Leverage will materially affect our operations.    As of December 31, 2004, the principal amount of our long-term debt was approximately $852 million, including approximately $152 million outstanding under our global bank credit facilities. Our long-term debt represented 38% of our total capitalization at December 31, 2004. Further, we may incur additional debt in the future, including in connection with acquisitions and refinancings.

        The level of our debt could have several important effects on our future operations, including, among others:

•

a significant portion of our cash flow from operations will be applied to the payment of principal and interest on the debt and will not be available for other purposes;



•

credit rating agencies have changed, and may continue to change, their ratings of our debt and other obligations as a result of changes in our debt level, financial condition, earnings, and cash flow; such ratings changes would in turn impact the costs, terms, conditions, and availability of financing;



•

covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;



•

our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate, and other purposes may be limited or burdened by increased costs or more restrictive covenants;



•

we may be at a competitive disadvantage to similar companies that have less debt; and



•

our vulnerability to adverse economic and industry conditions may increase.

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        Lower oil and gas prices may cause us to record ceiling limitation writedowns.    We use the full cost method of accounting to report our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit," which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test writedown." This charge would not impact cash flow from operating activities, but it would reduce our shareholders' equity. The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. We cannot assure you that we will not experience ceiling test writedowns in the future. Our Canadian full cost pool, in particular, could be adversely impacted by moderate declines in commodity prices.

        We may incur significant abandonment costs or be required to post substantial performance bonds in connection with the plugging and abandonment of wells, platforms, and pipelines.    We are responsible for the costs associated with the plugging of wells, the removal of facilities and equipment, and site restoration on our oil and gas properties, pro rata to our working interest. Future liabilities for projected abandonment costs, net of estimated salvage values, are included as a reduction in the future cash flows from our reserves in our reserve reporting. As of December 31, 2004, our estimated discounted asset retirement obligation liability recorded in the balance sheet was approximately $210.2 million, primarily for properties in offshore Gulf of Mexico and the Cook Inlet of Alaska. Approximately $33.8 million of abandonment costs were settled in 2004 and $25.5 million of abandonment costs are anticipated to be settled in 2005, all of which are expected to be funded by cash flow from operations. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, changes in abandonment techniques and technology, and changes in environmental laws and regulations.

        We may not be able to replace production with new reserves.    In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Many Gulf of Mexico reservoirs experience high decline rates, while the decline rates in long-lived fields in other regions are lower. Production from the offshore Gulf Coast reservoirs represented approximately 48% of our total production in 2004. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful exploration and development activities. Forest's future natural gas and oil production is highly dependent upon its level of success in finding or acquiring additional reserves. The business of exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may be unable to make the necessary capital investment to maintain or expand our oil and gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

        Our operations are subject to numerous risks of oil and gas drilling and production activities.    Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. Oil and gas drilling and production activities may be shortened, delayed, or canceled as a result of a variety of factors, many of which are beyond our control. These factors include unexpected drilling conditions; geological irregularities or pressure in formations; equipment failures or accidents; weather conditions; shortages in labor; shortages or delays in the delivery of equipment; and failure to secure necessary regulatory approvals and permits.

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        The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment, and related services.

        We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs.

        We may not be insured against all of the operating risk to which our business is exposed.    The exploration, development, and production of oil and natural gas involves risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations, and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures, or discharges of toxic gases. If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. For example, a substantial portion of our oil and gas operations is located offshore in the Gulf of Mexico. The Gulf of Mexico area experiences tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and interrupt production. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. We cannot assure you that our insurance will be fully adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

        Our international operations may be adversely affected by currency fluctuations and economic and political developments.    We have significant oil and gas operations in Canada. The expenses and revenues of such operations, which represented approximately 14% of consolidated costs of oil and gas operations, and 12% of our consolidated oil and gas revenues in 2004, are denominated in Canadian dollars. As a result, the profitability of our Canadian operations is subject to the risk of fluctuations in the relative value of the Canadian and United States dollars. We have also acquired additional oil and gas assets in other countries. Although there are no material operations in these countries, our foreign operations may also be adversely affected by political and economic developments, royalty and tax increases, and other laws or policies in these countries, as well as United States policies affecting trade, taxation, and investment in other countries. In South Africa we have an interest in offshore properties with the potential for gas production. No proved reserves have been assigned to these properties as commercial sales contracts have not been established. If we are unable to arrange for commercial use of these properties, we may not be able to recoup our investment and will not realize our anticipated financial and operating results from these properties.

        Hedging transactions may limit our potential gains.    In order to manage our exposure to price risks in the marketing of our oil and natural gas, we enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedges are limited in duration, usually for periods of one year or less. However, in connection with acquisitions, sometimes our hedges are for longer periods. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains if oil and gas prices rise over the price established by the arrangements. In trying to maintain an appropriate balance, we may end up hedging too much or too little, depending upon how oil or natural gas prices fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our future contracts fail to perform under the contracts; or a sudden unexpected event materially impacts oil or natural gas prices.

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        We cannot assure you that our hedging transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. For further information concerning prices, market conditions, and energy swap and collar agreements, see Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk" of this Form 10-K, and Note 8 to the Consolidated Financial Statements.

        Competition within our industry may adversely affect our operations.    We operate in a highly competitive environment. Forest competes with major and independent oil and gas companies in acquiring desirable oil and gas properties and in obtaining the equipment and labor required to develop and operate such properties. Forest also competes with major and independent oil and gas companies in the marketing and sale of oil and natural gas. Many of these competitors have financial and other resources substantially greater than ours.

        Our growth may partially depend on our ability to acquire oil and gas properties on a profitable basis.     Acquisition of producing oil and gas properties is a key element of maintaining and growing reserves and production. Competition for these assets has been and will continue to be intense. The success of any acquisition will depend on a number of factors, including the purchase price, future oil and gas prices, the ability to reasonably estimate or assess the recoverable volumes of reserves, rates of future production and future net revenues attainable from reserves, future operating and capital costs, results of future exploration, exploitation and development activities on the acquired properties, and future abandonment and possible future environmental liabilities.

        There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, actual future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results may vary substantially from those assumed in the estimates.

        Our oil and gas operations are subject to various governmental regulations that materially affect our operations.    Our oil and gas operations are subject to various United States federal, state, and local and Canadian federal and provincial governmental regulations. These regulations may be changed in response to economic or political conditions. Matters regulated include permits for discharges of wastewaters and other substances generated in connection with drilling operations, bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs, reports concerning operations, the spacing of wells, and unitization and pooling of properties and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies may restrict the rates of flow of oil and gas wells below actual production capacity. In addition, the Federal Oil Pollution Act ("OPA"), as amended, requires operators of offshore facilities to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other federal and state environmental statutes, owners and operators of certain defined facilities are strictly liable for such spills of oil and other regulated substances, subject to certain limitations. A substantial spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. United States and non-United States laws regulate production, handling, storage, transportation, and disposal of oil and gas, by-products from oil and gas, and other substances and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

        We have limited control over the activities on properties we do not operate.    Although we operate the properties from which most of our production is derived, other companies operate some of our other properties. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund for their operation. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties

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could have a material adverse effect on the realization of our targeted returns or lead to unexpected future costs.

        Our Restated Certificate of Incorporation and By-laws have provisions that discourage corporate takeovers.    Certain provisions of our Restated Certificate of Incorporation and Bylaws and provisions of the New York Business Corporation Law may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms. Also, our Restated Certificate of Incorporation authorizes our board of directors to issue preferred stock without shareholder approval and to set the rights, preferences, and other designations, including voting rights of those shares as the board may determine. Additional provisions include restrictions on business combinations, the availability of authorized but unissued common stock, and notice requirements for shareholder proposals and director nominations. These provisions, alone or in combination with each other and with the rights plan described below, may discourage transactions involving actual or potential changes of control.

        In addition, our board of directors has adopted a shareholder rights plan. If activated, the plan would cause extreme dilution to any person or group that attempts to acquire a significant interest in Forest without advance approval of our board of directors.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

        We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign currency exchange rates, and interest rates as discussed below.

Commodity Price Risk

        We produce and sell natural gas, crude oil, and natural gas liquids for our own account in the United States and Canada. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant.

Hedging Program

        In order to reduce the impact of fluctuations in prices, or to protect the economics of property acquisitions, we make use of an oil and gas hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in our credit facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons. Hedging arrangements covered 56%, 52%, and 42% of our consolidated production, on an equivalent basis, during the years ended December 31, 2004, 2003, and 2002, respectively. We do not enter into derivative instruments for trading purposes.

Swaps

        In a typical commodity swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher, Forest pays the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged

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production. Our current swaps are settled in cash on a monthly basis. As of December 31, 2004, Forest had entered into the following swaps accounted for as cash flow hedges:

Collars

        Forest also enters into collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price; and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price.

        Collars are also settled in cash, either on a monthly basis or at the end of their terms. By entering into collars, we effectively provide a floor for the price that we will receive for the hedged production; however, the collar also establishes a maximum price that we will receive for the hedged production if prices increase above the ceiling price. We enter into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for foregoing the benefit of price increases in excess of the ceiling price on the hedged production. As of December 31, 2004, Forest had entered into the following gas and oil collars accounted for as cash flow hedges:

        In addition, Forest has entered into three-way collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, we receive the difference between the two floors. If the index price is between the two floors, we receive the difference between the higher of the two floors and the index price. If the index price is between

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the higher floor and the ceiling, we do not receive or pay any additional amounts. If the index price is above the ceiling, we pay the excess over the ceiling price.

        As of December 31, 2004, Forest had entered into the following three-way oil collars accounted for as cash flow hedges:

        The fair value of our cash flow hedges based on the futures prices quoted on December 31, 2004 was a liability of approximately $88.9 million. As of December 31, 2004, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 40 Bbtu per day for 2005.

        Forest also obtained the following collar agreements in the Wiser acquisition. These collar agreements could not be designated as cash flow hedges by Forest under generally accepted accounting principles, because the collars had unrealized losses at the date of the Wiser acquisition.

        The fair value of our derivative instruments not designated as cash flow hedges on December 31, 2004 was a liability of approximately $1.3 million, based on the future prices quoted on that day.

        The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2004, beginning with the fair value of the our commodity contracts on December 31, 2003, less the decrease in fair value during the period and the fair value of commodity contracts acquired in connection with the acquisition of oil and gas companies, plus the contract losses settled and recognized during the period.

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        Subsequent to December 31, 2004, we entered into the following derivative instruments primarily to hedge the economics of a recent acquisition.

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*

Represents weighted average floor and ceiling.

Long-Term Sales Contracts

        A portion of Canadian Forest's natural gas production is sold in a joint venture with other producers (the "Canadian Netback Pool"). The Canadian Netback Pool's resale markets are comprised of market based and fixed price contracts. Canadian Forest's average daily production sold through the Canadian Netback Pool represented approximately 4% of Forest's total average daily production in 2004. Canadian Forest supplied 41% of the Canadian Netback Pool sales quantity in 2004, and it is estimated that Canadian Forest will supply 44% of the Canadian Netback Pool quantity in the 2005 contract year. We expect that Canadian Forest's pro rata obligations as a gas producer will increase in 2005 and future years. At December 31, 2004, the weighted average price paid under the resale contracts was approximately 82% of market value based on the closing AECO prices on that date. To the extent the Canadian Netback Pool's supply is insufficient to meet the delivery obligations under the resale contracts, as is currently the case, the Canadian Netback Pool must make up the shortfall by purchasing spot market gas at prices that currently exceed the prices paid under the resale contracts. This shortfall could increase if individual producers were to default on their supply obligations owed to the Canadian Netback Pool. See Note 10 to the Consolidated Financial Statements for more information.

Foreign Currency Exchange Risk

        We conduct business in several foreign currencies and thus are subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing, and investing transactions. In the past, we have not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk. Expenditures incurred relative to the foreign concessions held by Forest outside of North America have been primarily United States dollar-denominated, as have cash proceeds related to property sales and farmout arrangements. Substantially all of our Canadian revenues and costs are denominated in Canadian dollars. While the value of the Canadian dollar does fluctuate in relation to the U.S. dollar, we believe that any currency risk associated with our Canadian operations would not have a material impact on our results of operations.

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Interest Rate Risk

        The following table presents principal amounts and related average fixed interest rates by year of maturity for Forest's debt obligations at December 31, 2004:

---

⁽¹⁾

As of December 31, 2004.

⁽²⁾

The effective interest rate on the 8% Senior Notes due 2008, the 8% Senior Notes due 2011, and the 7³/4% Senior Notes due 2014 will be reduced from the coupon rate as a result of amortization of gains related to termination of related interest rate swaps.

Item 8. Financial Statements and Supplementary Data.

