10-K 1 a2183054z10-k.htm FORM 10-K

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


FORM 10-K

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

For the fiscal year ended December 31, 2007

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)

State of incorporation: New York   I.R.S. Employer Identification No. 25-0484900
707 17th Street - Suite 3600 - Denver, Colorado   80202
(Address of Principal Executive Offices)   (Zip Code)

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

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

Title of Each Class

 

Name of Each Exchange on which Registered

Common Stock, Par Value $.10 Per Share   New York Stock Exchange

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 ý 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 ý

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

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

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

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company 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 ý

         The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 29, 2007, the last business day of the registrant's most recently completed second fiscal quarter, was $3,357,673,088 (based on the closing price of such stock on the New York Stock Exchange Composite Tape).

         There were 88,407,646 shares of the registrant's common stock, par value $.10 per share, outstanding as of February 15, 2008.

         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, 2007 are incorporated by reference into Part III of this Form 10-K.





TABLE OF CONTENTS

 
   
  Page No.
    PART I    
Item 1.   Business   1
Item 1A.   Risk Factors   17
Item 1B.   Unresolved Staff Comments   25
Item 2.   Properties   25
Item 3.   Legal Proceedings   25
Item 4.   Submission of Matters to a Vote of Security Holders   25
Item 4A.   Executive Officers of Forest   26
    PART II    
Item 5.   Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   28
Item 6.   Selected Financial Data   31
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   32
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk   51
Item 8.   Financial Statements and Supplementary Data   54
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   116
Item 9A.   Controls and Procedures   116
Item 9B.   Other Information   116
    PART III    
Item 10.   Directors, Executive Officers and Corporate Governance   118
Item 11.   Executive Compensation   118
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   118
Item 13.   Certain Relationships and Related Transactions, and Director Independence   118
Item 14.   Principal Accounting Fees and Services   119
    PART IV    
Item 15.   Exhibits and Financial Statement Schedules   119
    Signatures   125

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 currently conduct our operations in three geographical segments and five business units. Geographical segments include: the United States, Canada, and International. Business units include: Western, Eastern, Southern, Canada, and International. We conduct exploration and development activities in each of our geographical segments; however, substantially all of our estimated proved reserves and all of our producing properties are located in North America. Forest's total estimated proved reserves as of December 31, 2007 were approximately 2.1 Tcfe. At December 31, 2007, approximately 85% of our estimated proved oil and gas reserves were in the United States, approximately 12% were in Canada, and approximately 3% were in Italy. See Note 14 to the Consolidated Financial Statements for additional information about our geographical segments.

        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.

        Over the last several years, we have implemented a strategy directed at transforming Forest from a predominantly Gulf of Mexico oil and gas producer with frontier exploration emphasis to a North American onshore producer with numerous low risk opportunities for growth. As part of this transformation, we have made several key acquisitions and dispositions, including most recently the acquisition of The Houston Exploration Company ("Houston Exploration") in June 2007, the sale of our Alaska operations in August 2007, and the disposition of our offshore Gulf of Mexico properties in March 2006.

Acquisition of Houston Exploration

        On June 6, 2007, Forest completed the acquisition of Houston Exploration in a cash and stock transaction totaling approximately $1.5 billion and the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. Houston Exploration had operations in four producing regions within the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. At the time of the acquisition in June 2007, Forest estimated the Houston Exploration oil and gas reserves to be 653 Bcfe, of which 71% were classified as proved developed and the remaining amounts were classified as proved undeveloped. Pursuant to the terms and conditions of the agreement and plan of merger ("Merger Agreement"), Forest paid total merger consideration of $750 million in cash and issued approximately 24 million common shares, valued at $30.28 per share. The per share value of the Forest common shares issued was calculated as the average of Forest's closing share price for a five day period surrounding the announcement date of the acquisition on January 7, 2007. The cash component of the merger consideration was financed from a private placement of $750 million of 71/4% senior notes due 2019 and borrowings under our $1.0 billion second amended and restated credit facilities that were executed on June 6, 2007.

1


Sale of Alaska Assets

        On August 27, 2007, Forest sold all of its assets located in Alaska (the "Alaska Assets") to Pacific Energy Resources Ltd. ("PERL"). Forest estimated the proved oil and gas reserves associated with the Alaska Assets at closing to be 173 Bcfe. The total consideration received for the Alaska Assets included $400 million in cash, 10 million shares of PERL common stock (subject to certain restrictions), and a zero coupon senior subordinated note from PERL due 2014 in the principal amount at stated maturity of $60.8 million.

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 special 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 approximately 50.6 million 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. Forest estimated the proved oil and gas reserves associated with the Spin-off to be 313 Bcfe.

