UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

x                              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

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

FOREST OIL CORPORATION

(Exact Name of Registrant as Specified in Its Charter)

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

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act.

Large accelerated filer x        Accelerated filer o        Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, was $1,808,671,247 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

There were 63,009,959 shares of the registrant’s common stock, par value $.10 per share, outstanding as of February 16, 2007.

Documents incorporated by reference: Portions of the registrant’s notice of annual meeting of shareholders and proxy statement to be filed pursuant to Regulation 14A within 120 days after the registrant’s fiscal year end of December 31, 2006 are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

i

PART I

Item 1.                        Business.

General

Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of natural gas and liquids primarily in North America. 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 conduct our operations in three geographical segments and five business units. Geographical segments include: the United States, Canada and International. Business units include: the Western United States (“Western”), Southern United States (“Southern”), Alaska, Canada and International. We conduct exploration and development activities in each of our geographical segments; however, all of our estimated proved reserves and producing properties are located in North America. While discoveries of oil and gas have been made in our International business unit, no proven reserves have been recorded to date. At December 31, 2006, approximately 84% of our estimated proved oil and gas reserves were in the United States and approximately 16% were in Canada. Forest’s total estimated proved reserves as of December 31, 2006 were 1,455 Bcfe.

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 “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.

Pending Acquisition of Houston Exploration

On January 7, 2007, Forest announced it had entered into a definitive agreement and plan of merger pursuant to which The Houston Exploration Company (“Houston Exploration”) will merge with and into Forest in a stock and cash transaction totaling approximately $1.5 billion plus the assumption of debt. Houston Exploration is an independent natural gas and oil producer engaged in the exploration, development, exploitation and acquisition of natural gas and oil reserves in North America with operations in the following four producing areas in the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. The boards of directors of Forest and Houston Exploration have each unanimously approved the transaction. The transaction is subject to regulatory approvals and other customary conditions, as well as both Forest shareholder and Houston Exploration stockholder approvals. Forest management and its board of directors will continue in their current positions with Forest following the completion of the merger. The merger is expected to close in the second quarter of 2007.

Under the terms of the merger agreement, Houston Exploration stockholders are to receive total consideration equal to 0.84 shares of Forest common stock and $26.25 in cash for each share of Houston Exploration common stock outstanding. This represents estimated merger consideration of 23.6 million shares of Forest common stock and cash of approximately $740 million, or $52.47 per share, to be received by the Houston Exploration stockholders (based on the closing price of Forest’s common stock on January 5, 2007 and the number of shares of Houston Exploration common stock outstanding on January 4, 2007 and subject to increase in the event that any additional shares of Houston Exploration common stock are issued prior to the merger closing date in connection with the exercise of outstanding stock options pursuant to the terms of the merger agreement). The actual amount of total cash and stock consideration to be received by each Houston Exploration stockholder will be determined by elections, an

1

equalization formula and a proration procedure. It is anticipated that the transaction will be tax free to Houston Exploration and the stock portion of the consideration will be received tax free by its stockholders. The cash component of the acquisition is expected to be financed under an amended and restated revolving credit facility of up to $1.4 billion for which JPMorgan Chase Bank, N.A. has provided us a commitment letter.

Spin-off of Offshore Gulf of Mexico Operations

On March 2, 2006, Forest completed the spin-off of its offshore Gulf of Mexico operations by means of a stock dividend, which consisted of a pro rata spin-off (the “Spin-off”) of all outstanding shares of Forest Energy Resources, Inc. (hereinafter known as Mariner Energy Resources, Inc. or “MERI”), a total of 50,637,010 shares of common stock, to holders of record of Forest common stock as of the close of business on February 21, 2006. Immediately following the Spin-off, MERI was merged with a subsidiary of Mariner Energy, Inc. (“Mariner”) (the “Merger”). Mariner’s common stock commenced trading on the New York Stock Exchange on March 3, 2006. The Spin-off was completed without the payment of consideration by Forest shareholders and consisted of a special dividend of 0.8093 shares of MERI for each outstanding share of Forest common stock. In the Merger, Forest shareholders received one share of Mariner common stock for each whole share of MERI that they held. The Spin-off was a tax-free transaction for federal income tax purposes.

Business Strategy

Our strategy includes four key points: to provide organic growth, make strategic acquisitions, control costs, and remain financially flexible.

Organic Growth

The acquisitions of The Wiser Oil Company in 2004, the Buffalo Wallow field in 2005, and the East Texas Cotton Valley assets in 2006 provide, and we also expect the proposed acquisition of Houston Exploration to provide, assets conducive to low-risk, repeatable development and exploitation opportunities. In 2007, Forest expects organic growth from its planned exploitation activities, including exploration and development drilling, workovers, stimulation treatments, water floods, and recompletions.