        Information concerning this Item begins on the following page.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Forest Oil Corporation:

        We have audited the accompanying consolidated balance sheets of Forest Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Forest Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

        As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards Nos. 143 and 145; and effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Forest Oil Corporation's internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2005 expressed an unqualified opinion on management's assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Denver, Colorado
March 15, 2005

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FOREST OIL CORPORATION

CONSOLIDATED BALANCE SHEETS

					December 31,
					2004			2003
					(In Thousands Except Share Data)
ASSETS
Current assets:
	Cash and cash equivalents				$	55,251		11,509
	Accounts receivable					151,927		158,954
	Derivative instruments					8,913		4,130
	Current deferred tax asset					38,321		23,302
	Other current assets					29,056		17,465
			Total current assets			283,468		215,360
Property and equipment, at cost:
	Oil and gas properties, full cost method of accounting:
			Proved, net of accumulated depletion of $2,701,402 and $2,322,434			2,495,894		2,263,554
			Unproved			213,870		162,489
	Net oil and gas properties					2,709,764		2,426,043
	Other property and equipment, net of accumulated depreciation and amortization of $28,797 and $24,717					11,354		7,923
			Net property and equipment			2,721,118		2,433,966
Goodwill						68,560		—
Other assets						49,359		34,222
					$	3,122,505		2,683,548
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable				$	202,537		192,001
	Accrued interest					4,292		3,869
	Derivative instruments					80,523		49,838
	Asset retirement obligations					25,452		23,243
	Other current liabilities					10,811		4,158
			Total current liabilities			323,615		273,109
Long-term debt						888,819		929,971
Asset retirement obligations						184,724		188,189
Derivative instruments						20,890		9,696
Other liabilities						35,785		24,062
Deferred income taxes						196,525		72,723
Commitments and contingencies (Note 10)
Shareholders' equity:
	Preferred stock, none issued and outstanding					—		—
	Common stock, 61,595,024 and 55,631,924 shares issued and outstanding					6,159		5,563
	Capital surplus					1,444,367		1,302,340
	Retained earnings (accumulated deficit)					66,007		(56,495	)
	Accumulated other comprehensive income (loss)					6,780		(9,740	)
	Treasury stock, at cost, 1,901,807 and 2,076,731 shares held					(51,166	)	(55,870	)
			Total shareholders' equity			1,472,147		1,185,798
					$	3,122,505		2,683,548

See accompanying Notes to Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

						Years Ended December 31,
						2004			2003		2002
						(In Thousands Except Per Share Amounts)
Revenue:
	Oil and gas sales:
		Natural gas				$	573,342		439,700		288,542
		Oil, condensate and natural gas liquids					336,438		215,493		183,198
			Total oil and gas sales				909,780		655,193		471,740
	Processing income, net						3,118		1,985		1,128
				Total revenue			912,898		657,178		472,868
Operating expenses:
	Oil and gas production						238,194		154,170		158,699
	General and administrative						32,145		36,322		37,642
	Depreciation and depletion						354,092		234,822		185,288
	Impairment and other						12,929		16,910		—
	Accretion of asset retirement obligations						17,251		13,785		—
				Total operating expenses			654,611		456,009		381,629
Earnings from operations							258,287		201,169		91,239
Other income and expense:
	Other (income) expense, net						(1,427	)	6,964		7,682
	Interest expense						57,844		49,341		50,433
				Total other income and expense			56,417		56,305		58,115
Earnings before income taxes, discontinued operations, and cumulative effect of change in accounting principle							201,870		144,864		33,124
Income tax expense:
	Current						2,960		693		228
	Deferred						75,784		53,943		11,813
				Total income tax expense			78,744		54,636		12,041
Net earnings from continuing operations							123,126		90,228		21,083
	(Loss) income from discontinued operations, net of tax						(575	)	(7,731	)	193
	Cumulative effect of change in accounting principle, net of tax						—		5,854		—
Net earnings						$	122,551		88,351		21,276
Basic earnings per common share:
	Earnings from continuing operations					$	2.16		1.82		.45
		Loss from discontinued operations, net of tax					(.01	)	(.15	)	—
		Cumulative effect of change in accounting, net of tax					—		.12		—
	Net earnings per common share					$	2.15		1.79		.45
Diluted earnings per common share:
	Earnings from continuing operations					$	2.12		1.79		.44
		Loss from discontinued operations, net of tax					(.01	)	(.15	)	—
		Cumulative effect of change in accounting principle, net of tax					—		.11		—
	Net earnings per common share					$	2.11		1.75		.44

See accompanying Notes to Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

			Common Stock							Retained Earnings (Accumulated Deficit)		Accumulated Other Comprehensive Income (Loss)
								Capital Surplus						Treasury Stock		Total Shareholders' Equity
			Shares		Amount
			(In Thousands)
Balances at January 1, 2002			48,834		$	4,883		1,145,282		(165,824	)	(4,147	)	(56,251	)	923,943
	Exercise of warrants to purchase 17,971 shares of common stock		18			2		231		—		—		—		233
	Stock options exercised		265			26		4,059		—		—		—		4,085
	Tax benefit of stock options exercised		—			—		865		—		—		—		865
	Tax benefit of additional acquired net operating losses and other tax assets		—			—		8,800		—		—		—		8,800
	Employee stock purchase plan		21			3		457		—		—		—		460
	Purchase of 21,894 treasury shares		—			—		—		—		—		(560	)	(560	)
	Retirement of 1,584 shares in lieu of taxes on restricted stock award		—			—		(43	)	—		—		—		(43	)
	Other		(12	)		(1	)	(382	)	—		—		275		(108	)
Comprehensive loss:
	Net earnings		—			—		—		21,276		—		—		21,276
	Unrealized loss on market value of investment, net of tax		—			—		—		—		(94	)	—		(94	)
	Unrealized loss on effective derivative instruments, net of tax		—			—		—		—		(36,650	)	—		(36,650	)
	Increase in unfunded pension liability, net of tax		—			—		—		—		(3,595	)	—		(3,595	)
	Foreign currency translation		—			—		—		—		2,599		—		2,599
	Total comprehensive loss															(16,464	)
Balances at December 31, 2002			49,126			4,913		1,159,269		(144,548	)	(41,887	)	(56,536	)	921,211
	Common stock issued, net of offering costs		6,023			602		132,982		—		—		—		133,584
	Exercise of warrants to purchase 1,573 shares of common stock		2			—		33		—		—		—		33
	Stock options exercised		462			46		7,386		—		—		—		7,432
	Tax benefit of stock options exercised		—			—		1,014		—		—		—		1,014
	Employee stock purchase plan		21			2		422		—		—		—		424
	Retirement of 1,583 shares in lieu of taxes on restricted stock award		—			—		(44	)	—		—		—		(44	)
	Issuance of treasury stock for option exercises		—			—		—		(298	)	—		666		368
	Other		(2	)		—		1,278		—		—		—		1,278
Comprehensive earnings:
	Net earnings		—			—		—		88,351		—		—		88,351
	Unrealized gain on market value of investment, net of tax		—			—		—		—		481		—		481
	Unrealized loss on effective derivative instruments, net of tax		—			—		—		—		(17,076	)	—		(17,076	)
	Increase in unfunded pension liability, net of tax		—			—		—		—		(534	)	—		(534	)
	Foreign currency translation		—			—		—		—		49,276		—		49,276
	Total comprehensive earnings															120,498

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Balances at December 31, 2003			55,632			5,563		1,302,340		(56,495	)	(9,740	)	(55,870	)	1,185,798
	Common stock issued, net of offering costs		5,030			503		116,585		—		—		—		117,088
	Exercise of warrants to purchase 162,901 shares of common stock		163			16		3,093		—		—		—		3,109
	Stock options exercised		828			82		19,116		—		—		—		19,198
	Tax benefit of stock options exercised		—			—		2,168		—		—		—		2,168
	Employee stock purchase plan		22			3		507		—		—		—		510
	Retirement of 501 shares in lieu of taxes on restricted stock award		—			—		—		—		—		(15	)	(15	)
	Issuance of treasury stock for option exercises		(80	)		(8	)	(1,819	)	(320	)	—		2,147		—
	Restricted stock issued		—			—		(2,640	)	271		—		2,572		203
	Tax benefit of acquired net operating losses		—			—		5,283		—		—		—		5,283
	Other		—			—		(266	)	—		—		—		(266	)
Comprehensive earnings:
	Net earnings		—			—		—		122,551		—		—		122,551
	Unrealized loss on effective derivative instruments, net of tax		—			—		—		—		(18,269	)	—		(18,269	)
	Decrease in unfunded pension liability, net of tax		—			—		—		—		5,565		—		5,565
	Foreign currency translation		—			—		—		—		29,224		—		29,224
	Total comprehensive earnings															139,071
Balances at December 31, 2004			61,595		$	6,159		1,444,367		66,007		6,780		(51,166	)	1,472,147

See accompanying Notes to Consolidated Financial Statements.

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FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

						Years Ended December 31,
						2004			2003		2002
						(In Thousands)
Operating activities:
	Net earnings					$	122,551		88,351		21,276
		Adjustments to reconcile net earnings to net cash provided by operating activities:
			Depreciation and depletion				354,092		236,148		186,221
			Impairment and other				11,361		16,910		—
			Accretion of asset retirement obligations				17,251		13,785		—
			Amortization of deferred hedge gain				(4,988	)	(4,561	)	(791	)
			Amortization of deferred debt costs				2,081		2,315		2,233
			Unrealized loss (gain) on derivative instruments, net				1,088		(451	)	788
			Deferred income tax expense				76,506		61,730		11,997
			(Earnings) loss of equity method investee				(1,726	)	2,043		(30	)
			Other, net				(789	)	366		3,156
			Changes in operating assets and liabilities, net of effects of acquisitions:
				Accounts receivable			32,754		(34,388	)	23,196
				Other current assets			(7,610	)	6,281		7,929
				Accounts payable			(43,456	)	22,204		(59,065	)
				Accrued interest and other current liabilities			8,898		(28,749	)	(6,138	)
			Net cash provided by operating activities				568,013		381,984		190,772
Investing activities:
	Acquisition of subsidiaries						(223,834	)	(82,160	)	—
	Capital expenditures for property and equipment:
	Exploration, development and other acquisition costs						(317,166	)	(583,332	)	(354,220	)
	Other fixed assets						(2,829	)	(2,251	)	(4,057	)
	Proceeds from sale of assets						97,933		14,445		5,465
	Sale of goodwill and contract value						8,493		—		—
	Increase in other assets, net						(18,498	)	(5,883	)	(3,801	)
			Net cash used by investing activities				(455,901	)	(659,181	)	(356,613	)
Financing activities:
	Proceeds from bank borrowings						2,025,074		865,511		466,760
	Repayments of bank borrowings						(2,232,000	)	(668,000	)	(391,371	)
	Proceeds from termination of interest rate swaps						—		5,057		35,630
	Issuance of 73/4% senior notes, net of offering costs						—		—		146,846
	Issuance of 8% senior notes, net of offering costs						133,312		—		—
	Redemption of 91/2% senior notes						(126,971	)	—		—
	Repurchase of 83/4% senior subordinated notes						—		—		(66,248	)
	Redemption and repurchase of 101/2% senior subordinated notes						—		(69,441	)	(23,935	)
	Proceeds of common stock offerings, net of offering costs						117,088		318,216		—
	Repurchase and retirement of common stock						—		(184,632	)	—
	Proceeds from the exercise of options and warrants						22,894		8,257		4,671
	Other, net						146		—		(560	)
	Settlement of acquired derivative instruments						(8,833	)	—		—
	Increase (decrease) in other liabilities, net						1,021		(419	)	(965	)
			Net cash (used) provided by financing activities				(68,269	)	274,549		170,828
Effect of exchange rate changes on cash							(101	)	991		(208	)
Net increase (decrease) in cash and cash equivalents							43,742		(1,657	)	4,779
Cash and cash equivalents at beginning of year							11,509		13,166		8,387
Cash and cash equivalents at end of year						$	55,251		11,509		13,166
Cash paid during the year for:
	Interest					$	64,687		55,632		51,038
	Income taxes						3,790		1,968		720

See accompanying Notes to Consolidated Financial Statements.

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FOREST OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2004, 2003, and 2002

(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Description of the Business

        Forest Oil Corporation is engaged in the acquisition, exploration, development, and production of natural gas and liquids. The Company was incorporated in New York in 1924, the successor to a company formed in 1916, and has been publicly held since 1969. The Company is active in several of the major exploration and producing areas in and offshore the United States and in Canada, and has exploratory interests in various other foreign countries.

Basis of Presentation and Principles of Consolidation

        The consolidated financial statements include the accounts of Forest Oil Corporation and its consolidated subsidiaries (collectively, "Forest" or the "Company"). Significant intercompany balances and transactions are eliminated. The Company consolidates all subsidiaries in which it controls over 50% of the voting interests. Entities in which the Company does not have a direct or indirect majority voting interest are generally accounted for using the equity method. Under the equity method, the initial investment in the affiliated entity is recorded at cost and subsequently increased or reduced to reflect the Company's share of gains or losses or dividends received from the affiliate. The Company's share of the income or losses of the affiliate is included in the Company's reported net income.

        Certain amounts in prior years' financial statements have been reclassified to conform to the 2004 financial statement presentation. Losses related to the extinguishment of debt in 2002, previously presented as extraordinary items, have been reclassified to other (income) expense, net in the accompanying statements of operations as a result of the Company's adoption of Statement of Financial Accounting Standards No. 145 on January 1, 2003.

Assumptions, Judgments, and Estimates

        In the course of preparing the consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the reported amounts of assets, liabilities, revenue, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously established.

        The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil and gas reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs and abandonment obligations used in such calculations. Assumptions, judgments, and estimates are also required in determining impairments of undeveloped properties, valuing deferred tax assets, and estimating fair values of derivative instruments.

Cash Equivalents

        For purposes of the statements of cash flows, the Company considers all debt instruments with original maturities of three months or less to be cash equivalents.

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Property and Equipment

        The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During 2004, 2003, and 2002, the Company's primary oil and gas operations were conducted in the United States and Canada. All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized.

        Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

        Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, including the effects of derivative instruments but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. There were no provisions for impairment of oil and gas properties in 2004, 2003, or 2002, although our Canadian full cost pool, in particular, could be adversely impacted by moderate declines in commodity prices.