        The Spin-off was a tax-free transaction for federal income tax purposes. Prior to the Merger, as part of the Spin-off, MERI paid Forest approximately $176.1 million. The $176.1 million was drawn on a newly created bank credit facility established by MERI immediately prior to the Spin-off. This credit facility and the associated liability were included in the Spin-off. Subsequent to the closing, in 2006 Forest received additional net cash proceeds of $21.7 million from MERI for a total of $197.8 million. In accordance with the transaction agreements, Forest and MERI each submitted post-closing adjustments, from which Forest paid MERI a total of $5.8 million during 2007. Additional adjustments to the cash amount may occur during 2008 pending the resolution of certain accounting matters that are the subject of ongoing arbitration between Forest and MERI. The arbitration is currently expected to be concluded in the second half of 2008.

Business Strategy

        We adopted a new business strategy in 2003 that includes four key points: make strategic acquisitions, increase production organically, control costs, and remain financially flexible.

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 strategy in 2003, through 2007 we have incurred approximately $3.7 billion (including deferred tax gross ups of $.7 billion recorded in connection with business combinations) to acquire oil and gas assets including approximately 1.5 Tcfe of estimated proved reserves, over 1.5 million net acres, drilling rigs, and transportation infrastructure. In general, our acquisition program has focused on acquisitions of properties that have substantial development drilling opportunities and undeveloped acreage.

        During 2007, we made approximately $2.2 billion of oil and gas acquisitions (including approximately $559 million of deferred tax gross ups), including the acquisition of Houston Exploration in June 2007 as discussed above. The oil and gas properties of Houston Exploration included approximately 926,000 net acres, an estimated 653 Bcfe of estimated proved reserves, and production of 204 MMcfe per day. Of the 926,000 net acres, approximately 738,000 net acres were undeveloped.

        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

2



("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 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.

Organic Growth

        Our acquisition program has provided oil and gas properties conducive to low-risk, repeatable development and exploitation opportunities focused primarily in unconventional tight gas sand reservoirs. In 2008, Forest expects continued organic growth from its planned exploitation activities, including exploration and development drilling, workovers, stimulation treatments, enhanced oil recoveries, and recompletions.

Focus on Cost Control

        Maintaining capital spending discipline and a focus on cost control are keystones of Forest's business philosophy. A critical area of our cost control efforts is lease operating expenses. While in a period of rising costs in the oil and gas sector, we decreased our per-unit lease operating expenses from the level achieved in 2005. See "Lease Operating Expenses" and the accompanying table in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations." Lease operating expenses decreased 11% to $1.08 per Mcfe in 2007 compared to $1.21 per Mcfe in 2005.

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 exceed this range when conditions warrant using leverage to make strategic acquisitions. At December 31, 2007, for example, our debt-to-book capitalization ratio was 42%, which was reduced from 49% at mid-year 2007. Subsequent to the acquisition of Houston Exploration in June 2007, our debt-to-book capitalization ratio increased to 49% as a result of the issuance of 71/4% senior notes due 2019 and debt assumed in the acquisition. However, strategic sales in 2007, including the Alaska Assets and a sales lease back transaction of previously owned drilling equipment, reduced our debt-to-book capitalization ratio to 42% at December 31, 2007.

        We also employ a "free cash flow" business model where we expect each of our producing business units to generate cash flows from operations (before changes in working capital) equal to or in excess of the business unit's capital expenditures used in exploration and development activities. We believe this policy provides for sustainable and sensible growth while providing the opportunity to use leverage to capitalize on acquisition opportunities. Hedging is also an important part of our strategy to cushion our exposure to commodity price volatility. We have a board-approved policy related to commodity hedging activities. As of February 27, 2008, we have hedged, via swaps and collar instruments, approximately 75 Bcfe of our 2008 production.

        At December 31, 2007, we had approximately $10 million of cash on hand and $703 million available under our credit facilities.

3


Business Unit Activities

        The production volumes, estimated proved reserves, and exploration and development expenditures for our business units as of and for the year ended December 31, 2007 are summarized below. The acquisition of Houston Exploration on June 6, 2007 had a significant impact on the Western, Eastern, and Southern business units. Accordingly, the production volumes and the exploration and development expenditures reflected in the table below are not indicative of full-year results.

 
  Production Volumes
  Estimated Proved Reserves
  Exploration and Development Expenditures(1)
Business Unit

  Natural
Gas
(MMcf)

  Liquids
(MBbls)

  Total
(MMcfe)

  Total
(Bcfe)

  Total
(In Thousands)

Western   28,261   3,892   51,613   767.9   $ 278,701
Eastern   24,102   1,498   33,090   600.3     227,587
Southern   29,327   573   32,765   442.6     103,614
Canada   25,079   1,060   31,439   252.1     173,212
International(2)         56.3     15,853
Alaska(3)   1,273   922   6,805       4,601
   
 
 
 
 
Total   108,042   7,945   155,712   2,119.2   $ 803,568
   
 
 
 
 

(1)
Includes estimated discounted asset retirement obligations of $1.4 million.
(2)
All estimated proved reserves in the International business unit are in Italy.
(3)
On August 27, 2007, Forest sold its Alaska Assets to PERL.