Make Strategic 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. Since the inception of our four-point plan in 2003, through 2006, we have spent approximately $1.5 billion (including deferred tax gross ups of $151 million recorded in connection with business combinations) to acquire approximately 838 Bcfe of estimated proved reserves. In general, our acquisition program since 2004 has focused on acquisitions of properties that have substantial development drilling opportunities and undeveloped acreage.

During 2006, we made approximately $316 million of oil and gas acquisitions, including the acquisition of oil and gas properties located primarily in the Cotton Valley trend in East Texas (“Cotton Valley assets”) for approximately $255 million in cash, as adjusted to reflect an economic effective date of February 2, 2006. At the time the acquisition was announced, the Cotton Valley assets included approximately 26,000 net acres, an estimated 110 Bcfe of estimated proved reserves, and production of 13 MMcfe per day. Of the 26,000 net acres, approximately 14,000 net acres were undeveloped.

During 2005, we made approximately $314 million of oil and gas acquisitions (including approximately $71 million of deferred tax gross ups). The largest acquisition was of oil and gas properties in the Buffalo Wallow area in the Texas Panhandle in April 2005. The Buffalo Wallow transaction included the payment

2

of $197 million in cash and the assumption of $35 million of debt to acquire approximately 120 Bcfe of estimated proved reserves and approximately 28,000 net acres primarily in Hemphill and Wheeler Counties, Texas.

During 2004, we made approximately $436 million of oil and gas acquisitions (including approximately $47 million of deferred tax gross ups). Our largest acquisition in 2004 was of The Wiser Oil Company (“Wiser”) in June 2004 which included oil and gas assets valued at $347 million. The Wiser transaction included the payment of $171 million in cash and the assumption of $163 million of debt to acquire approximately 186 Bcfe of estimated proved reserves and approximately 388,000 net acres.

Focus on Cost Control

Maintaining capital spending discipline and a focus on cost control are keystones of Forest’s business philosophy. We establish budgets that are designed to generate discretionary cash flow in each of our producing business units. A critical area of our cost control efforts is lease operating expense. While in a period of rising costs in the oil and gas sector, we have successfully kept our per-unit lease operating expenses attributable to the properties retained after the Spin-off at levels near those achieved in 2004. See “Lease Operating Expenses” and the accompanying table on page 34. Lease operating expense attributable to the retained properties was $1.21 per Mcfe in 2006 compared to $1.19 per Mcfe in 2004.

Maintain Financial Flexibility

We seek to maintain financial flexibility and sufficient liquidity to capitalize on opportunities as they arise. Generally, we attempt to maintain a debt-to-book capitalization ratio of between 30% and 40% but may occasionally exceed this range when conditions warrant using leverage to make strategic acquisitions. At December 31, 2006, for example, our debt-to-book capitalization ratio was 46%, which was higher than our targeted ratio. The higher leverage was due to two transactions in 2006. The Spin-off, which was accounted for as a special dividend, reduced our shareholders’ equity by over $500 million. In addition, we utilized our bank credit facilities in 2006 to purchase the Cotton Valley assets for $255 million as described above. Upon closing the pending acquisition of Houston Exploration, our debt-to-book capitalization ratio will likely increase to approximately 50% due primarily to the approximate $740 million of cash consideration expected to be paid and other Houston Exploration debt to be assumed. However, as discussed below, we have recently announced plans to sell our Alaska business unit in 2007 in order to reduce indebtedness. At December 31, 2006, we had approximately $33 million of cash on hand and $489 million available under our credit facilities.

Hedging is an important part of our strategy to mitigate our exposure to commodity price volatility. We have a board-approved policy related to commodity hedging activities. As of February 27, 2007 we have hedged, via swaps and collar instruments, approximately 55 Bcfe of our 2007 production.

3

Business Unit Activities

The production volumes, estimated proved reserves, and capital expenditures for our business units as of and for the year ended December 31, 2006 are summarized below.

(1)                 The offshore component of the Southern business unit represented the offshore Gulf of Mexico operations that were included in the Spin-off, which was completed on March 2, 2006 as discussed above.

(2)                 Does not include estimated discounted asset retirement obligations of $2.4 million, including $1.0 million assumed in connection with acquisition activities.

Southern

The Southern business unit’s onshore operations are located in East Texas, South Texas, and Louisiana Gulf Coast. The onshore portion of the Southern business unit had a production increase of 24% in 2006 compared to 2005. Production was increased through a combination of acquisitions and exploitation, including a drilling program that totaled 56 gross wells in 2006. The Southern business unit’s major capital expenditures in 2007 are expected to be primarily directed to its East Texas Cotton Valley field as well as the Katy field outside of Houston, in which the Company gained operatorship in August 2006.

Western

The Western business unit’s operations are located in the Texas Panhandle, West Texas, New Mexico, western Oklahoma, Utah and Wyoming. The Western business unit had a production increase of 15% in 2006 compared to 2005 primarily due to the continued development of the Buffalo Wallow field and exploration success in the Greater Haley/Vermejo fields in Texas. In 2007, capital expenditures in this business unit are expected to be primarily targeted in the Buffalo Wallow field and the Permian Basin.