        At December 31, 2004, the spot price that Forest used for its Canadian low gravity oil in computing its cost center ceiling was temporarily depressed to a level at which Forest's capitalized costs in its Canadian cost center would have exceeded the cost center ceiling, as described above, by approximately $10 million. Subsequent to December 31, 2004 and before the release of these annual financial statements, the spot price of Canadian low gravity oil increased to levels such that Forest's Canadian cost center ceiling exceeded its capitalized costs. As such, no impairment adjustment to the Canadian cost center was necessary as of December 31, 2004.

        Gain or loss is not recognized on the sale of oil and gas properties unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and gas reserves attributable to a cost center.

        Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. Furniture and fixtures, computer hardware and

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software, and other equipment are depreciated on the straight-line or declining balance method, based upon estimated useful lives of the assets ranging from five to 14 years.

Asset Retirement Obligations

        Effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). 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, with a corresponding increase in the carrying amount of the related long-lived asset. Prior to 2003, the Company recorded estimated costs of future abandonment liabilities, net of estimated salvage values, as part of its provision for depreciation and depletion for oil and gas properties, without recording a separate liability for such amounts. The Company's asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

        Upon adoption of SFAS No. 143 in the first quarter of 2003, the Company recorded an increase to net property and equipment of $165.4 million, an asset retirement obligation liability of $156.0 million, and an after tax credit of $5.9 million for the cumulative effect of the change in accounting principle related to the depreciation, depletion, and accretion amounts that would have been reported had the asset retirement obligations been recorded when incurred. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method.

        The following table summarizes the activities for the Company's asset retirement obligations for the years ended December 31:

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        The following table sets forth the pro forma effect on net earnings and earnings per share for the year ended December 31, 2002 as if SFAS No. 143 had been applied in that year, and for the year ended December 31, 2003 as if no cumulative effect of adopting SFAS No. 143 had been made.

Financial Instruments

        The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents and accounts receivable. The Company's cash equivalents are cash investment funds that are placed with a major financial institution. The Company manages and controls market and credit risk through established formal internal control procedures, which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure to purchasers of the Company's oil and natural gas through formal credit policies, monitoring procedures, and letters of credit.

        The Company used various assumptions and methods in estimating fair value disclosures for financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short maturity of these instruments. The carrying amount of the Company's credit facilities approximated fair value because the interest rates on the credit facilities are variable. The fair values of long-term debt were estimated based on quoted market prices, if available, or quoted market prices of comparable instruments. The fair values of derivative instruments were estimated based on discounted future net cash flows.

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        For additional disclosures regarding the Company's long-term debt and derivative instruments, see Notes 4 and 8, respectively.

Oil and Gas Sales

        The Company recognizes oil sales when title to the product is transferred. The Company accounts for natural gas sales using the entitlements method. Under the entitlements method, revenue is recorded based upon the Company's share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue. As of December 31, 2004 and 2003, the Company had recorded the following net long-term asset in the accompanying consolidated balance sheets related to its gas imbalances:

        In 2004, sales to four purchasers were approximately 15%, 11%, 11%, and 11% of total revenue. In 2003, sales to three purchasers were approximately 15%, 10%, and 10% of total revenue, and in 2002 sales to two purchasers were approximately 16% and 10% of total revenue.

Accounts Receivable

        The components of accounts receivable include the following:

Processing Income, Net

        Processing income, net consists of fees earned, net of expenses, attributable to volumes processed on behalf of third parties through Company-owned gas processing plants.

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Income Taxes

        The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets. Management believes that it could implement tax planning strategies to prevent certain of these carryforwards from expiring.

Foreign Currency Translation

        The functional currency of Canadian Forest Oil Ltd. ("Canadian Forest"), the Company's wholly owned Canadian subsidiary, is the Canadian dollar. Assets and liabilities related to Canadian Forest are generally translated at current exchange rates, and related translation adjustments are generally reported as a component of shareholders' equity in accumulated other comprehensive income (loss). Statement of operations accounts are translated at the average exchange rates during the period.

        During 2004, Forest realized approximately $4.7 million of foreign currency exchange gains in connection with the repayment of intercompany loans. The $4.7 million is included in other (income) expense, net in the Consolidated Statements of Operations.

Earnings per Share

        Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options, and warrants.

        The following sets forth the calculation of basic and diluted earnings per share for the years ended December 31:

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Stock Based Compensation

        The Company applies APB Opinion 25, Accounting for Stock Issued to Employees, and related Interpretations in accounting for its stock-based compensation plans. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common stock. Compensation cost is recognized over the vesting period of options granted at a price less than the fair market value of the common stock at the date of the grant. No compensation cost is recognized for stock purchase rights that qualify under Section 423 of the Internal Revenue Code as a non-compensatory plan. Had compensation cost for the Company's stock-based compensation plans been determined using the fair value of the options at the grant date as prescribed by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the Company's pro forma net earnings and earnings per common share would have been as follows:

Treasury Stock

        The Company accounts for treasury stock acquisitions using the cost method. For reissuance of treasury stock, to the extent that the reissuance price is more than the cost, the excess is recorded as an increase to capital surplus. If the reissuance price is less than the cost, the difference is also recorded to capital surplus to the extent there is a cumulative treasury stock paid in capital balance. Once the cumulative balance is reduced to zero, any remaining difference resulting from the sale of treasury stock below cost is recorded to retained earnings.

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Goodwill

        The Company accounts for goodwill in accordance with SFAS No. 142, "Goodwill and other Intangible Assets," and is required to make an annual impairment assessment in lieu of periodic amortization. The impairment assessment requires the Company to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. Although the Company bases its fair value estimate on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. Downward revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, continued weakening of the U.S. dollar or depressed natural gas, NGLs and crude oil prices could lead to an impairment of goodwill in future periods.

Comprehensive Earnings (Loss)

        Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in the Company's other comprehensive income (loss) for the years ended December 31, 2004, 2003, and 2002 are foreign currency gains (losses) related to the translation of the assets and liabilities of the Company's Canadian operations; changes in the unfunded pension liability; unrealized gains (losses) related to the change in fair value of securities available for sale; and unrealized gains (losses) related to the changes in fair value of derivative instruments designated as cash flow hedges.

        The components of comprehensive earnings (loss) for the years ended December 31, 2004, 2003, and 2002 are as follows:

		Foreign Currency Translation			Unfunded Pension Liability(1)		Unrealized Gain (Loss) on Securities Available for Sale(1)		Unrealized Gain (Loss) on Derivative Instruments, Net(1)		Accumulated Other Comprehensive Income (Loss)
		(In Thousands)
Balance at January 1, 2002		$	(13,197	)	(9,856	)	(387	)	19,293		(4,147	)
2002 activity			2,599		(3,595	)	(94	)	(36,650	)	(37,740	)
Balance at December 31, 2002			(10,598	)	(13,451	)	(481	)	(17,357	)	(41,887	)
2003 activity			49,276		(534	)	481		(17,076	)	32,147
Balance at December 31, 2003			38,678		(13,985	)	—		(34,433	)	(9,740	)
2004 activity			29,224		5,565		—		(18,269	)	16,520
Balance at December 31, 2004		$	67,902		(8,420	)	—		(52,702	)	6,780

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⁽¹⁾

Net of tax.

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Impact of Recently Issued Accounting Pronouncements

        In May 2004, the Financial Accounting Standards Board ("FASB") issued Staff Position ("FSP") No. 109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004" ("FSP 109-2"). FSP 109-2 provides guidance under FASB Statement of Accounting Standard ("SFAS") No. 109, "Accounting for Income Taxes," with respect to recording the potential impact of the repatriation provisions of the American Jobs Creation Act of 2004 (the "Jobs Act") on enterprises' income tax expense and deferred tax liability. The Jobs Act was enacted on October 22, 2004. FSP 109-2 states that an enterprise is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Jobs Act on its plan for reinvestment or repatriation of foreign earnings for purposes of applying SFAS No. 109. The Company is continuing to evaluate the impact of the repatriation provisions. Accordingly, as provided for in FSP 109-2, the Company has not adjusted its tax expense or deferred tax liability to reflect the repatriation provisions of the Jobs Act.

        In December 2004, the FASB issued SFAS No. 123(R), "Share-Based Payment," which is a revision of SFAS No. 123, "Accounting for Stock-Based Compensation". SFAS No. 123(R) is effective for public companies for interim or annual periods beginning after June 15, 2005, supersedes APB Opinion No. 25, "Accounting for Stock Issued to Employee's," and amends SFAS No. 95, "Statement of Cash Flows." SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values, beginning with the first interim or annual period after June 15, 2005, with early adoption encouraged. The pro forma disclosures, previously permitted under SFAS 123, no longer will be an alternative to financial statement recognition. SFAS 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Company's future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future.

        The Company is required to adopt SFAS 123(R) in its third quarter of fiscal 2005, beginning July 1, 2005. Under SFAS 123(R), Forest must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost, and the transition method to be used at date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive options, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock at the beginning of the first quarter of adoption of SFAS 123(R); the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. Forest is evaluating the requirements of SFAS 123(R), and expects that the adoption of SFAS 123(R) will have a material impact on consolidated results of operations and earnings per share. The Company has not yet determined the method of adoption or the effect of adopting SFAS 123(R), and also has not determined whether the adoption will result in amounts that are similar to the current pro forma disclosures under SFAS 123.

        The Company has an Employee Stock Purchase Plan (the "ESPP") that allows eligible employees to annually purchase the Company's common stock at a discount. The provisions of SFAS 123(R) will

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cause the ESPP to be a compensatory plan. However, the change in accounting for the ESPP is not expected to have a material impact on the Company's financial position, future results of operations, or liquidity. Historically, the ESPP compensatory amounts have been nominal. See Note 6 for additional information regarding the ESPP.

        In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions" ("SFAS 153"). SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in paragraph 21(b) of APB Opinion No. 29, "Accounting for Nonmonetary Transactions," and replaces it with an exception for exchanges that do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for the fiscal periods beginning after June 15, 2005. The Company is currently evaluating the effect that the adoption of SFAS 153 will have on consolidated results of operations and financial condition but does not expect it to have a material impact.

        In September 2004, the Securities and Exchange Commission issued Staff Accounting Bulletin ("SAB") No. 106 regarding the application of SFAS No. 143, "Accounting for Asset Retirement Obligations," by oil and gas producing entities that follow the full cost accounting method. SAB No. 106, effective in the fourth quarter of 2004, states that after adoption of SFAS No. 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the present value of estimated future net cash flows used for the full cost ceiling test calculation. Forest has accounted for its asset retirement obligations in this manner since the adoption of SFAS No. 143 and, therefore, SAB No. 106 will have no effect on the Company's financial statements or its ceiling test computation.

(2)    ACQUISITIONS AND DIVESTITURES:

Acquisitions

Recent Acquisition

        On February 28, 2005, Forest announced that it had agreed to purchase all of the stock of a private company whose primary asset is an operated average working interest of 83% (unaudited) in the Buffalo Wallow Field in Texas and approximately 33,000 (unaudited) 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 is expected to occur on March 31, 2005. The Buffalo Wallow Field has estimated proved reserves of 120 Bcfe (unaudited).

Acquisition of The Wiser Oil Company

        In June 2004, the Company completed its acquisition of the common stock of The Wiser Oil Company ("Wiser"), which held oil and gas assets located in the Company's Gulf Coast, Western U.S., and Canada business units (the "Wiser Acquisition"). The Wiser Acquisition provided potential for increased production, reserves, and undeveloped acreage as well as diversification in terms of both current production and long-term growth opportunities. At the time the acquisition was closed, the net

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oil and gas reserves were estimated to be approximately 186 Bcfe (unaudited), of which 85% (unaudited) were classified as proved developed and the remaining amounts were classified as proved undeveloped. Average production from the Wiser properties at the time of acquisition was 64 MMcfe (unaudited) per day. The acquisition also included working capital and certain other financial assets and liabilities of Wiser. The purchase price was allocated to assets and liabilities, adjusted for tax effects, based on the fair values at the date of acquisition. The acquisition was accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Forest since the date of acquisition.

        The total cash purchase price, including transaction costs, of $171 million was allocated to the assets acquired and the liabilities assumed based on the estimated fair values set forth in the table below. The purchase price allocation is preliminary and will be finalized after management's final review of the relative fair values of the net assets acquired.

        Goodwill of $68.6 million ($67.3 million before effects of foreign currency exchange) has been recognized to the extent that cost exceeded the fair value of net assets acquired. See Note 12 for the allocation of goodwill between operating segments. Goodwill is not expected to be deductible for tax purposes. The principal factor that contributed to the recognition of goodwill was opportunities for cost savings through administrative and operational synergies.

        The following unaudited pro forma consolidated statements of operations information assumes that the Wiser Acquisition occurred as of January 1 of each year. These pro forma results of operations are

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not necessarily indicative of the results of operations that would have actually been attained had the transaction occurred as of these dates.

Acquisitions of Unocal Assets and Private Company

        During the fourth quarter of 2003, Forest completed an acquisition of certain oil and gas properties onshore South Louisiana and offshore Gulf of Mexico from Union Oil Company of California ("Unocal"). The estimated proved reserves acquired at closing were approximately 141 Bcfe (unaudited). The majority of the properties were purchased in a transaction that closed on October 31, 2003. The remainder of the properties were purchased in two additional transactions that closed on November 12, 2003 and December 15, 2003. The acquisition was funded in part by the proceeds from a common stock offering and by borrowings under Forest's U.S. credit facility. The revenue and expenses of these properties have been included in Forest's consolidated financial statements since the closing dates.