Western

        The Western business unit's operations are located in the Texas Panhandle, West Texas, New Mexico, North Dakota, western Oklahoma, Colorado, Utah, and Wyoming. A significant area of activity for the Western business unit is in the Buffalo Wallow area located in Hemphill and Wheeler Counties in the Texas Panhandle. In 2007, we drilled 63 gross wells in the Buffalo Wallow area and plan to drill over 70 gross wells in 2008 targeting the Granite Wash and Atoka sands. As of December 31, 2007, we have identified approximately 700 non-proved potential locations in the Buffalo Wallow area, some of which have been approved for 20 acre downspacing. Current production from the Buffalo Wallow area represents approximately 35% of the Western business unit's total production. Capital expenditures in the Buffalo Wallow area are expected to comprise approximately $180 million of the business unit's 2008 capital expenditure budget of approximately $300 million.

        The Western business unit added the Rocky Mountain leasehold positions acquired from Houston Exploration in 2007 including the Niobrara area in eastern Colorado and the Uinta Basin in western Utah. The Niobrara area has a significant number of potential drilling locations on approximately 475,000 net acres. With attractive, low risk, low decline rates, and low development costs, we expect to further optimize the gas gathering infrastructure and drill approximately 25 wells in the Niobrara field in 2008 utilizing 3D seismic. Our leaseholds in the Uinta Basin also have a significant number of potential drilling locations on approximately 100,000 net acres with substantial gas resource in place. Although we decreased the level of activity in the Uinta Basin in 2007 to allocate capital on higher rate-of-return projects in East Texas and the Arkoma Basin, we plan to continue a consistent level of activity in 2008 as we believe field economics have improved since 2007.

Eastern

        The Eastern business unit's operations are located in East Texas, Arkansas, and Louisiana. The business unit's most significant area of focus has been in the Cotton Valley trend in East Texas since

4



the initial acquisition of 26,000 net acres in early 2006. Since the initial acquisition, we have drilled a total of 83 net wells targeting multi-pay zones including the upper and lower Cotton Valley Taylor sands and, together with the additional net acreage acquired from the Houston Exploration acquisition, our net acreage position has increased to over 60,000 net acres. In 2008, we expect to drill over 50 gross wells including 12 horizontal wells on large undeveloped acreage in blocks in the area. The Eastern business unit also added another core area in the Arkoma Basin in western Arkansas as a result of the Houston Exploration acquisition. The Arkoma Basin has over 39,000 net acres and provides for additional low risk, low cost repeatable drilling opportunities with downspacing potential. In addition to a significant amount of surface work that commenced in 2007 and will continue in 2008, we plan to drill over 100 gross wells in the Arkoma Basin in 2008. Current production from the East Texas and the Arkoma Basin properties represents approximately 75% of the Eastern business unit's total production. We expect capital expenditures in these areas to comprise approximately $195 million of the business unit's 2008 capital expenditure budget of approximately $285 million.

Southern

        The Southern business unit's operations are located in South Texas. The business unit's core operations include the Charco and Rincon fields acquired from Houston Exploration as well as the Katy and McAllen Ranch fields, which are legacy Forest properties. With the utilization of an extensive seismic database, we have identified a significant number of drilling locations in South Texas, and we plan to drill approximately 59 wells in the area in 2008. In 2008, we also plan to continue our extensional and infill drilling and recompletion program in the Katy field after achieving excellent results in 2007. Current production from the Rincon, Charco, Katy and McAllen Ranch fields represents approximately 65% of the Southern business unit's total production. Capital expenditures in the Rincon, Charco, Katy and McAllen Ranch fields are expected to comprise approximately $125 million of the business unit's 2008 capital expenditure budget of approximately $215 million.

Canada

        The Canada business unit's operations are located primarily in central Alberta. The Canada business unit's primary area of focus is in the Deep Basin in central Alberta. In 2007, a total of 45 gross wells were drilled utilizing new fracture stimulation techniques resulting in the best wells drilled in the area to date by Forest in terms of initial production rates. We plan to drill approximately 35 gross wells in the Deep Basin in 2008. With the business unit's Wild River field anticipated to reach full development of its Cretaceous zones on 160-acre spacing, we plan to direct further capital at Sundance/Ansell, a multi-zone, Cretaceous play similar to Wild River in 2008 and focus on further development of additional reservoirs in the Wild River field. The Canada business unit also expanded its acreage position in the Deep Basin in 2007 to approximately 73,000 gross acres, with extensive 3D seismic coverage. Current production from the Deep Basin represents approximately 50% of the Canada business unit's total production. Capital expenditures in the Deep Basin are expected to be approximately $80 million of the business unit's 2008 capital expenditure budget of approximately $140 million.

International

        The International business unit's operations are located in Italy and South Africa. In 2007, the International business unit drilled and completed two wells in Italy, which established estimated proved reserves of approximately 56 Bcfe as of December 31, 2007. Production from these wells is expected to come on line in 2009. In South Africa, the 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 sales contracts for the Ibhubesi field. See "Acreage" below, for further details.