Alaska

The Alaska business unit’s operations are primarily located onshore and offshore Cook Inlet. The Alaska business unit had a production decrease of 8% in 2006 compared to 2005. Production decreased due to natural declines in the non-operated offshore oil fields offset in part by increased natural gas production in 2006 from our onshore gas exploration program. Effective October 31, 2006, we transferred the majority of the assets associated with the Alaska business unit to a separate subsidiary which obtained $375 million of term loan financing that is secured by substantially all of the subsidiary’s assets and is nonrecourse to Forest’s other assets. See Note 4 to the Consolidated Financial Statements. In January 2007, the Company announced its plans to sell its Alaska business unit in order to reduce indebtedness associated with the pending acquisition of Houston Exploration.

4

Canada

The Canada business unit’s operations are located primarily in Alberta and British Columbia. The Canada business unit had a production increase of 18% in 2006 compared to 2005. Production was increased through development and exploratory drilling in the Wild River, Ansell and Foothills areas in central Alberta. In 2007, capital expenditures in this business unit are expected to be directed primarily in the Wild River, Evi/Loon, Ansell, and Foothills areas.

International

The International business unit’s operations are located primarily in South Africa, Gabon and Italy. In 2006, the International business unit completed the drilling of a shallow oil prospect in Gabon which was found to be dry; however, the majority of the drilling costs were carried by our partners. In South Africa, the International business unit continued to pursue commercial development of the Ibhubesi field discovery. The business unit filed a production right application and also continued efforts toward securing gas contracts for the Ibhubesi field. In 2007, the business unit plans to drill a gas test well in central Italy which was originally planned for 2006 but was delayed due to rig availability following the receipt of the drilling permit.

Reserves

The following table shows our estimated quantities of proved reserves as of December 31, 2006 and 2005. All estimated proved reserves are currently located in North America. See Note 15 to the Consolidated Financial Statements for additional information regarding estimated proved reserves.

(1)                 “Retained Properties” refers to the properties and associated estimated proved reserves retained by Forest following the Spin-off transaction completed on March 2, 2006. The “Spin-off Properties” and associated estimated proved reserves relate to Forest’s offshore Gulf of Mexico properties, which were included in the Spin-off, as discussed above.

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 its interpretation. 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 or development and production expenses, may require revision of such estimates. Accordingly, oil and gas

5

quantities ultimately recovered will vary from reserve estimates. See Item 1A—“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 2006, we filed estimates of our oil and gas reserves as of December 31, 2005 with the DOE, which were consistent with the reserve data reported for the year ended December 31, 2005 in Note 15 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 the aggregate value of Forest’s year-end proved reserves, discounted at 10% per annum, for each country in which Forest owns fields for which proved reserves have been recorded. The fields selected for audit comprise at least the top 80% of Forest’s fields based on the discounted value of such fields and a minimum of 80% of the value added during the year through discoveries, extensions, and acquisitions. Forest may also include fields that fall outside of the top 80% 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%. The independent reserve engineers then compare their estimates to those prepared by Forest. The independent reserve audits prepared for Forest are not financial audits and are not performed in accordance with the established generally accepted financial audit procedures. Instead, a reserve audit is conducted based on rules and regulations, reserve definitions, and costs and price parameters specified by the Securities and Exchange Commission (“SEC”).

For the year-end 2006, we engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to perform reserve audit services. DeGolyer and MacNaughton independently audited estimates relating to properties constituting approximately 83% of our reserves, as of December 31, 2006, based on reserve values. When compared on a field-by-field basis, some of Forest’s estimates of net proved reserves were greater and some were less than the estimates prepared by DeGolyer and MacNaughton. However, there was no material difference, in the aggregate, between Forest’s internal estimates of total net proved reserves and the estimates prepared by DeGolyer and MacNaughton for the fields subject to the audit.

6

Drilling Activities

During 2006, we drilled a total of 382 gross wells, of which 158 were classified as exploration and 224 were classified as development. Our 2006 drilling program achieved a 98% success rate. The following table summarizes the number of wells drilled during 2006, 2005, and 2004, 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, 2006, we had 27 gross (16 net) wells in progress in the United States and 18 gross (10 net) wells in progress in Canada.

(1)                 A non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well; also known as a dry well (or dry hole).

Productive Wells

Productive wells consist of producing wells, and wells capable of production, including shut-in wells. One or more completions in the same well bore are counted as one well. As of December 31, 2006, Forest owned interests in 410 gross wells containing multiple completions. The following table summarizes our productive wells as of December 31, 2006, all of which are located in the United States and Canada:

(1)                 The large variance between gross and net non-operated wells is primarily a result of our ownership interest in approximately 2,539 gross gas wells in the San Juan Basin with an average working interest of approximately 2%.

7

Acreage

The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of December 31, 2006 and 2005. A majority of our developed acreage in the United States and Canada is subject to mortgage liens securing our bank credit facilities. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests.