        On December 31, 2003, Forest purchased 100% of the stock of a private company with oil and gas assets located primarily in the Permian Basin and in fields located in South Texas. Estimated proved reserves acquired at closing were approximately 109 Bcfe (unaudited). The acquisition included working capital, oil and gas assets, and certain other financial assets and liabilities of the seller. The consolidated balance sheet of Forest as of December 31, 2003 includes the assets acquired and liabilities assumed in this transaction. The closing date of this transaction was December 31, 2003; therefore, no revenue or expenses for these properties were recorded until January 1, 2004.

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        The purchase price of the two acquisitions discussed above was allocated as follows:

        The following unaudited pro forma consolidated statements of operations information assumes that the two acquisitions discussed above occurred as of January 1 of each year. These pro forma results of operations are not necessarily indicative of the results of operations that would have actually been attained had the transactions occurred as of these dates.

Other Acquisitions

        Throughout 2004 and 2003, Forest made several other acquisitions of oil and gas properties for cash consideration totaling $86.4 million and $61.6 million, respectively. Total estimated proved reserves acquired in these other acquisitions totaled approximately 63 Bcfe (unaudited) and 72 Bcfe (unaudited) in 2004 and 2003, respectively.

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Divestitures

Sale of ProMark

        On March 1, 2004, the Company sold the assets and business operations of Producers Marketing, Ltd. ("ProMark") to Cinergy Canada, Inc. ("Cinergy") for $11.2 million CDN. Under the terms of the purchase and sale agreement, Cinergy will market natural gas (not already subject to prior contractual commitment) on behalf of Canadian Forest for five years. Cinergy will also administer the netback pool formerly administered by ProMark. Forest could receive additional contingent payments over the next five years if Cinergy meets certain earnings goals with respect to the acquired business.

        As a result of the sale, ProMark's results of operations have been reported as discontinued operations in the accompanying financial statements. The components of assets held for sale related to discontinued operations included in Other Assets in the Consolidated Balance Sheet at December 31, 2003 are as follows:

        The components of (loss) income from discontinued operations for the years ended December 31, 2004, 2003, and 2002 are as follows:

Other Divestitures

        During 2004, Forest sold oil and gas properties with estimated proved reserves of approximately 85 Bcfe (unaudited) for total proceeds of approximately $97.9 million. During 2003, Forest disposed of properties with estimated proved reserves of approximately 21 Bcfe (unaudited) for total proceeds of approximately $14.4 million.

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(3)    PROPERTY AND EQUIPMENT:

        Net property and equipment at December 31 consists of the following:

        The following table sets forth a summary of oil and gas property costs not being depleted at December 31, 2004, by the year in which such costs were incurred, and related impairment charges:

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        Forest holds interests in various projects located outside North America. Costs related to these international interests of $56.0 million are not being depleted pending determination of the existence of estimated proved reserves. Forest's exploration project in South Africa accounts for the majority of the $56.0 million of international costs not being amortized. During 2004, Forest initiated a gas marketing program in South Africa seeking to negotiate with potential gas purchases of possible future South Africa natural gas production. Forest expects that substantially all unevaluated costs for this project will be classfied as evaluated within the next five years. In 2004, Forest recorded an impairment of $4.0 million ($2.4 million net of taxes) related to certain concessions in Albania, Germany, and Italy. In 2003, Forest recorded an impairment of $16.9 million ($10.5 million net of taxes) related primarily to concessions in Albania, Italy, Romania, Switzerland, and Tunisia. No impairments were recorded in 2002. The Company anticipates that the majority of all the unproved costs in the table above will be classified as proved costs within the next five years.

(4)    LONG-TERM DEBT:

        Components of long-term debt are as follows:

		December 31, 2004									December 31, 2003
		Principal			Unamortized Premium (Discount)		Other(4)		Total		Principal		Unamortized Discount		Other(4)		Total
		(In Thousands)
U.S. Credit Facility(1)		$	152,000		—		—		152,000		291,000		—		—		291,000
Canadian Credit Facility(1)			—		—		—		—		1,542		—		—		1,542
Bank debt assumed in acquisition(2)			—		—		—		—		30,000		—		—		30,000
8% Senior Notes Due 2008			265,000		(341	)	7,952		272,611		265,000		(439	)	10,258		274,819
8% Senior Notes Due 2011(3)			285,000		9,042		5,829		299,871		160,000		—		6,671		166,671
73/4% Senior Notes Due 2014			150,000		(2,228	)	16,565		164,337		150,000		(2,467	)	18,406		165,939
		$	852,000		6,473		30,346		888,819		897,542		(2,906	)	35,335		929,971

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In September 2004, Forest entered into amended and restated credit facilities totaling $600 million, consisting of a $550 million United States credit facility and a $50 million Canadian credit facility. The credit facilities mature in September 2009. Subject to the agreement of Forest and the applicable lenders, the size of the credit facilities may be increased by $200 million in the aggregate.

⁽²⁾

Repaid in January 2004 with borrowings under Forest's U.S. credit facility.

⁽³⁾

In July 2004, Forest issued an additional $125 million in principal amount of 8% Senior Notes due 2011, at 107.75% of par, for proceeds of $133.3 million (net of related offering costs). Net proceeds from this offering were used to reduce the balance outstanding under Forest's U.S. credit facility.

⁽⁴⁾

Represents the unamortized portion of gains realized upon termination of interest rate swaps that were accounted for as fair value hedges. The gains are being amortized as a reduction of interest expense over the terms of the note issues.

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Bank Credit Facilities

        On September 28, 2004, Forest entered into credit facilities totaling $600 million, consisting of a $550 million United States credit facility through a syndicate of banks led by JPMorgan Chase and a $50 million Canadian credit facility through a syndicate of banks led by JPMorgan Chase Bank, Toronto Branch. The credit facilities mature in September 2009. Subject to the agreement of Forest and the applicable lenders, the size of the credit facilities may be increased by $200 million in the aggregate. Availability under the credit facilities is based either on certain financial covenants included in the credit facilities or on the loan value assigned to Forest's oil and gas properties. Availability under the credit facilities currently is governed by the global borrowing base. The global borrowing base is currently set at $500 million, with $480 million allocated to the United States credit facility and $20 million allocated to the Canadian credit facility. The determination of the global borrowing base is made by the lenders taking into consideration the estimated value of Forest's oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. While the global borrowing base is in effect, it is redetermined semi-annually, and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, Forest and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the global borrowing base redetermined. At December 31, 2004, the unused borrowing amount under the global borrowing base was approximately $341 million. At December 31, 2004, there were outstanding borrowings of $152.0 million under the U.S. credit facility at an average interest rate of 3.66%, and there were no borrowings under the Canadian credit facility. Forest also had used the U.S. and Canadian credit facilities for letters of credit in the amount of $6.5 million at December 31, 2004.

        The credit facilities are collateralized by a portion of Forest's assets. Forest is required to mortgage, and grant a security interest in, 75% of the present value of its proved oil and gas properties. Forest has also pledged the stock of several subsidiaries to the lenders to secure the credit facilities. Under certain circumstances, Forest could be obligated to pledge additional assets as collateral. If Forest's corporate credit ratings by Moody's and S&P improve and meet pre-established levels, the collateral requirements would not apply and, at Forest's request, the banks would release their liens and security interests on Forest's properties. The credit facilities include terms and covenants that place limitations on certain types of activities, the payment of dividends, and certain financial tests. In particular, any time that availability is not governed by the global borrowing base, the amount available and Forest's ability to borrow under the credit facilities is determined by certain financial covenants.

8% Senior Notes Due 2008

        In June 2001, Forest issued $200 million in principal amount of 8% Senior Notes due 2008 (the "8% Notes Due 2008") at par for proceeds of $199.5 million (net of related offering costs). In October 2001, Forest issued an additional $65 million in principal amount of 8% Notes Due 2008 at 99% of par for proceeds of $63.6 million (net of related offering costs).

8% Senior Notes Due 2011

        In December 2001, Forest issued $160 million in principal amount of 8% Senior Notes due 2011 (the "8% Notes Due 2011") at par for proceeds of $157.5 million (net of related offering costs). In

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July 2004, Forest issued an additional $125 million in principal amount of 8% Senior Notes due 2011 at 107.75% of par for proceeds of $133.3 million (net of related offering costs).

7³/4% Senior Notes Due 2014

        In 2002, Forest issued $150 million in principal amount of 7³/4% Senior Notes due 2014 (the "7³/4% Notes") at 98.09% of par for proceeds of $146.8 million (net of related offering costs).

(5)    INCOME TAXES:

        The income tax expense was different from amounts computed by applying the U.S. statutory federal income tax rate for the following reasons:

        Deferred income taxes generally result from recognizing income and expenses at different times for financial and tax reporting. In the United States, the largest differences are the tax effect of the capitalization of certain development, exploration, and other costs under the full cost method of accounting, recording proceeds from the sale of properties in the full cost pool, and the provision for impairment of oil and gas properties for financial accounting purposes. In Canada, differences result in part from accelerated cost recovery of oil and gas capital expenditures for tax purposes.

        The Company's deferred income tax expense excludes amounts related to the tax benefit of stock options exercised in 2004, 2003, and 2002 for which the related tax benefit was credited directly to shareholders' equity.

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        The components of the net deferred tax liability by geographical segment at December 31, 2004 and 2003 are as follows:

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        The net deferred tax assets are reflected in the accompanying balance sheets as follows:

        In assessing whether deferred tax assets are realizable, management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in

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making this assessment. The net changes in the valuation allowance for the years ended December 31, 2004, 2003, and 2002 were as follows:

        The $4.0 million decrease in valuation allowance for deferred tax assets in 2004 is comprised of a decrease of $5.3 million associated with Forcenergy tax losses expected to be utilized in 2004, which is reflected as an increase to Capital Surplus, and an increase of $1.3 million associated with Canadian losses.

        The Alternative Minimum Tax ("AMT") credit carryforward available to reduce future U.S. federal regular taxes aggregated $3.5 million at December 31, 2004. This amount may be carried forward indefinitely. U.S. federal regular and AMT net operating loss carryforwards at December 31, 2004 were approximately $466.1 million and $389.2 million, respectively. Of these amounts, approximately $235.8 million and $200.3 million were acquired by the Company in a merger that occurred in 2000 (the "Forcenergy Merger"); approximately $13.2 million and $11.5 million were acquired by the Company in its acquisition of Wiser. The Company's regular and AMT net operating losses are scheduled to expire in the years indicated below:

        AMT net operating loss carryforwards can be used to offset 90% of AMT income in future years.

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        Canadian tax pools relating to the exploration, development, and production of oil and natural gas that are available to reduce future Canadian federal income taxes aggregated approximately $211.6 million ($253.7 million CDN) at December 31, 2004. These tax pool balances are deductible on a declining balance basis ranging from 4% to 100% of the balance annually, and are composed of costs incurred for oil and gas properties, and developmental and exploration expenditures, as follows:

        Other Canadian tax pools and loss carryforwards available to reduce future Canadian federal income taxes were approximately $29.2 million ($35.0 million CDN) at December 31, 2004, of which $26.6 million may be carried forward indefinitely. The Canadian tax pools include approximately $68.5 million ($82.3 million CDN) acquired from predecessor companies that are limited in use to income derived from assets acquired.

        The Company's ability to use some of its net operating loss carryforwards and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code. In particular, the Company's ability to utilize such carryforwards is limited due to the occurrence of "Ownership Changes" within the meaning of Section 382 of the Internal Revenue Code. Ownership Changes occurred in the Company in 1995 following the issuance of securities to The Anschutz Corporation ("Anschutz"), in 1996 following a public stock issuance, and in connection with the 2000 Forcenergy Merger.

        Ownership Changes occurred in Forcenergy in 1995 as a result of an initial public offering and merger with another entity, and in 2000 following its emergence from bankruptcy. These Ownership Changes will affect the use of tax attributes acquired in the Forcenergy Merger. Portions of Forcenergy's net operating loss carryforwards and other tax attributes are further limited due to Ownership Changes that occurred with respect to businesses acquired by Forcenergy in 1997. An Ownership Change also occurred in connection with Forest's acquisition of Wiser. Forest does not expect this Ownership Change to materially affect its ability to use Wiser's tax attributes in the future.

        Approximately $80 million of Forest's net operating loss carryforwards are subject to an annual limitation of approximately $5.8 million. In addition, Forest's ability to utilize substantially all of Forcenergy's built-in losses and net operating loss carryforwards will be subject to an overall annual limitation of approximately $22 million. Additional limitations affect Forest's ability to utilize certain portions of Forcenergy's built-in losses and net operating loss carryforwards generated prior to 1997. Because of these limitations, approximately $81 million of these losses will not be realized before they expire. The Company believes it is more likely than not that additional carryforwards will expire before they can be realized and has provided a valuation allowance for its estimate of the total amounts that will not ultimately be realized due to limitations imposed by Section 382.

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(6)    SHAREHOLDERS' EQUITY:

Common Stock

        At December 31, 2004 the Company had 200 million shares of common stock ("Common Stock"), par value $.10 per share, authorized.

        In June 2004, Forest issued 5.0 million shares of common stock at a price of $24.40 per share. Net proceeds from this offering were approximately $117.1 million after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds from the offering were used to fund a portion of the Wiser Acquisition.