5


Reserves

        The following table shows our estimated quantities of proved reserves as of December 31, 2007 and 2006. Substantially all estimated proved reserves are currently located in North America. See Note 16 to the Consolidated Financial Statements for additional information regarding estimated proved reserves.

 
  December 31,
 
  2007
  2006
Proved developed:        
  Natural gas (MMcf)   1,092,075   566,139
  Liquids (MBbls)   66,597   78,280
  Total (MMcfe)   1,491,657   1,035,819
Proved undeveloped:        
  Natural gas (MMcf)   460,301   211,900
  Liquids (MBbls)   27,879   34,584
  Total (MMcfe)   627,575   419,404
Total proved:        
  Natural gas (MMcf)   1,552,376   778,039
  Liquids (MBbls)   94,476   112,864
  Total (MMcfe)   2,119,232   1,455,223

        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 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 2007, we filed estimates of our oil and gas reserves as of December 31, 2006 with the DOE, which were consistent with the reserve data reported for the year ended December 31, 2006 in Note 16 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. We engage independent reserve engineers to audit a substantial portion of our reserves. 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 our year-end proved reserves, discounted at 10% per annum, for each country in which we own 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

6



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 reserve definition and cost and price parameters specified by the Securities and Exchange Commission ("SEC").

        For the year-end 2007, 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 81% of our reserves, as of December 31, 2007, 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.

Drilling Activities

        During 2007, we drilled a total of 495 gross wells, of which 52 were classified as exploration and 443 were classified as development. Our 2007 drilling program achieved a 96% success rate. The following table summarizes the number of wells drilled during 2007, 2006, and 2005, 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, 2007, we had 40 gross (28 net) wells in progress in the United States and 14 gross (8 net) wells in progress in Canada.

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  Gross
  Net
  Gross
  Net
  Gross
  Net
Development wells, completed as:                        
  Gas wells   392   210   210   52   232   32
  Oil wells   34   29   13   11   16   14
  Non-productive(1)   17   14   1   1   3   3
   
 
 
 
 
 
  Total   443   253   224   64   251   49
   
 
 
 
 
 
Exploratory wells, completed as:                        
  Gas wells   41   28   135   68   100   51
  Oil wells   6   2   15   9   31   27
  Non-productive(1)   5   3   8   5   10   5
   
 
 
 
 
 
  Total   52   33   158   82   141   83
   
 
 
 
 
 

(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. A well bore with multiple completions is counted as only one well. As of December 31, 2007, Forest owned interests in 458 gross wells containing multiple completions. The following table

7



summarizes our productive wells as of December 31, 2007, all of which are located in the United States, Canada, and Italy:

 
  United States
  Canada
  Italy
  Total
 
  Operated Wells
  Non-operated
Wells(1)

  Operated
Wells

  Non-operated
Wells

  Operated
Wells

  Non-operated
Wells

  Operated and Non-operated
Wells

 
  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net
Gas   2,674   2,560   3,316   176   375   295   251   70   2   2       6,618   3,103
Oil   2,020   1,987   604   56   246   221   95   20           2,965   2,284
   
 
 
 
 
 
 
 
 
 
 
 
 
 
Total   4,694   4,547   3,920   232   621   516   346   90   2   2       9,583   5,387
   
 
 
 
 
 
 
 
 
 
 
 
 
 

(1)
The large variance between gross and net non-operated wells is primarily a result of our ownership interest in approximately 2,589 gross gas wells in the San Juan Basin with an average working interest of approximately 5%.

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, 2007 and 2006. 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.

 
  December 31,
 
  2007
  2006
 
  Developed
Acreage

  Undeveloped
Acreage

  Developed
Acreage

  Undeveloped
Acreage

Location

  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net
United States:                                
  Western(1)   353,754   217,814   1,128,547   789,494   262,461   154,267   207,190   103,820
  Eastern(1)   172,633   113,557   282,298   139,101   115,554   64,034   229,797   118,497
  Southern(1)   192,752   135,852   73,843   34,208   68,921   38,351   22,685   5,755
  Alaska(2)           52,242   32,155   1,038,532   1,012,637
   
 
 
 
 
 
 
 
    719,139   467,223   1,484,688   962,803   499,178   288,807   1,498,204   1,240,709

Canada

 

286,016

 

157,737

 

852,704

 

375,398

 

267,157

 

151,645

 

1,082,504

 

581,746

International:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  South Africa       2,771,695   1,474,542       2,771,695   1,474,542
  Gabon       2,409,276   1,204,638       2,409,276   1,204,638
  Italy   2,500   2,250   288,543   287,911       654,896   654,014
   
 
 
 
 
 
 
 
    2,500   2,250   5,469,514   2,967,091       5,835,867   3,333,194
   
 
 
 
 
 
 
 

Total

 

1,007,655

 

627,210

 

7,806,906

 

4,305,292

 

766,335

 

440,452

 

8,416,575

 

5,155,649
   
 
 
 
 
 
 
 

(1)
Changes in acreage positions for the Western, Eastern, and Southern business units from 2006 are primarily the result of the Houston Exploration acquisition in 2007, which included 1,279,883 gross acres and 926,047 net acres. 2006 acreage amounts have been reclassified among U.S. locations to conform with the 2007 business unit structure.
(2)
The Alaska Assets were sold to PERL in August 2007.