At December 31, 2006, approximately 1% and 9% of our net undeveloped acreage in the United States and Canada was held under leases that have terms that will expire in 2007 and 2008, respectively, if not extended by exploration or production activities. In the first quarter of 2007, we relinquished two permits in Italy comprising 363,853 gross and net undeveloped acres. The South African national government recently adopted legislation to revise the process pursuant to which it grants petroleum exploration and production licenses. Under the new regulations, we have applied to the government to convert one existing prospecting sublease into an exploration right. In addition, we are in the process of applying for a production right covering the geographic area of our other existing prospecting sublease. Because the regulations implementing the new legislation in South Africa are not yet final, we cannot predict whether these applications, if granted, will meet our economic or operational requirements, in which event we may choose to relinquish our rights.

8

Production, Average Sales Prices, and Production Costs

The following table reflects production, average sales price, and production cost information for the years ended December 31, 2006, 2005, and 2004.

(1)                 Include the effects of hedging under cash flow hedge accounting. See Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations”, concerning our hedging activities and the effects of energy swaps and collars not accounted for under cash flow hedge accounting.

Marketing and Delivery Commitments

Our oil and gas production is sold to various purchasers in accordance with our credit policies and procedures. These policies and procedures take into account the credit-worthiness of potential purchasers 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 ability to sell our production, because any individual spot purchaser could be readily replaced by another spot purchaser, absent a broad market disruption. In 2006, sales to FB Energy Canada Corp and Tesoro Alaska Petroleum Company represented approximately 12% and 13%, respectively, of our total oil and gas revenue.

Our natural gas production is typically sold on a month-to-month basis in the spot market, priced in reference to 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. In Canada, a portion of our natural gas production is also sold through a joint venture with other producers (the “Canadian Netback Pool”), which is a long-term commitment, or under direct sales contracts or spot

9

contracts. See Part II, Item 7A—“Quantitative and Qualitative Disclosures about Market Risk,” below, for further details.

Competition

Forest encounters competition in all aspects of its 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 completing wells. Our ability to increase reserves in the future will depend on our ability to generate successful prospects on our existing properties, execute on major development drilling programs, acquire new producing properties, and 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, staff and resources to identify and evaluate properties, available funds, and internal standards for minimum projected return on investment. Higher recent commodity prices have increased both equipment, service and labor costs in the industry as well as the cost of properties available for acquisition and a large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources. 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 United States federal, state, and local laws and regulations and foreign laws and regulations.

United States

Various aspects of our oil and natural gas operations are subject to regulation by state and federal agencies. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have adopted laws regulating the exploration for and production of crude oil and natural gas, including laws requiring permits for the drilling of wells, imposing bonding requirements in order to drill or operate wells, and providing authority for regulation relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, 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 of our operations are conducted on federal land pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). These leases contain relatively standardized terms and require compliance with detailed BLM regulations and orders (which are subject to change by the BLM). In addition to permits required from other agencies, lessees must obtain a permit from the BLM 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 the Mineral Management Service (“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.

Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by Congress, the states, the 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.

10

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 in certain circumstances. Regulatory requirements also exist related to licensing for drilling of wells, the method and ability to produce wells, surface usage, transportation of production from wells, and conservation matters. 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 taxes, environmental protection, and other matters under their respective jurisdictions. 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 depend on prescribed reference prices, well productivity, geographical location, and the type or quality of the product produced. Any royalties payable on production from privately owned lands are determined by negotiations between Forest and the landowners.

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 exploration, production and transportation operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. 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 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 at the present time 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

11

jurisdictions. We employ an environmental, health and safety 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.

Employees

As of December 31, 2006, we had 585 employees, including 193 who were employees of our drilling subsidiary. None of our employees is currently represented by a union for collective bargaining purposes.

Geographical Data

Forest operates in one industry segment. For information relating to our geographic operating segments, see Note 14 to the Consolidated Financial Statements of this Form 10-K.

Offices

Our principal office is located in leased space at 707 17th Street, Denver, Colorado 80202. We also lease field offices and subsidiary offices throughout the United States and Canada and in Cape Town, South Africa. Upon consummation of the proposed merger with Houston Exploration, we expect to establish an office in Houston, Texas.

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 and term loan facilities, we have granted the lenders a lien on a majority of 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 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.

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this Form 10-K. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definitions of those terms can be viewed on the SEC’s website at http://www.sec.gov/about/forms/regs-x.pdf.

Bbl.   One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.

Bcf.   Billion cubic feet of natural gas.

Bcfe.   Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Bbtu.   One billion British Thermal Units.

Btu.   A British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.

Condensate.   Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

12

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.

Exploitation.   Ordinarily considered to be a form of development within a known reservoir.

Exploratory well.   A well drilled to find and produce oil or gas reserves not classified as proved, 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 or the undertaking of other work obligations.

Field.   An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

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 and administrative expense, 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.

Lease operating expenses.   The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

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

MBbls.   Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf.   Thousand cubic feet of natural gas.