        In October 2003, Forest issued 5.1 million shares of common stock at a price of $23.10 per share. Net proceeds from this offering were approximately $112.6 million after deducting underwriting discounts and commissions and estimated offering expenses.

        Forest issued 7.9 million shares of common stock at a price of $24.50 per share in January 2003. Net proceeds from this offering (before any exercise of the underwriters' over-allotment option) were approximately $184.4 million after deducting underwriting discounts and commissions and the estimated expenses of the offering. An additional .9 million shares of common stock were issued in February 2003 pursuant to exercise of the underwriters' over-allotment option for net proceeds of $21.2 million.

Rights Agreement

        In October 1993, the Board of Directors adopted a shareholders' rights plan and entered into the Rights Agreement. The Company distributed one Preferred Share Purchase Right (the "Rights") for each outstanding share of the Company's Common Stock. The Rights are exercisable only if a person or group acquires 20% or more of the Company's Common Stock or announces a tender offer that would result in ownership by a person or group of 20% or more of the Common Stock.

        In October 2003, the Board of Directors of Forest entered into the First Amended and Restated Rights Agreement (the "First Amended Rights Agreement"). The rights issued under the First Amended Rights Agreement will expire on October 29, 2013, unless earlier exchanged or redeemed, and entitle the holder thereof to purchase 1/100th of a preferred share at an initial purchase price of $120.

Warrants

        At December 31, 2004, Forest had outstanding 180,831 warrants expiring on February 15, 2005 (the "2005 Warrants"). Each 2005 Warrant entitled the holder to purchase 0.8 shares of Common Stock for $20.83, or an equivalent per share price of $26.04. In 2005, 158,033 warrants were exercised for cash or in cashless exercises, and Forest issued 102,137 shares of Common Stock. All remaining 2005 Warrants expired unexercised on February 15, 2005.

        At February 28, 2005, Forest had outstanding 1,752,355 subscription warrants ("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.

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        During the years ending December 31, 2004, 2003, and 2002, warrants totaling 267,508; 1,972; and 22,481 were exercised in cash and cashless exercises to purchase 162,901; 1,573; and 17,971 shares of Common Stock, respectively, at prices ranging from $10.00 to $20.83.

Restricted Stock

        During the year ended December 31, 2004, the Company granted 95,600 shares of Common Stock valued at $2.8 million as compensation to employees that vest three years after the grant date. The value of these shares was recorded as deferred compensation in shareholders' equity. The Company amortized deferred compensation of $.2 million during the year ended December 31, 2004 related to these restricted stock amounts.

Stock Options

        In 2001, the Company adopted the Forest Oil Corporation 2001 Stock Incentive Plan (the "2001 Plan") under which stock options, restricted stock, and other awards may be granted to employees, consultants and non-employee directors. In 2003, the Company amended the 2001 Plan to increase the number of shares reserved for issuance. The aggregate number of shares of Common Stock that the Company may issue under the 2001 Plan may not exceed 3.8 million shares. The exercise price of an option shall not be less than the fair market value of one share of Common Stock on the date of grant. Options under the 2001 Plan generally vest in increments of 25% on each of the first four anniversary dates of the date of grant and have a term of ten years. As of December 31, 2004, the Company had 829,337 shares available to be issued under the 2001 Plan.

        The Company had a Stock Incentive Plan (the "1996 Plan") that expired on March 5, 2002 under which non-qualified stock options and restricted stock were granted to employees, and director stock awards were granted to non-employee directors. Under the 1996 Plan, the exercise price of an option could not be less than 85% of the fair market value of one share of Common Stock on the date of grant. Options granted under the 1996 Plan generally vested in increments of 20% on the date of grant and thereafter on each of the first four anniversary dates of the date of the grant.

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        The following table summarizes the activity in the Company's stock-based compensation plans for the years ended December 31, 2004, 2003, and 2002:

        The fair value of each option granted in 2004, 2003, and 2002 was estimated using the Black-Scholes option pricing model. The following assumptions were used to compute the weighted average fair market value of options granted during the periods presented:

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        The following table summarizes information about options outstanding at December 31, 2004:

Employee Stock Purchase Plan

        Under the 1999 Employee Stock Purchase Plan (the "ESPP"), the Company is authorized to issue up to 125,000 shares of Common Stock. Employees who are regularly scheduled to work more than 20 hours per week and more than five months in any calendar year may participate in the ESPP. Under the terms of the plan, employees can choose each quarter to have up to 15% of their annual base earnings withheld to purchase Common Stock, up to a limit of $25,000 of Common Stock per calendar year. The purchase price of the Common Stock is 85% of the lower of its beginning-of-quarter or end-of-quarter market price. The employee is restricted from selling the shares of Common Stock purchased under the ESPP for a period of six months after purchase. Under the ESPP, the Company sold 22,207 shares, 21,403 shares, and 20,160 shares of Common Stock to employees in 2004, 2003, and 2002, respectively. The fair value of each stock purchase right granted during 2004, 2003, and 2002 was estimated using the Black-Scholes option pricing model. As of December 31, 2004, the Company had 32,853 shares available to be issued under the ESPP. The following assumptions were used to compute the weighted average fair market value of purchase rights granted during the periods presented:

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(7)    EMPLOYEE BENEFITS:

United States Pension Plans and Postretirement Benefits

        The Company has a qualified defined benefit pension plan that covers certain employees and former employees in the United States (the "Forest Pension Plan"). The Company also has a non-qualified unfunded supplementary retirement plan (the "Supplemental Executive Retirement Plan" or "SERP") that provides certain retired executives with defined retirement benefits in excess of qualified plan limits imposed by federal tax law. The Forest Pension Plan was curtailed and all benefit accruals under both plans were suspended effective May 31, 1991. Amounts for both the Forest Pension Plan and the SERP are combined in the "Pension Benefits" column below.

        In addition, as a result of the Wiser Acquisition, Forest assumed a noncontributory defined benefit pension plan (the "Wiser Pension Plan"). The Wiser Pension Plan was curtailed and all benefit accruals were suspended effective December 11, 1998. In October 2000, the Wiser Pension Plan was amended to provide additional benefits by implementing a cash balance plan for the then current employees of Wiser. In December 2004, all benefit accruals under the Wiser Pension Plan were suspended.

        The weighted average asset allocations of the Forest Pension Plan and Wiser Pension Plan at December 31, 2004 and 2003 were:

        Hereinafter, the Forest Pension Plan, the Wiser Pension Plan, and the SERP will be collectively referred to as the "Plans." Forest anticipates that it will make contributions in 2005 totaling $1.1 million to the Plans.

        The overall investment goal for pension plan assets is to achieve an investment return that allows plan assets to achieve the actuarial interest rate and to exceed the rate of inflation. In order to manage risk, in terms of volatility, the portfolios are designed to avoid a loss of 20% during any single year and to express no more volatility than experienced by the S&P 500 Stock Index.

        The Plans' assets are invested with a view toward the long term in order to fulfill the obligations promised to participants as well as to control future levels of funding. The long-term goal for equity securities exposure is 50% of plan assets at market value. The maximum allowable equity exposure is 60%. There is no specified minimum equity exposure for any point in time. The long-term goal for fixed income exposure is 50% of the plan assets at market value. The maximum allowable fixed income exposure is 70%. There is no specified minimum fixed income exposure for any point in time. This asset allocation is designed to achieve an appropriate balance between capital appreciation, preservation of capital, and current income.

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        The discount rate used to determine benefit obligations was reduced from 6.00% at December 31, 2003 to 5.75% at December 31, 2004. The discount rate reflects the market rate of return on investment grade fixed income securities.

        Forest developed its expected rate of return on plan assets by evaluating input from external consultants and long-term inflation assumptions. The expected long-term rate of return is based on the target allocation of plan assets.

        In addition to the defined benefit pension plans described above, Forest also accrues expected costs of providing postretirement benefits to employees in the United States, their beneficiaries, and covered dependents in accordance with Statement of Financial Accounting Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions ("SFAS No. 106"). These amounts, which consist primarily of medical benefits payable on behalf of retirees in the United States, are presented in the "Postretirement Benefits" column below. Contributions to be made in 2005 for post retirement benefits other than pensions are expected to be approximately $.5 million, net of retiree contributions.

        In the future, it is anticipated that the Company will be required to provide benefit payments from the Forest Pension Plan, the SERP, the Wiser Pension Plan, and the postretirement plan of the following amounts for each year 2005 through 2009 and in the aggregate for the years 2010 through 2014:

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⁽¹⁾

Benefit payments expected to be made to participants in the Forest Pension Plan and Wiser Pension Plan are expected to be paid out of funds held in trusts established for each plan.

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        The following tables set forth the estimated benefit obligations, the fair value of the plans' assets, and the funded status of the Plans and the postretirement plan at December 31, 2004 and 2003:

Benefit Obligations

Fair Value of Plan Assets

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Funded Status

        The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions for the years ended December 31, 2004, 2003, and 2002:

			Pension Benefits							Postretirement Benefits(1)
			2004			2003		2002		2004		2003		2002
			(In Thousands)							(In Thousands)
Service cost			$	81		—		—		631		530		576
Interest cost				2,056		1,814		1,728		553		523		467
Expected return on plan assets				(1,843	)	(1,362	)	(1,452	)	—		—		—
Recognized actuarial loss				692		728		268		46		—		—
Settlement loss				20		—		—		—		—		—
Total net periodic expense			$	1,006		1,180		544		1,230		1,053		1,043
Assumptions used to determine net periodic expense:
	Discount rate			6.00	%	6.50	%	7.00	%	6.00	%	6.50	%	7.00	%
	Expected return on plan assets			*		7.00	%	7.00	%	n/a		n/a		n/a
Assumptions used to determine benefit obligations:
	Discount rate			5.75	%	6.00	%	6.50	%	5.75	%	6.00	%	6.50	%

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*

Expected return on plan assets of the FOC Pension Plan and the Wiser Pension Plan was 7.00% and 8.00%, respectively.

⁽¹⁾

The net periodic postretirement benefit costs do not reflect any amount associated with the federal subsidy provided by the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the "Act") because the Company is presently unable to conclude whether the benefits provided by the plan are actuarially equivalent to Medicare Part D under the Act.

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        Assumed health care cost trend rates have a significant effect on the amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects for 2004:

        For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits was held constant at 5.5% during 2004 and thereafter.

        In December 2003, a new Medicare bill was enacted that provides prescription drug coverage to Medicare-eligible retirees. In its present form, the Company's U.S. medical plan provides prescription drug benefits to certain Medicare-eligible retirees. The results contained in these financial statements do not anticipate any changes to the U.S. retiree medical plan in light of the Medicare legislation. The Company is continuing to study the impact of the new legislation and the resulting impact, if any, on its financial statements. Specific authoritative guidance on the accounting for the federal subsidy is pending, and that guidance, when issued, may require changes to previously reported information.

Canadian Pension Plan and Postretirement Benefits

        All employees of Canadian Forest participate in a defined contribution pension plan (the "Defined Contribution Pension Plan"). The expense associated with the Company's contributions to the Defined Contribution Pension Plan were $.3 million CDN in 2004 and $.4 million CDN in 2003.

        Prior to 2003, contributions to the Defined Contribution Benefit Plan were taken from the surplus in a non-contributory defined benefit pension plan (the "Defined Benefit Pension Plan") sponsored by Canadian Forest. Under a plan to wind up the Defined Benefit Pension Plan, participating employees were provided an option to transfer an actuarially computed value to their defined contribution pension plan or to have an annuity purchased on their behalf from an insurance company. At December 31, 2003, all annuities had been purchased or computed values transferred out, resulting in the recognition of a net loss of $.8 million CDN in 2003 and Canadian Forest had no further obligations under the Defined Benefit Pension Plan. Consents from the provincial and federal governments to formally wind up the plan were received in May 2004.

        Canadian Forest also accrues expected costs of providing postretirement benefits to certain of its employees, their beneficiaries, and covered dependents in accordance with SFAS No. 106. These amounts, which consist primarily of medical and dental benefits payable on behalf of retirees in Canada, are presented in the "Postretirement Benefits" column below. The postretirement benefit is closed to new participants. In the future, it is anticipated that the Company will make contributions equal to the benefits to be paid out. The benefits expected to be paid in each year from 2005 - 2009 are $36,414 CDN, $38,365 CDN, $40,273 CDN, $42,117 CDN, and $43,878 CDN, respectively. The aggregate benefits expected to be paid in the five years from 2010 - 2014 are $248,532 CDN.

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        The following tables set forth the estimated benefit obligations, fair value of the plans' assets, funded status of the Defined Benefit Pension Plan and the Canadian postretirement plan at December 31, 2004 and 2003:

Benefit Obligations

Fair Value of Plan Assets

Funded Status

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        The following table sets forth the components of net periodic pension cost of the Defined Benefit Pension Plan and the Postretirement Benefits and the underlying weighted average actuarial assumptions for the years ended December 31, 2004, 2003, and 2002.

        For measurement purposes, the annual rate of increase in the per capita cost of covered health care benefits for Canadian Forest was assumed to be 4% per year for the dental plan; 5% per year for Provincial health care; and 7.00% in 2005, 6.25% in 2006, 5.50% in 2007, 4.75% in 2008, and 4% thereafter for the medical plan.