        At December 31, 2007, approximately 13% and 7% of our net undeveloped acreage in the United States and Canada was held under leases that have terms that will expire in 2008 and 2009, respectively, if not extended by exploration or production activities. In addition, approximately 170,000 net undeveloped acres in the Niobrara area in eastern Colorado are scheduled to expire in 2008 but are held under leases

8


that may be extended for an additional five years. 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 implemented new legislation in 2004 that revised the regulations and 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 and have applied for a production right covering the geographic area of our other existing prospecting sublease. The government has not taken final action on these applications. Because the regulations implementing the new legislation are not final and the potential work obligations that could be imposed pursuant to any new rights, when and if they are granted, are still uncertain, we cannot predict whether these rights will meet our economic or operational requirements. If the rights do not meet our internal requirements, we may choose to relinquish these leases. See "Our International operations may be adversely affected by currency fluctuations and economic and political developments" in Part I, Item 1A—"Risk Factors", for further details.

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, 2007, 2006, and 2005.

 
  United States
  Canada
  Total Company
 
 
  2007
  2006
  2005
  2007
  2006
  2005
  2007
  2006
  2005
 
Natural Gas:                                        
  Sales price received (per Mcf)   $ 5.95   6.21   7.53   5.29   5.07   6.70   5.79   5.83   7.38  
  Effects of energy swaps and collars (per Mcf)(1)       (.37 ) (1.24 )         (.25 ) (1.02 )
   
 
 
 
 
 
 
 
 
 
  Average sales price (per Mcf)(1)   $ 5.95   5.84   6.29   5.29   5.07   6.70   5.79   5.58   6.36  
  Natural gas sales volumes (MMcf)     82,963   48,674   82,912   25,079   24,350   18,921   108,042   73,024   101,833  

Liquids:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Oil and Condensate:                                        
  Sales price received (per Bbl)   $ 67.91   62.18   52.78   58.05   50.89   41.92   66.44   60.79   51.67  
  Effects of energy swaps and collars (per Bbl)(1)       (4.94 ) (11.22 )         (4.34 ) (10.07 )
   
 
 
 
 
 
 
 
 
 
  Average sales price (per Bbl)(1)   $ 67.91   57.24   41.56   58.05   50.89   41.92   66.44   56.45   41.60  
  Natural gas liquids:                                        
  Average sales price (per Bbl)   $ 39.32   32.02   29.61   43.54   41.40   36.15   39.75   33.85   30.76  
  Total liquids:                                        
  Average sales price (per Bbl)(1)   $ 58.02   51.22   39.12   54.40   47.55   40.04   57.54   50.70   39.23  
  Liquids sales volumes (MBbls)     6,885   6,887   9,316   1,060   1,139   1,252   7,945   8,026   10,568  

Average sales price (per Mcfe)(1)

 

$

7.18

 

7.08

 

6.38

 

6.05

 

5.69

 

6.69

 

6.96

 

6.72

 

6.43

 

Total sales volumes (MMcfe)

 

 

124,273

 

89,996

 

138,808

 

31,439

 

31,184

 

26,433

 

155,712

 

121,180

 

165,241

 

Production costs (per Mcfe):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  Lease operating expenses   $ 1.09   1.41   1.30   1.00   .91   .71   1.08   1.28   1.21  
  Production and property taxes     .42   .40   .29   .11   .10   .11   .35   .32   .26  
  Transportation and processing costs     .08   .13   .10   .33   .32   .22   .13   .18   .12  
Total production costs (per Mcfe)   $ 1.59   1.94   1.69   1.44   1.32   1.04   1.56   1.78   1.58  

(1)
Include the effects of hedging under cash flow hedge accounting in 2006 and 2005. 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, among other things, the credit-worthiness of potential purchasers and concentrations of credit risk. We believe that the loss of one or more of our current oil and gas purchasers would not have a material adverse effect on our ability to sell our

9



production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. In 2007, there were no purchasers who exceeded 10% of our total 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 contracts. See Note 9 to the Consolidated Financial Statements 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 than we have. 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

10



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 Minerals Management Service, 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 Federal Energy Regulatory Commission ("FERC"), and the courts. We cannot predict when or whether any such proposals may become effective. No material portion of Forest's business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Canada

        The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. Federal authorities do not regulate the price of oil and gas in export trade. Legislation exists, however, that regulates the quantities of oil and natural gas which may be removed from the provinces and exported from Canada 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.

        The majority of our Canadian operations are located in Alberta, Canada, and, in October 2007, the Alberta Government announced a new oil and gas royalty framework to take effect in January 2009. The new framework establishes new royalties for conventional oil, natural gas, and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects.