Mcfe.   Thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

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

MMcf.   Million cubic feet of natural gas.

MMcfe.   Million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

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.

13

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.

Reservoir.   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Standardized measure or present value of estimated future net revenues.   An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of U.S. federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

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 to receive a share of production.

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 Forest’s website, and available in print upon written request of any shareholder addressed to the Secretary of Forest, at 707 17th Street, Suite 3600, Denver, Colorado 80202, are Forest’s Corporate Governance Guidelines, the charters for the committees of our Board of Directors (including the charters of the Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee) and codes of ethics entitled “Code of Business Conduct and Ethics” and “Proper Business Practices Policy.”

In May 2006, we submitted to the New York Stock Exchange (“NYSE”) the certification of the Chief Executive Officer of Forest required by Section 303A.12 of the NYSE Listed Company Manual, relating to Forest’s compliance with the NYSE’s corporate governance listing standards with no qualifications. Also, we included the certifications of the Principal Executive Officer and Principal Financial Officer of Forest required by Section 302 of the Sarbanes-Oxley Act of 2002 and related rules, relating to the quality of Forest’s public disclosure, in this Form 10-K as Exhibits 31.1 and 31.2.

14

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. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” variations of such words and similar expressions identify forward-looking statements, and any statements regarding Forest’s future financial condition, results of operations and business, are also forward-looking statements. These forward-looking statements are based on our current expectations and assumptions about future events and are 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 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;

·       the amount, nature and timing of capital expenditures, including future development costs, and availability of capital resources to fund capital expenditures;

·       the amount, nature and timing of any synergies or other benefits expected to result from acquisitions, including the proposed merger with Houston Exploration;

·       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, most of which are difficult to predict and 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 drilling and production equipment 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, cash flow and access to capital, the 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 reservoir engineers. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

15

Factors that could cause actual results to differ materially from those contemplated by the forward-looking statements include, among others, the following factors related to the proposed merger with Houston Exploration:

·       the ability to consummate the merger;

·       difficulties and delays in obtaining regulatory approvals for the merger;

·       difficulties and delays in achieving synergies and cost savings from the merger; and

·       potential difficulties in meeting conditions set forth in the merger agreement.

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.

Item 1A.                Risk Factors.

The nature of the business activities conducted by Forest subject it to certain risks and hazards. The risks discussed below, any of which could materially and adversely affect our business, financial condition, cash flows, or results of operations, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

Risk Factors Relating to Forest

Oil and gas price declines adversely affect Forest’s financial results 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. Oil and gas prices are currently near historical highs and may fluctuate and decline significantly in the near future. 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, Russia, and South America; the price and quantity of oil and gas imports; or general economic conditions.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 53% of our estimated proved reserves as of December 31, 2006 were natural gas reserves, our financial results in 2007 are more sensitive to movements in natural gas prices. We have

16

announced plans to complete a merger with Houston Exploration and the vast majority of Houston Exploration’s estimated proved reserves are natural gas, therefore, our financial results will be even more sensitive to natural gas price fluctuations following the proposed merger. For all of these reasons, declines in oil and gas prices may have a material adverse effect on our financial condition and results of operations.

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 are favorable. We also continue to examine alternative sources of long-term capital such as 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, the value and performance of Forest, and the credit ratings assigned to Forest by independent ratings agencies. We will be unable to execute our operating strategy if we cannot obtain adequate capital.

Availability under our bank credit facilities 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. We expect that the terms of our proposed amended and restated credit facilities to be entered into in connection with the proposed merger with Houston Exploration will be substantially similar to Forest’s existing credit facilities. See “—Leverage materially affects 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 credit agreements and indentures governing our debt securities, our ability to fund our planned capital expenditures could be adversely affected. After utilizing our available sources of financing, we could be forced to issue additional debt or equity securities to fund such expenditures. We cannot assure you that additional debt or equity financing or cash generated by operations will be available to meet our capital requirements.

A curtailment of capital spending could adversely affect our ability to replace production and our future cash flow from operations and could result in a decline in our oil and gas reserves and production.

Estimates of oil and gas reserves are uncertain and inherently imprecise.   Estimating our proved reserves involves many uncertainties, including factors beyond our control. The estimates of proved reserves and related future net revenues described in this Form 10-K are based on various assumptions, which may ultimately prove inaccurate. 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. As a result of lower oil and gas “spot” prices in the future or downward future reserve revisions, we could incur writedowns of our United State and Canadian full cost pools under “ceiling test” limitations pursuant to full cost accounting. If we were to record writedowns, shareholders’ equity could be reduced significantly. See “Additional Risk Factors Relating to Forest if the Merger with Houston Exploration is Consummated—Forest will be more vulnerable to a ceiling test writedown following the merger with Houston Exploration” below.