Employee Savings Plans

        Forest sponsors a qualified tax-deferred savings plan ("Retirement Savings Plan") for its employees in the United States in accordance with the provisions of Section 401(k) of the Internal Revenue Code. Employees may defer up to 80% of their compensation, subject to certain limitations. In 2002, the Company matched employee contributions up to 5% of eligible employee compensation. Effective January 1, 2003, the Company matching percentage increased to 6% of eligible employee compensation and the matching percentage increased to 7% of eligible employee compensation effective January 1, 2004. Expenses associated with the Company's contributions to the Retirement Savings Plan totaled $1.9 million in 2004, $1.4 million in 2003, and $1.2 million in 2002. In each of these years, the Company matched employee contributions in cash.

        Canadian Forest provides a savings plan ("Canadian Savings Plan") that is available to all of its employees. Employees may contribute up to 4% of their salary, subject to certain limitations, with Canadian Forest matching the employee contribution in full. The expense associated with Canadian Forest's contributions to the plan was approximately $.2 million in each of 2004, 2003, and 2002.

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        Due to the achievement of various corporate performance objectives in 2004, the Company accrued approximately $2.0 million for an employer discretionary contribution to the Retirement Savings Plan as well as an additional $.2 million to be rewarded to the Company's Canadian employees under the Canadian Savings Plan. These discretionary contributions were paid in March 2005.

Deferred Compensation Plans

        Forest has an Executive Deferred Compensation Plan (the "Executive Plan") pursuant to which certain officers may participate and defer a portion of their compensation after contributing the maximum allowable amount to the Retirement Savings Plan. The Executive Plan is not funded, but the Company records a liability for matching contributions and accrues interest on each participant's account balance at the rate of 1% per month. The expense associated with the Company's matching contributions to the Executive Plan and interest was $.4 million in 2004, and $.2 million in each of 2003 and 2002. The liability associated with the Executive Plan was approximately $1.6 million and $1.1 million at December 31, 2004 and 2003, respectively.

        Forest has also adopted two salary deferred compensation plans and a change of control deferred compensation plan. Eligibility to participate in the salary deferred compensation plans is limited to officers and directors of the Company, and officers may participate in the change of control deferred compensation plan. Under the terms of the salary deferral compensation plans, a participant may defer a percentage of his or her base salary, bonuses, and, under one of the salary deferred compensation plans, possibly certain equity awards. The change of control plan, which has not been implemented, allows participants to make one-time deferrals of compensation that they would otherwise receive upon a change in control of the Company. As of December 31, 2004 and 2003, the fair value of amounts deferred under the salary deferred compensation plans was approximately $.8 million and $1.1 million, respectively.

Split Dollar Life Insurance

        The Company provides life insurance benefits for certain retirees and former executives under split dollar life insurance plans. Under the life insurance plans, the Company is assigned a portion of the benefits, which is designed to recover the premiums paid. No current executives are covered by the plan.

(8)    DERIVATIVE INSTRUMENTS:

        The Company recognizes the fair value of its derivative instruments as assets or liabilities on the balance sheet. The accounting treatment for the changes in fair value is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative qualifies as an effective hedge. Changes in fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. For fair value hedges, to the extent the hedge is effective, there is no effect on the statement of operations because changes in fair value of the derivative offset changes in the fair value of the hedged item. For derivative instruments that do not qualify as fair value hedges or cash flow hedges, changes in fair value are recognized in earnings as other income or expense.

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Commodity Swaps, Collars, and Basis Swaps

        Forest periodically hedges a portion of its oil and gas production through swap, basis swap, and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company's cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk.

        Substantially all of Forest's commodity swap and collar agreements and a portion of its basis swaps in place at December 31, 2004 have been designated as cash flow hedges. In addition, Forest has basis swaps that are not designated as cash flow hedges. Forest also had certain collar agreements that could not be designated as cash flow hedges under generally accepted accounting principles, because these collars had unrealized losses at the date they were obtained by Forest in the Wiser Acquisition. At December 31, 2004, the Company had a derivative asset of $11.2 million (of which $8.9 million was classified as current) and a derivative liability of $101.4 million (of which $80.5 million was classified as current).

        The Company's losses under these agreements recognized in the Company's statements of operations were:

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⁽¹⁾

Included in oil and gas sales in the Consolidated Statements of Operations.

⁽²⁾

Included in other (income) expense, net in the Consolidated Statements of Operations.

        Net losses of $118.2 million, $72.4 million and $2.5 million recognized during 2004, 2003 and 2002, respectively, are included in net cash flows from operating activities in the Consolidated Statements of Cash Flows for each respective year. Net (gains) losses of $(.3) million, $.1 million and $1.3 million recognized during 2004, 2003 and 2002, respectively, are included in net cash flows from financing activities in the Consolidated Statements of Cash Flows for each respective year.

        Based on the estimated fair values of the derivative contracts at December 31, 2004, the Company expects to reclassify net losses of $71.6 million into earnings related to the derivative contracts during the next 12 months; however, actual gains or losses recognized may differ materially.

        The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2004, beginning with the fair value of the commodity contracts on December 31, 2004, less the decrease in fair value during the period, less the fair value of commodity

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contracts acquired in connection with the acquisition of oil and gas companies, and plus the contract losses settled, or recognized, during the period.

        In a typical swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon published, third party index when the index price is lower than the fixed price. When the index price is higher, Forest pays the difference. By entering into swap agreements the Company effectively fixes the price that it will realize in the future for the hedged production. Forest's current swaps are settled in cash on a monthly basis. As of December 31, 2004, Forest had entered into the following swaps accounted for as cash flow hedges:

        Forest also enters into collar agreements with third parties. A collar agreement is similar to a swap agreement, except that the Company receives the difference between the floor price and the index price only when the index price is below the floor price; and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. Collars are also settled in cash, either on a monthly basis or at the end of their terms. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged

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production. As of December 31, 2004, the Company had entered into the following gas and oil collars accounted for as cash flow hedges:

        In addition, Forest has entered into three-way collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price.

        As of December 31, 2004, Forest had entered into the following 3-way oil collars accounted for as cash flow hedges:

        The Company also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX price and the index price at which the hedged gas is sold. At December 31, 2004, there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 40.0 Bbtu per day for 2005.

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        Forest also obtained the following collar agreements in the Wiser Acquisition. These collar agreements could not be designated as cash flow hedges by Forest under generally accepted accounting principles, because the collars had unrealized losses at the date of the Wiser Acquisition.

        The Company is exposed to risks associated with swap and collar agreements arising from movements in the prices of oil and natural gas and from the unlikely event of non-performance by the counterparties to the swap and collar agreements.

        Subsequent to December 31, 2004, we entered into the following derivative instruments primarily to hedge the economics of a recent acquisition.

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*

Represents weighted average floor and ceiling.

Interest Rate Swaps

        Throughout 2001, 2002, and 2003, the Company entered into various interest rate swaps designated as fair value hedges intended to exchange (i) the fixed interest rate specified portions of its long term debt for (ii) a variable rate based on LIBOR plus specified basis points over the term of the notes. During 2002 and 2003, the interest rate swaps were terminated for net proceeds of $35.6 million and $5.1 million, respectively. These gains were deferred and added to the carrying value of the related debt, and are being amortized as reductions of interest expense over the remaining terms of the notes. During the years ended December 31, 2004, 2003, and 2002, the Company recognized a portion of the gains by reducing interest expense by $5.0 million, $5.5 million, and $9.8 million, respectively.

(9)    RELATED PARTY TRANSACTIONS:

        Beginning in 1995, the Company consummated certain transactions with Anschutz pursuant to which Anschutz acquired a significant ownership position in the Company. In January 2003, the Company issued 7.9 million shares of stock to the public at a gross price of $24.50 per share and used the net proceeds from the offering to repurchase 7.9 million shares of common stock from Anschutz and certain of its affiliates at a price of $23.52 per share. As of December 31, 2004, Anschutz owned

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approximately 13.1% of Forest's outstanding Common Shares, including warrants to purchase 522,036 shares of Common Stock.

(10)    COMMITMENTS AND CONTINGENCIES:

        Future rental payments for office facilities, office equipment, and well equipment under the remaining terms of non-cancelable operating leases are $6.8 million, $6.2 million, $5.0 million, $4.2 million, and $3.8 million for the years ending December 31, 2005 through 2009, respectively.

        Net rental payments applicable to exploration and development activities and capitalized in the oil and gas property accounts aggregated $5.6 million in 2004, $5.9 million in 2003, and $4.1 million in 2002. Net rental payments charged to expense amounted to $10.3 million in 2004, $8.3 million in 2003, and $7.5 million in 2002. Rental payments include the short-term lease of vehicles. There are no leases that are accounted for as capital leases.

        Forest, in the ordinary course of business, is a party to various lawsuits, claims, and proceedings. 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 Forest's results of operations and cash flow in the reporting periods in which any such actions are resolved. Forest is also involved in a number of governmental proceedings in the ordinary course of business, including environmental matters.

Long-Term Sales Contracts

        A portion of Canadian Forest's natural gas production is sold through the Canadian Netback Pool. The Canadian Netback Pool is comprised of market based and fixed price contracts. Canadian Forest's contractual obligation to deliver natural gas production volumes to these contracts extends through 2011. Canadian Forest's average daily production sold through the Canadian Netback Pool represented approximately 4% of Forest's total average daily production in 2004. Canadian Forest's total fixed-price production volume obligation, through 2011, is 27.4 Bcf. At December 31, 2004, the weighted average price of these contracts was approximately 82% of market value based on the closing AECO prices at December 31, 2004. The Canadian Netback Pool's contractual obligation to deliver volumes to these resale contracts extends through 2011.

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(11)    SELECTED QUARTERLY FINANCIAL DATA (unaudited):

		First Quarter			Second Quarter		Third Quarter		Fourth Quarter
		(In Thousands Except Per Share Amounts)
2004
Revenue		$	194,253		208,478		245,393		264,774
Earnings from operations		$	44,661		56,301		73,320		84,005
Net earnings from continuing operations		$	19,637		28,130		31,775		43,584
Net earnings		$	19,062		28,130		31,775		43,584
Basic earnings per share from continuing operations		$	.37		.51		.54		.73
Basic earnings per share			.36		.51		.54		.73
Diluted earnings per share from continuing operations			.36		.50		.53		.72
Diluted earnings per share			.35		.50		.53		.72
2003(1)
Revenue		$	168,072		154,245		161,329		173,532
Earnings from operations		$	72,900		54,495		53,272		20,502
Net earnings from continuing operations		$	34,256		23,537		26,321		6,114
Net earnings (loss)		$	38,871		23,412		26,340		(272	)
Basic earnings per share from continuing operations		$	.72		.49		.55		.11
Basic earnings (loss) per share			.81		.49		.55		(.01	)
Diluted earnings per share from continuing operations			.70		.48		.54		.11
Diluted earnings (loss) per share			.80		.48		.54		(.01	)

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⁽¹⁾

In conjunction with the Company's fourth quarter 2003 decision to sell its Canadian marketing subsidiary, ProMark, the financial information for each of the quarters of 2003 has been restated to report ProMark's results of operations as discontinued operations.

(12)    BUSINESS AND GEOGRAPHICAL SEGMENTS:

      Segment information has been prepared in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. At December 31, 2004, Forest had five reportable segments consisting of oil and gas operations in five business units (Gulf Coast, Western, Alaska, Canada, and International). On March 1, 2004, the assets and business operations of the Company's gas marketing subsidiary, ProMark, were sold to Cinergy, as discussed in Note 2. Accordingly, in conjunction with the Company's fourth quarter 2003 decision to sell the gas marketing business of ProMark, ProMark's results of operations have been reported as discontinued operations, and the segment reporting for 2002 has been restated to exclude the marketing activities of ProMark. The Company's remaining processing activities are not significant and therefore are not reported as a separate segment, but are included as a reconciling item in the information below. In addition, in the first quarter of 2003, the Company modified its business unit structure by combining the Gulf of Mexico Offshore Region and the Gulf Coast Onshore Region into

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the Gulf Coast for increased efficiencies. Therefore, segment information for the 2002 period has been restated to give effect to this combination.

        The segments were determined based upon the type of operations in each business unit and the geographical location of each. The segment data presented below was prepared on the same basis as the consolidated financial statements.

Year ended December 31, 2004

			Oil and Gas Operations
			Gulf Coast			Western		Alaska		Total United States		Canada		International		Total Company
			(In Thousands)
Revenue			$	566,177		172,500		60,913		799,590		110,190		—		909,780
Expenses:
	Oil and gas production			122,402		46,970		46,660		216,032		22,162		—		238,194
	General and administrative			8,667		2,607		3,680		14,954		3,837		—		18,791
	Depletion			212,784		33,390		58,400		304,574		45,737		—		350,311
	Impairment and other			5,273		1,270		497		7,040		1,764		4,125		12,929
	Accretion of asset retirement obligations			13,835		1,189		1,461		16,485		766		—		17,251
Earnings from operations			$	203,216		87,074		(49,785	)	240,505		35,924		(4,125	)	272,304
Capital expenditures(1)			$	255,892		258,352		21,928		536,172		158,310		5,755		700,237
Property and equipment, net			$	1,259,473		629,595		377,804		2,266,872		386,926		55,966		2,709,764
Goodwill			$	16,859		37,525		—		54,384		14,176		—		68,560

---

⁽¹⁾

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

        Information for reportable segments relates to the Company's 2004 consolidated totals as follows:

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Year ended December 31, 2003

			Oil and Gas Operations
			Gulf Coast			Western		Alaska		Total United States		Canada		International		Total Company
			(In Thousands)
Revenue			$	416,454		98,388		75,375		590,217		64,976		—		655,193
Expenses:
	Oil and gas production			75,011		23,188		41,482		139,681		14,489		—		154,170
	General and administrative			9,090		2,528		4,790		16,408		3,955		495		20,858
	Depletion			148,745		18,547		34,851		202,143		28,917		—		231,060
	Impairment and other			—		—		—		—		—		16,910		16,910
	Accretion of asset retirement obligations			10,130		910		2,302		13,342		423		20		13,785
Earnings from operations			$	173,478		53,215		(8,050	)	218,643		17,192		(17,425	)	218,410
Capital expenditures(1)			$	412,072		193,014		68,933		674,019		46,518		8,211		728,748
Property and equipment, net			$	1,231,680		414,510		418,968		2,065,158		304,138		56,747		2,426,043

---

⁽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.