        Under the new framework, the formula for conventional oil and natural gas royalties will be set by a sliding rate formula, dependant on the market price and production volumes. Royalty rates for conventional oil will range from 0% to 50%. New natural gas royalty rates will range from 5% to 50%. Under the current royalty regime, royalty rates range from 10% to 35% for conventional oil and from 5% to 35% for natural gas.

        The implementation of the new framework is subject to certain risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation, and development of proprietary software to support the calculation and collection of royalties. In addition, certain proposed changes contemplate further public and/or industry consultation. Accordingly, there may be modifications introduced to the new framework prior to its implementation on January 1, 2009. If the new framework is implemented in the same form as announced, the rate caps will be raised for conventional oil from $30 to $120 per barrel. The rate caps for natural gas will be raised from $3.90 to $17.50 per MMBtu. The tiers in conventional oil and natural gas that distinguish 'vintages' based on discovery date will be eliminated. Several special royalty programs for

11



conventional oil and natural gas will also be extinguished, except for the Otherwise Flared Solution Gas Royalty Waiver Program and Deep Gas Drilling Program, both of which will be amended. The royalties for natural gas liquids will be set at 40% for pentanes, from the previous 22% to 50% for old tiers and 22% to 35% for new. The new royalties for butanes and propane will be 30%, from the current 15% to 30%. The Alberta government will extinguish the option to use the Corporate Average Price to determine natural gas royalties in lieu of a single reference price. If adopted in its current form, we expect that our royalty payments on our Canadian oil and gas sales will increase.

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 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, 2007, we had 728 employees. None of our employees is currently represented by a union for collective bargaining purposes.

12


Geographical Data

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

Offices

        Our corporate office is located in leased space at 707 17th Street, Denver, Colorado 80202. We maintain offices in Houston, Texas and Calgary, Alberta, Canada and also lease or own field offices in the areas in which we conduct operations.

Title to Properties

        Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Under the terms of our bank credit facilities, 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.

        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.

        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.

13


        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.

        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.

14


        Proved reserves.    Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years 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 for recovery to occur.

        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 estimation date and held constant for the life of the reserves.

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

        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 each of 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 for our directors and employees entitled "Code of Business Conduct and Ethics" and "Proper Business Practices Policy," respectively.

        In May 2007, 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 have 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.

15


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" included in this Form 10-K.

        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;

    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 operations outside the United States 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.

16


        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.

        Our business activities are subject to certain risks and hazards, including the risks discussed below. If any of these events should occur, it could materially and adversely affect our business, financial condition, cash flows, or results of operations. Further, these risks 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.

        Oil and natural gas prices fluctuate due to a number of factors outside of our control, and declining prices will adversely affect our financial condition and results of operations.    Our results of operations and future rate of growth depend upon the prices that we receive for our oil and natural gas. We sell most of our oil and gas at current prices rather than through fixed-price contracts. Historically, the markets for oil and natural gas have been volatile and are likely to remain volatile in the future. Oil and gas prices are currently at or near historical highs, and they may decline in the future. The prices we receive depend upon factors beyond our control, including among others:

    domestic and foreign supply, consumer demand for oil and gas, and market expectations regarding supply and demand;

    weather conditions;

    political instability and armed conflicts in oil-producing and gas-producing regions;

    actions by the Organization of Petroleum Exporting Countries ("OPEC");

    domestic and worldwide economic conditions;

    the price and availability of foreign exports and the availability of alternate fuels; and

    governmental regulations and taxes.

        Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Approximately 73% of our estimated proved reserves at December 31, 2007 was natural gas, and, as a result, our financial results in 2008 will be more sensitive to fluctuations in natural gas prices.

        To the extent we have not hedged our production, a significant or extended decline in the prices of oil and gas below current levels will negatively impact:

    our revenues, cash flows, profitability, and earnings;

    our ability to make capital expenditures;

    our ability to replace our production and our future rate of growth;

    our ability to meet our financial obligations;

    our ability to raise capital or borrow money and our cost of such capital;

17


    the amount that we are allowed to borrow under our credit facilities; and

    the amount of oil and natural gas that we can produce economically.

        We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.    We incur, and will continue to incur, substantial capital expenditures for the acquisition, development, and exploration of our oil and natural gas reserves. In 2007, 2006, and 2005, we incurred approximately $3.0 billion, $943 million, and $854 million on capital expenditures, respectively, including approximately $2.2 billion, $316 million, and $314 million on property acquisitions. Our exploration and development expenditures budget for 2008 is approximately $900 million to $1 billion. We intend to finance our ongoing capital expenditures primarily through cash flow from operations and our bank credit facilities, and any exceptional expenditures with public or private equity and debt offerings.

        Our ability to access these sources of capital will depend upon a number of factors, some of which are outside our control. These factors include:

    oil and natural gas prices;

    the value and performance of Forest debt and equity securities;

    the credit ratings assigned to Forest by independent rating agencies; and

    general economic and financial market conditions.