17

In estimating future net revenues from proved reserves, future prices and costs are assumed to be fixed and a fixed discount factor is applied. Our revenues, profitability and cash flow could be materially less than our estimates if these assumptions and discount factor are incorrect.   The present value of future net revenues from our proved reserves is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the SEC net present value estimate. The timing and amount of development expenditures and the rate and timing of oil, natural gas, and natural gas liquids production will affect both the timing of future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. 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.

Lower oil and gas prices and other factors may cause us to record ceiling test 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%. 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.” Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown 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. The merger with Houston Exploration is expected to increase the risk of a ceiling test writedown. See “Additional Risk Factors Relating to Forest if the Merger with Houston Exploration is Consummated—Forest will be more vulnerable to a ceiling test writedown following the merger with Houston Exploration” below.

Leverage may materially affect our operations.   As of December 31, 2006, the principal amount of our consolidated long-term debt was approximately $1.2 billion, including approximately $107 million outstanding under the combined U.S. and Canadian bank credit facilities among Forest and its Canadian subsidiary and the various lenders that are parties to the facilities and $375 million outstanding under term loan facilities among Forest Alaska Operating LLC and the lenders that are parties to those facilities, which are nonrecourse to Forest and its non-Alaska subsidiaries. Our long-term debt represented 46% of our total capitalization at December 31, 2006. Further, we may incur additional debt in the future, including in connection with acquisitions and refinancings. In connection with the announcement of the proposed merger with Houston Exploration, we also announced our plans to enter into an amended and restated $1.4 billion credit facility which will be used to finance the cash component of the merger consideration, which is expected to total approximately $740 million. See “Risk Factors Relating to Forest if the Merger with Houston Exploration is Consummated” below.

The level of our debt has several important effects on our operations, including, among others:

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

18

·       credit rating agencies have changed, and may change in the future, 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 in turn impact the costs, terms, conditions, and availability of financing;

·       covenants contained in our existing and future credit and debt arrangements require us to meet financial tests that 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 is limited and any such financing may be burdened by increased costs or more restrictive covenants;

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

·       we are more vulnerable to adverse economic and industry conditions.

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, 2006, our estimated discounted asset retirement obligation liability recorded in the balance sheet was approximately $64.1 million, of which $16.9 million was for properties in the Cook Inlet of Alaska. Approximately $6.7 million of abandonment costs were settled in 2006 and $2.7 million of abandonment costs are anticipated to be settled in 2007, 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. Our reserves will decline as they are produced unless we are successful in our exploration and development activities or acquire new producing properties. Forest’s future natural gas and oil production is highly dependent upon its level of success in finding or acquiring additional reserves. 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 declines or 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 oil and gas drilling and production activities are subject to numerous operational and exploration risks.   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; shortages in supplies of drilling rigs and related equipment; shortages in labor; weather conditions; delays in the delivery of equipment; and failure to secure necessary regulatory approvals and permits. Further, 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 activities can result in dry wells and wells that are productive but do not produce sufficient net revenues after operating and other costs and thus may be unprofitable.

We may not be insured against all of the operating risks to which our businesses are exposed.   The exploration, development, and production of oil and natural gas and the drilling activities performed by

19

our drilling subsidiary involve risks. These operating risks include the risk of fire, explosions, blow-outs, pipe failure, damaged drilling and oil field equipment, 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. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above. Generally, pollution related environmental risks are not fully insurable. We cannot assure that our insurance will be fully adequate to cover these 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 19% of our 2006 consolidated production costs, and 22% of our 2006 consolidated oil and gas revenues, 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 oil and gas assets in other countries including Italy, Gabon and South Africa. Although there are no material operations in these countries, our operations in these countries 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 that have tested natural gas. While no proved reserves have been assigned to these properties as commercial sales contracts have not been established, and if we are unable to arrange for commercial use of these properties, we may not be able to recoup our investment and may not realize our anticipated financial and operating results from these properties. The South African national government has recently adopted legislation to revise the process pursuant to which it grants petroleum exploration and production licenses. Under the new regulations, we have applied to the government to convert one existing prospecting sublease into an exploration right. In addition, we are in the process of applying for a production right covering the geographic area of our other existing prospecting sublease. Because the regulations implementing legislation are not yet final, we cannot predict whether these applications, if granted, will meet our economic or operational requirements, in which event we may choose to relinquish these leases and lose our investment.

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. For example, in 2006, our hedging arrangements reduced the benefits we received from increases in oil and natural gas prices by approximately $67.7 million. 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. Also, 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.

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

20

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 9 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. Factors that affect our ability to acquire properties include, among others, availability of desirable acquisition targets, staff and resources to identify and evaluate properties, available funds, and internal standards for minimum projected return on investment. Higher recent commodity prices have increased both equipment, service and labor costs in the industry as well as the cost of properties available for acquisition and a large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources. In addition, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future. Many of these competitors have financial and other resources substantially greater than ours. We can give no assurance that we will be able to compete effectively in the future and that our financial condition and results of operations will not suffer as a result.