        Information for reportable segments relates to the Company's 2003 consolidated totals as follows:

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Year ended December 31, 2002

			Oil and Gas Operations
			Gulf Coast			Western		Alaska		Total United States		Canada		International		Total Company
			(In Thousands)
Revenue			$	292,347		63,054		65,475		420,876		50,864		—		471,740
Expenses:
	Oil and gas production			82,331		21,572		40,988		144,891		13,808		—		158,699
	General and administrative			19,293		6,041		7,570		32,904		4,738		—		37,642
	Depletion			123,409		17,614		18,818		159,841		21,326		—		181,167
Earnings from operations			$	67,314		17,827		(1,901	)	83,240		10,992		—		94,232
Capital expenditures			$	115,256		37,578		163,836		316,670		21,286		16,264		354,220
Property and equipment, net			$	785,024		231,507		368,223		1,384,754		229,773		66,533		1,681,060

        Information for reportable segments relates to the Company's 2002 consolidated totals as follows:

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(13)    SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited):

        The following information is presented in accordance with Statement of Financial Accounting Standards No. 69, Disclosure about Oil and Gas Producing Activities (SFAS No. 69).

(A)    Costs Incurred in Oil and Gas Exploration and Development Activities.    The following costs were incurred in oil and gas acquisition, exploration and development activities during the years ended December 31, 2004, 2003, and 2002:

			United States			Canada		International		Total
			(In Thousands)
2004
	Property acquisition costs (undeveloped leases and proved properties)		$	316,214		109,212		—		425,426
	Exploration costs			67,317		18,521		5,755		91,593
	Development costs			152,641		30,577		—		183,218
	Estimated discounted future abandonment costs(1)			12,065		2,000		—		14,065
	Total costs incurred		$	548,237		160,310		5,755		714,302
2003
	Property acquisition costs (undeveloped leases and proved properties)		$	424,223		—		22		424,245
	Exploration costs			64,061		32,014		8,189		104,264
	Development costs			185,735		14,504		—		200,239
	Estimated discounted future abandonment costs(1)			63,293		443		—		63,736
	Total costs incurred		$	737,312		46,961		8,211		792,484
2002
	Property acquisition costs (undeveloped leases and proved properties)		$	3,938		—		(13	)	3,925
	Exploration costs			72,685		13,401		16,277		102,363
	Development costs			240,047		7,885		—		247,932
	Total costs incurred		$	316,670		21,286		16,264		354,220

---

⁽¹⁾

Estimated discounted future abandonment costs represent the anticipated future expenditures related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. See Note 1 for more information on asset retirement obligations.

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(B)    Aggregate Capitalized Costs.    The aggregate capitalized costs relating to oil and gas activities at the end of each of the years indicated were as follows:

(C)    Results of Operations from Producing Activities.    Results of operations from producing activities for the years ended December 31, 2004, 2003, and 2002 are presented below. Income taxes are different from income taxes shown in the Consolidated Statements of Operations because this table excludes certain items of income and expense.

					United States			Canada		Total
					(In Thousands)
2004
	Oil and gas sales				$	799,590		110,190		909,780
	Expenses:
		Production expense				216,032		22,162		238,194
		Depletion expense				304,574		45,737		350,311
		Impairment				2,233		—		2,233
		Accretion of asset retirement obligations				16,485		766		17,251
		Income tax expense				98,901		13,952		112,853
			Total expenses			638,225		82,617		720,842
	Results of operations from producing activities				$	161,365		27,573		188,938
2003
	Oil and gas sales				$	590,217		64,976		655,193
	Expenses:
		Production expense				139,681		14,489		154,170
		Depletion expense				202,143		28,917		231,060
		Accretion of retirement obligations				13,362		423		13,785
		Income tax expense				89,312		9,404		98,716
			Total expenses			444,498		53,233		497,731
	Results of operations from producing activities				$	145,719		11,743		157,462

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2002
	Oil and gas sales				$	420,876		50,864		471,740
	Expenses:
		Production expense				144,891		13,808		158,699
		Depletion expense				159,841		21,326		181,167
		Income tax expense				44,135		5,576		49,711
			Total expenses			348,867		40,710		389,577
	Results of operations from producing activities				$	72,009		10,154		82,163

(D)    Estimated Proved Oil and Gas Reserves.    The Company's estimate of its net proved and proved developed oil and gas reserves and changes for 2004, 2003, and 2002 follows. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made.

        Prices include consideration of changes in existing prices provided only by contractual arrangement, but not on escalations based on future conditions. Purchases of reserves in place represent volumes recorded on the closing dates of the acquisitions for financial accounting purposes.

        Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

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        Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

			Liquids (MBbls)						Gas (MMcf)
			United States		Canada		Total		United States		Canada		Total		Total MMcfe
Balance at January 1, 2002			110,995		8,554		119,549		668,739		159,810		828,549		1,545,843
	Revisions of previous estimates		3,419		170		3,589		1,002		(18,565	)	(17,563	)	3,971
	Extensions and discoveries		10,544		11		10,555		85,460		10,205		95,665		158,995
	Production		(7,477	)	(1,180	)	(8,657	)	(78,543	)	(13,525	)	(92,068	)	(144,010	)
	Sales of reserves in place		(97	)	(641	)	(738	)	(324	)	(3,059	)	(3,383	)	(7,811	)
	Purchases of reserves in place		68		—		68		2,076		118		2,194		2,602
Balance at December 31, 2002			117,452		6,914		124,366		678,410		134,984		813,394		1,559,590
	Revisions of previous estimates		(60,652	)	885		(59,767	)	(94,895	)	(19,136	)	(114,031	)	(472,633	)
	Extensions and discoveries		674		468		1,142		36,314		14,647		50,961		57,813
	Production		(7,686	)	(1,015	)	(8,701	)	(84,368	)	(12,609	)	(96,977	)	(149,183	)
	Sales of reserves in place		(2,303	)	—		(2,303	)	(7,364	)	—		(7,364	)	(21,182	)
	Purchases of reserves in place		26,587		—		26,587		162,085		—		162,085		321,607
Balance at December 31, 2003			74,072		7,252		81,324		690,182		117,886		808,068		1,296,012
	Revisions of previous estimates		3,664		(359	)	3,305		(20,125	)	(6,586	)	(26,711	)	(6,881	)
	Extensions and discoveries		1,098		213		1,311		33,212		11,582		44,794		52,660
	Production		(9,550	)	(1,287	)	(10,837	)	(91,420	)	(15,946	)	(107,366	)	(172,388	)
	Sales of reserves in place		(4,203	)	(4,003	)	(8,206	)	(13,160	)	(22,193	)	(35,353	)	(84,589	)
	Purchases of reserves in place		17,982		3,934		21,916		84,889		32,804		117,693		249,189
Balance at December 31, 2004			83,063		5,750		88,813		683,578		117,547		801,125		1,334,003
Proved developed reserves at:
	December 31, 2002		61,398		6,914		68,312		496,056		79,777		575,833		985,705
	December 31, 2003		53,942		6,917		60,859		518,317		91,781		610,098		975,252
	December 31, 2004		61,494		5,551		67,045		532,810		94,320		627,130		1,029,400

        During 2003, Forest revised downward its estimate of proved reserves by a total of approximately 473 Bcfe. The downward revision of the Company's estimates was due to information received from production results, drilling activity, and other events that occurred primarily in the latter part of 2003.

        Approximately 62% of the total revisions was attributable to the downward revision of the Company's estimate of proved oil reserves in the Redoubt Shoal Field in the Cook Inlet, Alaska. Forest reduced its estimate of proved oil reserves associated with its Redoubt Shoal Field from its 2002 year-end estimate by approximately 49 million barrels, or approximately 85% of the estimated proved oil reserves in the field as of December 31, 2002. Of this revision, approximately 36 million barrels were classified as proved undeveloped as of December 31, 2002. Forest's estimate of proved oil reserves attributable to the Redoubt Shoal Field was approximately 7.5 million barrels as of December 31, 2004.

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(E)    Standardized Measure of Discounted Future Net Cash Flows.    Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of oil and natural gas is covered by contracts. Where the sale is covered by contracts, the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract. Thereafter, the current spot price was used. All cash flow amounts, including income taxes, are discounted at 10%.

        Future income tax expenses are estimated using an estimated combined federal and state income tax rate of 38% in the United States and an average combined federal and provincial rate of 34% in Canada. Estimates for future general and administrative and interest expense have not been considered.

        Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the Company's proved reserves. Management does not rely upon the information that follows in making investment decisions.

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        Present value of future net cash flows before income taxes was $2,964.1 million in the United States and $347.3 million in Canada at December 31, 2004.

        Present value of future net cash flows before income taxes was $2,622.2 million in the United States and $293.1 million in Canada at December 31, 2003.

        Present value of future net cash flows before income taxes was $2,323.9 million in the United States and $262.3 million in Canada at December 31, 2002.

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(F)    Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.    An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows:

			December 31, 2004
			United States			Canada		Total
			(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year			$	2,061,370		246,560		2,307,930
Changes resulting from:
	Sales of oil and gas, net of production costs			(702,832	)	(89,001	)	(791,833	)
	Net changes in prices and future production costs			217,917		60,660		278,577
	Net changes in future development costs			(49,696	)	(16,053	)	(65,749	)
	Extensions, discoveries, and improved recovery			153,376		32,159		185,535
	Previously estimated development costs incurred during the period			152,641		30,577		183,218
	Revisions of previous quantity estimates			11,024		(21,059	)	(10,035	)
	Sales of reserves in place			(90,124	)	(106,320	)	(196,444	)
	Purchases of reserves in place			387,396		133,974		521,370
	Accretion of discount on reserves at beginning of year before income taxes			262,221		29,305		291,526
	Net change in income taxes			(177,017	)	(11,521	)	(188,538	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year			$	2,226,276		289,281		2,515,557

        The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2004 was based on average natural gas prices of approximately $5.88 per Mcf in the U.S. and approximately $4.81 per Mcf in Canada, and on average

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liquids prices of approximately $39.23 per barrel in the U.S. and approximately $32.94 per barrel in Canada.

			December 31, 2003
			United States			Canada		Total
			(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year			$	1,843,797		209,351		2,053,148
Changes resulting from:
	Sales of oil and gas, net of production costs			(525,384	)	(50,487	)	(575,871	)
	Net changes in prices and future production costs			255,666		40,305		295,971
	Net changes in future development costs			(71,827	)	(6,897	)	(78,724	)
	Extensions, discoveries, and improved recovery			141,622		31,936		173,558
	Previously estimated development costs incurred during the period			185,823		14,416		200,239
	Revisions of previous quantity estimates			(596,760	)	(24,702	)	(621,462	)
	Sales of reserves in place			(29,565	)	—		(29,565	)
	Purchases of reserves in place			706,376		—		706,376
	Accretion of discount on reserves at beginning of year before income taxes			232,387		26,226		258,613
	Net change in income taxes			(80,765	)	6,412		(74,353	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year			$	2,061,370		246,560		2,307,930

        In 2003, the Company recorded significant reductions in its estimates of proved reserves in the Redoubt Shoal Field in Alaska. These revisions were anomalous to the Company's reserve base in that the reserves from this field realize lower sales prices and higher operating costs than the United States properties as a whole. For this reason, the changes in standardized measure of discounted future net cash flows relating to the Company's U.S. proved oil and gas reserves for the year ended December 31, 2003 represent the sum of (i) the changes in standardized measure for the Company's Redoubt Shoal Field (calculated on a stand-alone basis) and (ii) the changes in standardized measure for the Company's other U.S. properties (calculated on an aggregate basis).

        The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2003 was based on average natural gas prices of approximately $5.79 per Mcf in the U.S. and approximately $4.52 per Mcf in Canada, and on average

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liquids prices of approximately $29.89 per barrel in the U.S. and approximately $27.84 per barrel in Canada.

			December 31, 2002
			United States			Canada		Total
			(In Thousands)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at beginning of year			$	1,176,640		170,013		1,346,653
Changes resulting from:
	Sales of oil and gas, net of production costs			(278,855	)	(37,056	)	(315,911	)
	Net changes in prices and future production costs			822,901		119,484		942,385
	Net changes in future development costs			(160,173	)	(18,174	)	(178,347	)
	Extensions, discoveries, and improved recovery			138,241		10,414		148,655
	Previously estimated development costs incurred during the period			227,980		7,197		235,177
	Revisions of previous quantity estimates			89,629		(27,670	)	61,959
	Sales of reserves in place			(454	)	(8,702	)	(9,156	)
	Purchases of reserves in place			4,284		36		4,320
	Accretion of discount on reserves at beginning of year before income taxes			134,574		19,703		154,277
	Net change in income taxes			(310,970	)	(25,894	)	(336,864	)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves, at end of year			$	1,843,797		209,351		2,053,148

        The computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2002 was based on average natural gas prices of approximately $4.16 per Mcf in the U.S. and approximately $3.30 per Mcf in Canada, and on average liquids prices of approximately $27.85 per barrel in the U.S. and approximately $26.63 per barrel in Canada.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

        None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

        We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is made known to the Officers who certify Forest's financial reports and the Board of Directors.