        For example, oil and natural gas prices are currently at or near historic highs, and a significant decline in oil and natural gas prices would reduce our cash flow and could affect our access to the capital markets. Further, our access to funds under our credit facilities is based on a global borrowing base, which is based on our estimated proved reserves, and is redetermined semi-annually by the lenders and may be redetermined at other times during the year at the option of Forest or the lenders. The global borrowing base may be reduced if oil and natural gas prices decline, or if we have downward revisions in estimates of our proved reserves, which may adversely affect our planned capital expenditures.

        We believe that our available cash, cash provided by operating activities, and funds available under our bank credit facilities will be sufficient to fund our operating, interest, and general and administrative expenses, our capital expenditure budget, and our short-term contractual obligations, including the 8% senior notes that will come due on June 15, 2008, at current levels for the foreseeable future. If revenues decrease, however, and we are unable to obtain additional debt or equity financing or alternative sources of funds, we may have to reduce our capital expenditures and may lack the capital necessary to replace our reserves or maintain our production at current levels.

        We have substantial indebtedness and may incur more debt in the future, and our leverage may materially affect our operations and financial condition.    We have incurred substantial debt. At December 31, 2007, the principal amount of our outstanding consolidated debt was approximately $1.7 billion, including $294 million outstanding under our combined U.S. and Canadian credit facilities. Our outstanding consolidated debt represented approximately 42% of our total capitalization at December 31, 2007. Further, we may incur more debt in the future, including in connection with acquisitions and refinancings. The level of our debt has several important effects on our business and operations; among other things, it may:

    require us to use a significant portion of our cash flow to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general purposes;

    increase our costs as our access to the capital markets and our cost of borrowing is predicated on the credit ratings assigned by third party rating agencies, which have in the past and may in

18


      the future downgrade their ratings of our debt and other obligations due to changes in market conditions, our debt level or our financial condition;

    limit our access to the capital markets, increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more restrictive covenants;

    impact our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;

    place us at a disadvantage compared to similar companies in our industry that have less debt; and

    make us more vulnerable to economic downturns and adverse developments in our business.

        Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, domestic and foreign economic conditions, regulatory, and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets, or sell shares of our stock on terms that we do not find attractive, if it can be done at all. Further, our failure to comply with the financial and other restrictive covenants relating to our credit facilities and the indentures pertaining to our outstanding senior notes could result in a default under these agreements, which could adversely affect our business, financial condition, and results of operations.

        For example, of the principal amount of outstanding consolidated debt at December 31, 2007, $265 million will come due in June 2008. Our ability to refinance this debt will depend on our cash flow and our borrowing base and ability to access funds under our credit facility. If we do not have sufficient funds available, we may need to access the capital markets. Over the recent months, the capital markets have limited the availability of funds due to distressed conditions in the sub-prime securities market and other factors. We can not predict whether we will need to access the capital markets to refinance any portion of our debt obligations or whether the market conditions existing at such time will allow us to obtain the necessary funds.

        Our use of hedging transactions could result in financial losses or reduce our income.    To reduce our exposure to fluctuations in oil and natural gas prices, we have and expect in the future to enter into derivative instruments (or, hedging agreements) for a portion of our oil and natural gas production. Our commodity hedging agreements are limited in duration, usually for periods of one year or less; however, in conjunction with acquisitions, we sometimes enter into or acquire hedges for longer periods. As of February 27, 2008, we had hedged, via commodity swaps and collar instruments, approximately 75 Bcfe of our 2008 production. Our hedging transactions expose us to certain risks and financial losses, including, among others:

    we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;

    we may hedge too much or too little production depending on how oil and natural gas prices fluctuate in the future;

    there is a change to the expected differential between the underlying price and the actual price received; and

    a counterparty to a hedging arrangement may default on its obligations to Forest.

        For further information concerning our commodity price hedging transactions and information concerning prices, market conditions, and our swap and collar hedging agreements, see Part II,

19



Item 7A—"Qualitative and Quantitative Disclosures about Market Risk—Commodity Price Risk" of this Form 10-K, and Note 9 to the Consolidated Financial Statements.

        Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.    The proved oil and gas reserve information and the related future net revenues information included in this Form 10-K represent only estimates, which are prepared by our internal staff of engineers. Estimating quantities of proved oil and natural gas reserves is a subjective, complex process and depends on a number of variable factors and assumptions. To prepare estimates of economically recoverable oil and natural gas reserves and future net cash flows:

    we analyze historical production from the area and compare it to production rates from other producing areas;

    we analyze available technical data, including geological, geophysical, production, and engineering data, and the extent, quality, and reliability of this data can vary; and

    we must make various economic assumptions, including assumptions about prices, production costs, severance and excise taxes, capital expenditures, and workover and remedial costs.

        Ultimately, actual production, revenues, and expenditures relating to our reserves will vary from our estimates. Any significant inaccuracies in our assumptions or changes in operating conditions could cause the estimated quantities and net present value of the reserves shown in this Form 10-K to be different from our estimates.