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 acquisition 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. When acquiring new properties, there are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, future production rates, and associated costs and potential liabilities with respect to prospective acquisition targets. Actual results from an acquisition may vary substantially from those assumed in the purchase analysis and acquired properties may not produce as expected, or there may be conditions that subject us to increased costs and liabilities including environmental liabilities.

We operate a drilling subsidiary and it involves many operating risks, any one of which could prevent us from realizing profits from the drilling subsidiary.   Forest seeks to increase its oil and gas reserves, production, and cash flow through exploratory and development drilling activities and conducting other production enhancement activities. In 2005, Forest formed a drilling subsidiary to hold drilling equipment and related assets that it acquired in a corporate transaction. The subsidiary performs services for Forest and its subsidiaries as well as third parties. Forest believes these new operations complement its business model and will lessen its exposure to the risks and delays associated with obtaining drilling equipment from third parties in an intensely competitive market. The drilling subsidiary is subject to risks, including shortages in labor and the risks associated with drilling oil and gas wells. These risks include: fires; explosions; blow-outs and surface cratering; pipe failures; casing collapses; natural disasters; and environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases. If any of these events occur, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, and environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of our operations.

Our oil and gas operations are subject to various environmental and other 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 discharge

21

of waste and other substances generated in connection with drilling and production 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. 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. The success and timing of drilling development activities on properties developed by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants, and selection of technology. 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 could have a material adverse effect on the realization of our targeted returns on capital 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. Also, our board of directors has adopted a shareholder rights plan. If activated, this 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. The provisions contained in our Bylaws and Certificate of Incorporation, alone or in combination with each other and with the rights plan, may discourage transactions involving actual or potential changes of control.

Additional Risk Factors Relating to Forest if the Merger with Houston Exploration is Consummated

The businesses of Forest and Houston Exploration, as well as other businesses that Forest may acquire after completion of the merger, may be difficult to integrate, disrupt Forest’s business, dilute shareholder value or divert management attention.   Risks with respect to the combination of Forest and Houston Exploration, as well as other recent and future acquisitions, include:

·       difficulties in the integration of the operations and personnel of the acquired company;

·       diversion of management’s attention away from other business concerns; and

·       the assumption of any undisclosed or other potential liabilities of the acquired company.

Forest will be more vulnerable to a ceiling test writedown following the merger with Houston Exploration.   As described above in the risk factor entitled, “Risk Factors Relating to Forest—Lower oil and gas and other factors prices may cause us to record ceiling test writedowns,” Forest uses the full cost method of accounting

22

and is subject to quarterly ceiling tests. After completion of the merger, Forest will add to net capitalized costs the cost to acquire Houston Exploration’s oil and gas properties. It will also add the estimated proved reserves associated with those properties. Forest expects that the net effect of these additions will be to reduce the difference between the ceiling limit and the net capitalized costs of its U.S. cost center. Based on oil and gas prices at December 31, 2006, on a stand-alone basis Forest had a ceiling limit in excess of the net capitalized costs in the U.S. cost center (the “Available Amount”) of approximately $535 million. Based on Forest’s current estimate of the cost to acquire Houston Exploration’s properties and the estimated proved reserves to be acquired, Forest’s Available Amount would have been approximately $100 million if the pending merger with Houston Exploration had occurred on December 31, 2006. The impact on the Available Amount indicates that Forest may be more likely to incur a writedown of its U.S. full cost pool immediately after the merger than it would have been immediately before the merger.

Forest will incur substantial transaction and merger-related costs in connection with the merger.   We expect to incur a number of non-recurring transaction and merger related costs (estimated to be in excess of $50 million) associated with completing the merger with Houston Exploration, combining the operations of the two companies and achieving desired synergies. These fees and costs will be substantial. Additional unanticipated costs may be incurred in the integration of the businesses of Forest and Houston Exploration. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses will offset the incremental transaction and merger-related costs over time, this net benefit may not be achieved in the near term, or at all.

Forest will have substantial debt after the effective time of the merger, which could have a material adverse effect on its financial health and limit its future operations.   Forest will have a significant amount of additional debt after the effective time of the merger. Approximately $740 million (based on the number of shares of Houston Exploration common stock outstanding on January 4, 2007) in expected cash consideration is expected to be paid with borrowings under Forest’s proposed amended and restated credit facilities. Forest’s substantial debt could have important consequences. In particular, it could:

·       increase its vulnerability to general adverse economic and industry conditions;

·       require it to dedicate a substantial portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of its cash flow to fund working capital, capital expenditures and other general corporate purposes;

·       place it at a competitive disadvantage compared to its competitors that have less debt; and

·       limit, along with the financial and other restrictive covenants of its indebtedness, among other things, its ability to borrow additional funds.

See, “Risk Factors Relating to Forest—Leverage may materially affect our operations” above.

Item 1B.               Unresolved Staff Comments.

None.

Item 2.                        Properties.

Information on Properties is contained in Item 1 of this Form 10-K.

23

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.