        Our Chief Executive Officer, H. Craig Clark, and our Chief Financial Officer, David H. Keyte, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. Based on the evaluation, they believe that:

•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms; and



•

our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

        There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Internal Control over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act, Rules 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Item 9B. Other Information.

        None.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Forest Oil Corporation:

        We have audited management's assessment, included in the accompanying Internal Control Over Financial Reporting, that Forest Oil Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Forest Oil Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, management's assessment that Forest Oil Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Forest Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Forest Oil Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 15, 2005 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Denver, Colorado
March 15, 2005

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PART III

Item 10. Directors and Executive Officers of the Registrant.

        The information concerning Forest's directors required by this Item is incorporated by reference to the information under the captions "Proposal No. 1—Election of Directors" in the definitive Proxy Statement concerning its Annual Meeting of Shareholders to be held on May 10, 2005 (the "2005 Proxy Statement").

        The information concerning Forest's executive officers required by this Item is incorporated by reference to the information set forth under the caption "Executive Officers of Forest" included in Part I, Item 4A of this Form 10-K.

        The information concerning compliance with Section 16(a) of the Securities Exchange Act of 1934, as amended, required by this Item is incorporated by reference to the information set forth under the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in the 2005 Proxy Statement.

        The information concerning Forest's Audit Committee, Audit Committee financial expert, and code of ethics is incorporated by reference to the information set forth under the caption "Corporate Governance Principles and Information about the Board and its Committees" in the 2005 Proxy Statement.

Item 11. Executive Compensation.

        The information required by this Item is incorporated by reference to the information under the captions "Executive Compensation" and "Stock Performance Graph" in the 2005 Proxy Statement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

        The information required by this Item is incorporated by reference to the information under the caption "Common Stock Ownership of Certain Beneficial Owners and Management" in the 2005 Proxy Statement.

Item 13. Certain Relationships and Related Transactions.

        The information required by this Item is incorporated by reference to the information under the caption "Certain Relationships and Related Transactions" in the 2005 Proxy Statement.

Item 14. Principal Accounting Fees and Services.

        The information required by this Item is incorporated by reference to the information under the captions "Fees to Independent Auditors" and "Report of the Audit Committee" in the 2005 Proxy Statement.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)

The following documents are filed as part of this report or are incorporated by reference:

(1)

Financial Statements:

1.

Independent Auditors' Report

2.

Consolidated Balance Sheets—December 31, 2004 and 2003

3.

Consolidated Statements of Operations—Years ended December 31, 2004, 2003, and 2002

4.

Consolidated Statements of Shareholders' Equity—Years ended December 31, 2004, 2003, and 2002

5.

Consolidated Statements of Cash Flows—Years ended December 31, 2004, 2003, and 2002

6.

Notes to Consolidated Financial Statements—Years ended December 31, 2004, 2003, and 2002

(2)

Financial Statement Schedules: All schedules have been omitted because the information is either not required or is set forth in the financial statements or the notes thereto.

(3)

Exhibits: See the Index of Exhibits listed in Item 15(b) hereof for a list of those exhibits filed as part of this Form 10-K.

(b)

Index of Exhibits:

Exhibit Number		Exhibits
3.1		Restated Certificate of Incorporation of Forest Oil Corporation dated October 14, 1993, incorporated herein by reference to Exhibit 3(i) to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 1993 (File No. 0-4597).
3.2		Certificate of Amendment of the Restated Certificate of Incorporation, dated as of July 20, 1995, incorporated herein by reference to Exhibit 3(i)(a) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
3.3		Certificate of Amendment of the Certificate of Incorporation, dated as of July 26, 1995, incorporated herein by reference to Exhibit 3(i)(b) to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 1995 (File No. 0-4597).
3.4		Certificate of Amendment of the Certificate of Incorporation dated as of January 5, 1996, incorporated herein by reference to Exhibit 3(i)(c) to Forest Oil Corporation's Registration Statement on Form S-2 (File No. 33-64949).
3.5		Certificate of Amendment of the Certificate of Incorporation dated as of December 7, 2000, incorporated herein by reference to Exhibit 3(i)(d) to Form 10-K for Forest Oil Corporation for the year ended December 31, 2000 (File No. 001-13515).
3.6		Bylaws of Forest Oil Corporation Restated as of February 14, 2001 as amended by Amendments No. 1, No. 2 and No. 3, incorporated herein by reference to Exhibit 3.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).

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4.1		Indenture dated as of June 21, 2001 between Forest Oil Corporation and State Street Bank and Trust Company, incorporated herein by reference to Exhibit 4.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2001 (File No. 001-13515).
4.2		Indenture dated December 7, 2001 between Forest Oil Corporation and State Street Bank and Trust Company, incorporated herein by reference to Exhibit 4.5 to Forest Oil Corporation's Registration Statement on Form S-4 dated February 6, 2002 (File No. 333-82254).
4.3		Indenture dated as of April 25, 2002 between Forest Oil Corporation and State Street Bank and Trust Company, incorporated herein by reference to Exhibit 4.6 to Forest Oil Corporation's Registration Statement on Form S-4 dated June 11, 2002 (File No. 333-90220).
4.4		Registration Rights Agreement dated as of May 19, 1995 between Forest Oil Corporation and The Anschutz Corporation incorporated by reference to Exhibit 4.21 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1995 (file No. 001-13515).
4.5		Registration Rights Agreement, dated as of July 10, 2000, by and between Forest Oil Corporation and the other signatories thereto, incorporated herein by reference to Exhibit 4.15 to Forest Oil Corporation Registration Statement on Form S-4, dated November 6, 2000 (File No. 333-49376).
4.6		First Amended and Restated Rights Agreement, dated as of October 17, 2003, between Forest Oil Corporation and Mellon Investor Services LLC, incorporated herein by reference to Exhibit 4.1 to Forest Oil's Current Report on Form 8-K, dated October 17, 2003 (File No. 001-13515).
4.7		Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing from Forest Oil Corporation to Robert C. Mertensotto, trustee, and Gregory P. Williams, trustee (Utah), and The Chase Manhattan Bank, as Global Administrative Agent, dated as of December 7, 2000, incorporated herein by reference to Exhibit 4.13 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2000 (File No. 001-13515).
4.8		U.S. Credit Agreement—Amended and Restated Credit Agreement dated as of September 28, 2004, among Forest Oil Corporation, each of the lenders that is party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas and Harris Nesbitt Financing, Inc., as Co-U.S. Documentation Agents, and JPMorgan Chase Bank, as Global Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).
4.9		Canadian Credit Agreement—Amended and Restated Credit Agreement dated as of September 28, 2004, among Forest Oil Corporation, each of the lenders that is party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas and Harris Nesbitt Financing, Inc., as Co-U.S. Documentation Agents, and JPMorgan Chase Bank, as Global Administrative Agent, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).
10.1*		Description of Executive Life Insurance Plan, incorporated herein by reference to Exhibit 10.2 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1991 (File No. 0-4597).

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10.2*		Form of non-qualified Supplemental Executive Retirement Plan, incorporated herein by reference to Exhibit 10.4 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
10.3*		Form of Executive Retirement Agreement, incorporated herein by reference to Exhibit 10.5 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1990 (File No. 0-4597).
10.4*		Forest Oil Corporation 1996 Stock Incentive Plan and Option Agreement, incorporated herein by reference to Exhibit 4.1 to Form S-8 for Forest Oil Corporation dated June 7, 1996 (File No. 0-4597).
10.5*		First Amendment to Forest Oil Corporation 1996 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2001 (File No. 001-13515).
10.6*		Second Amendment to Forest Oil Corporation 1996 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2001 (File No. 001-13515).
10.7*		Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.9 to Form 10-K for Forest Oil Corporation for the year ended December 31, 1993 (File No. 0-4597).
10.8*		Form of First Amendment to Severance Agreement, incorporated herein by reference to Exhibit 10.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2001 (File No. 001-13515).
10.9*		Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2001 (File No. 001-13515).
10.10*		Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.10 to Forest Oil Corporation's Registration Statement on Form S-4 dated February 6, 2002 (File No. 333-82254).
10.11*		Form of Amendment to Severance Agreement, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).
10.12*		Form of Executive Severance Agreement, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2003 (File No. 001-13515).
10.13*		Form of SVP Severance Agreement, incorporated herein by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).
10.14*		Form of Grandfathered SVP Severance Agreement, incorporated herein by reference to Exhibit 10.4 for Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).
10.15*		Form of VP Severance Agreement, incorporated herein by reference to Exhibit 10.5 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).

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10.16*		Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 4.1 to Form S-8 for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).
10.17*		Amendment No. 1 to Forest Oil Corporation's 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).
10.18*		Amendment No. 2 to Forest Oil Corporation's 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2004 (File No. 001-13515).
10.19*		Form of Employee Stock Option Agreement, incorporated herein by reference to Exhibit 4.2 to Form S-8 for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).
10.20*		Form of Non-Employee Director Stock Option Agreement, incorporated herein by reference to Exhibit 4.3 to Form S-8 for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).
10.21*		Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2004 (File No. 001-13515).
10.22*		Forest Oil Corporation Pension Trust Agreement dated as of January 1, 2002 by and between Forest Oil Corporation and the trustees named therein or their successors, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2002 (File No. 001-13515).
10.23*		Forest Oil Corporation Amended and Restated Salary Deferral Compensation Plan, incorporated herein by reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2003 (File No. 001-13515).
10.24*†		Forest Oil Corporation 2005 Salary Deferred Compensation Plan, effective as of December 31, 2004.
10.25*		Forest Oil Corporation Change of Control Deferred Compensation Plan, incorporated herein by reference to Exhibit 10.18 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2002 (File No. 001-13515).
10.26*		Forest Oil Corporation Executive Deferred Compensation Plan, effective as of July 1, 1994, incorporated herein by reference to Exhibit 10.24 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2003 (File No. 001-13515).
10.27*		First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan dated November 13, 2002, incorporated herein by reference to Exhibit 10.20 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2002 (File No. 001-13515).
10.28*		Second Amendment to Forest Oil Corporation Executive Deferred Compensation Plan dated February 3, 2003, incorporated herein by reference to Exhibit 10.21 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2002 (File No. 001-13515).
10.29*		Forest Oil Corporation 2005 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed on March 1, 2005.
10.30*		Forest Oil Corporation 2004 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed on March 1, 2005.

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21.1†		List of Subsidiaries of Registrant.
23.1†		Consent of KPMG LLP.
23.2†		Consent of Ryder Scott Company, L.P.
23.3†		Consent of DeGolyer and MacNaughton.
23.4†		Consent of Gilbert Laustsen Jung Associates Ltd.
24.1†		Powers of Attorney (included on the signature pages hereof).
31.1†		Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Act of 1934.
31.2†		Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Act of 1934.
32.1**		Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2**		Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

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*

Contract or compensatory plan or arrangement in which directors and/or officers participate.

**

Not considered to be "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†

Indicates exhibits filed with this Form 10-K.

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SIGNATURES

        Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: March 15, 2005		FOREST OIL CORPORATION (Registrant)
		By:		/s/  H. CRAIG CLARK       H. Craig Clark President and Chief Executive Officer

Power of Attorney

        The officers and directors of Forest Oil Corporation, whose signatures appear below, hereby constitute and appoint H. Craig Clark, David H. Keyte, Cyrus D. Marter IV, and Victor A. Wind and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this Form 10-K Annual Report for the year ended December 31, 2004, and any instrument or document filed as part of, as an exhibit to or in connection with any amendment, and each of the undersigned does hereby ratify and confirm as his own act and deed all that said attorneys shall do or cause to be done by virtue thereof.

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Signatures		Title		Date
/s/  H. CRAIG CLARK       H. Craig Clark		President and Chief Executive Officer and Director (Principal Executive Officer)		March 15, 2005
/s/   DAVID H. KEYTE       David H. Keyte		Executive Vice President and Chief Financial Officer (Principal Financial Officer)		March 15, 2005
/s/   VICTOR A. WIND       Victor A. Wind		Controller—Financial Accounting (Principal Accounting Officer)		March 15, 2005
/s/   FORREST E. HOGLUND       Forrest E. Hoglund		Chairman of the Board of Directors		March 15, 2005
/s/   WILLIAM L. BRITTON       William L. Britton		Director		March 15, 2005

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/s/   CORTLANDT S. DIETLER       Cortlandt S. Dietler		Director		March 15, 2005
/s/   DOD. A. FRASER       Dod. A. Fraser		Director		March 15, 2005
/s/   JAMES H. LEE       James H. Lee		Director		March 15, 2005
/s/   JAMES D. LIGHTNER       James D. Lightner		Director		March 15, 2005
/s/  PATRICK R. MCDONALD       Patrick R. McDonald		Director		March 15, 2005

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Index to Exhibits

Exhibit Number		Exhibits
10.24		Forest Oil Corporation 2005 Salary Deferred Compensation Plan, effective as of December 31, 2004.
21.1		List of Subsidiaries of Registrant.
23.1		Consent of KPMG LLP.
23.2		Consent of Ryder Scott Company, L.P.
23.3		Consent of DeGolyer and MacNaughton.
23.4		Consent of Gilbert Laustsen Jung Associates Ltd.
31.1		Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Act of 1934.
31.2		Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Act of 1934.
32.1		Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.
32.2		Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

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