Houston Exploration and Forest are subject to an ongoing shareholder lawsuit, which could result in an injunction preventing the consummation of the merger or significant monetary damages. Houston Exploration’s directors and Forest are defendants in a shareholder lawsuit brought by the City of Monroe Employees’ Retirement System (the “Plaintiff”) on June 22, 2006 in State court in Houston, Texas. The Plaintiff asserts that the Houston Exploration directors breached their fiduciary duties by not pursuing a June 12, 2006 unsolicited proposal to purchase the outstanding shares of Houston Exploration common stock for $62 per share that was made by a Houston Exploration shareholder. The Plaintiff also asserts, on behalf of an uncertified class of Houston Exploration’s shareholders, that the Houston Exploration directors’ decision to enter into the merger agreement with Forest constituted a breach of fiduciary duties, because, the Plaintiff alleges, the merger consideration being offered by Forest is inadequate. The Plaintiff asserts that Forest aided and abetted the Houston Exploration directors’ alleged breach of fiduciary duties.

At the time of the filing of this Annual Report, this lawsuit is at an early stage and subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, based on the current status of the litigation, we cannot currently predict the manner and timing of the resolution of the lawsuit, the likelihood of the issuance of an injunction preventing the consummation of the merger or an estimate of a range of possible losses or any minimum loss that could result in the event of an adverse verdict in the lawsuit. Furthermore, although the combined company’s insurance policies following the merger should provide coverage for the claims against Houston Exploration’s directors, the policies may not be sufficient to cover all costs and liabilities incurred by those directors. The current claim in the lawsuit against Forest is not covered by insurance.

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, 2006.

24

Item 4A.                Executive Officers of Forest.

The following persons were serving as executive officers of Forest as of February 27, 2007.

(1)                 Officers 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.

25

PART II

Item 5.                        Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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 16, 2007, our Common Stock was held by 640 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 per share of the Common Stock on the New York Stock Exchange composite tape, as well as adjusted prices for Forest common stock that reflect the stock dividend paid by Forest on March 2, 2006. There were no cash dividends declared on the Common Stock in 2005 or 2006. On February 27, 2007, the closing price of Forest Common Stock was $32.14.

(1)                 On March 2, 2006, Forest completed the Spin-off by means of a special stock dividend paid to all shareholders of Forest Common Stock. The stock dividend consisted of 0.8093 shares of a wholly owned subsidiary of Forest for each outstanding share of Forest Common Stock, which immediately thereafter became the right to receive one share of Mariner for each whole share of such subsidiary in connection with the merger of MERI and such subsidiary. Mariner’s common stock commenced trading on March 3, 2006 at a price of $20.40. Based on the ratio of 0.8093 Mariner shares for each Forest share, the value of the stock dividend to Forest shareholders is deemed by Forest to be equal to $16.51, or the price of Mariner common stock on March 3, 2006 ($20.40) multiplied by 0.8093.

         The prices shown in the “As Adjusted” column above for the first quarter of 2005 through the first quarter of 2006 have been adjusted to reflect the stock dividend paid on March 2, 2006. The ratio used for this historical price adjustment is 0.6698. This represents the ratio of (x) $33.49, the per share value of Forest Common Stock immediately after the stock dividend, which was the opening price for Forest shares on March 3, 2006, to (y) $50.00, which represents the sum of $33.49 plus $16.51, the value of the stock dividend described above. That is $33.49 divided by $50.00 equals 0.6698. Prices from the second quarter of 2006 onward are identical in both columns.

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 restated certificate of incorporation and bylaws, (iii) Forest’s 8% Senior Notes due 2008, Forest’s 8% Senior Notes due 2011, and Forest’s 73¤4% Senior Notes due 2014, and (iv) Forest’s United States and Canadian bank credit facilities dated as of September 29, 2004, as amended. 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. Also, if the merger with Houston Exploration is completed, the indenture governing its senior subordinated notes will limit our ability to pay dividends. As noted above, on March 2, 2006 Forest distributed a special stock dividend; however, Forest has not paid cash dividends on its Common Stock during the past five years. The

26

future payment of cash 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 cash dividends.

On February 10, 2006, Forest declared a special stock dividend payable to holders of record of Forest Common Stock as of the close of business on February 21, 2006, in connection with the Spin-off that was completed on March 2, 2006. In October 2005, Forest amended its credit facilities to permit the Spin-off and the special stock dividend. See Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for more details concerning the Spin-off. 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.

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2001 (and the reinvestment of dividends thereafter) in each of Forest Common Stock, the S&P 500 Index, and the Dow Jones U.S. Exploration and Production Index. We believe that the Dow Jones U.S. Exploration and Production Index is meaningful because it is an independent, objective view of the performance of other similarly-sized energy companies.

The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

27

Item 6.                      Selected Financial 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, 2006. 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. On March 2, 2006, Forest completed the Spin-off of its offshore Gulf of Mexico operations. See “Spin-off of Offshore Gulf of Mexico Operations” under Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.