        You should not assume that any present value of future net cash flows from our producing reserves shown in this Form 10-K is the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations and, or taxes. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

        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. In addition, our ceiling test cushion is subject to fluctuation as a result of our corporate development activity, which is difficult to fully assess prior to completion.

20


        Our failure to replace our reserves could result in a material decline in our reserves and could adversely affect our financial condition.    In general, our proved reserves decline when oil and natural gas is produced, unless we are able to conduct successful exploitation, exploration, and development activities, or acquire additional properties containing proved reserves, or both. Our future performance, therefore, is highly dependent upon our ability to find, develop and, or acquire additional reserves. Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

        Drilling oil and natural gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.    Drilling oil and natural gas wells involves numerous risks, including the risk that we may not encounter commercially productive oil or natural gas reservoirs. The presence of unanticipated pressures or irregularities in formations, miscalculations, or accidents may cause our drilling activities to be unsuccessful and result in significantly higher than expected costs and, or the total loss of our investment. Further, the cost of drilling, completing, and operating wells is often uncertain. Our drilling operations may be shortened, delayed, curtailed, or canceled as a result of a variety of factors, many of which are beyond our control, including:

    unexpected drilling conditions;

    geological irregularities or pressure in formations;

    equipment failures or accidents;

    costs of, or shortages or delays in the availability of, drilling rigs and related equipment;

    shortages in labor;

    adverse weather conditions;

    fires, explosions, blow-outs, or surface cratering; and

    restricted access to land necessary for drilling or laying pipelines.

        Forest has a drilling subsidiary that provides services to Forest and third parties. The operations of our drilling subsidiary are subject to various factors outside of our control, including the factors described above, and the risks associated with conducting drilling activities, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases, any of which could result in substantial losses, injuries or loss of life, environmental damage and clean-up responsibilities, and the suspension of our operations.

        We cannot assure you that any new wells we drill will be productive or that we will recover all or any portion of our investment.

        The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.    The marketability of our production depends in part upon the availability, proximity, and capacity of pipelines, natural gas gathering systems, and processing facilities. Any significant change in market factors affecting these infrastructure facilities, as well as delays in the construction of new infrastructure facilities, could harm our business. We deliver the majority of our oil and natural gas through gathering facilities that we do not own. As a result, we are subject to the risk that these facilities may be temporarily unavailable due to mechanical reasons or market conditions, or may not be available to us in the future. We have formed a natural gas gathering subsidiary to hold pipeline and related equipment, which currently operates solely within the State of Texas. The subsidiary transports natural gas produced by Forest as well as third parties.

21


        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 activities performed by our drilling subsidiary and gas gathering 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 do not insure against business interruption. We cannot assure that our insurance will be fully adequate to cover other 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 currently have oil and gas properties and operations in Canada, Italy, Gabon, and South Africa. As a result, we are exposed to the risks of international operations, including political and economic developments, royalty and tax increases, changes in laws or policies affecting our exploration and development activities, and currency exchange risks, as well as changes in the policies of the United States affecting trade, taxation, and investment in other countries.

        We have significant operations in Canada. In 2007, the revenues and expenses of such operations represented approximately 18% of our consolidated oil and gas revenues and 19% of our consolidated production costs. The revenues and expenses of these operations are denominated in Canadian dollars. As a result, the profitability of our Canadian operations is subject to the risk of fluctuation in the exchange rates between the U.S. dollar and Canadian dollar. In addition, our Canadian operations may be adversely affected by recent regulatory developments. The majority of our Canadian operations are located in Alberta, Canada, and in October 2007, the Alberta Government announced a new oil and gas royalty framework to take effect in January 2009. The new framework establishes new royalties for conventional oil, natural gas, and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the new framework, the formula for conventional oil and natural gas royalties will be set by a sliding rate formula, dependent on the market price and production volumes. Royalty rates for conventional oil will range from 0% to 50%. New natural gas royalty rates will range from 5% to 50%. Under the current royalty regime, royalty rates range from 10% to 35% for conventional oil and from 5% to 35% for natural gas.

        The implementation of the new royalty framework in Canada is subject to risks and uncertainties. The significant changes to the royalty regime require new legislation, changes to existing legislation and regulation, and development of proprietary software to support the calculation and collection of royalties. In addition, certain proposed changes contemplate further public and/or industry consultation. Accordingly, there may be modifications introduced to the new framework prior to its January 1, 2009 implementation. If the new framework is implemented in the same form as announced, the rate caps will be raised for conventional oil from $30 to $120 per barrel. The rate caps for natural gas will be raised from $3.90 to $17.50 per MMBtu. The tiers in conventional oil and natural gas that distinguish 'vintages' based on discovery date will be eliminated. Several special royalty programs for conventional oil and natural gas will also be extinguished, except for the Otherwise Flared Solution Gas Royalty Waiver Program and Deep Gas Drilling Program, both of which will be amended. The royalties for natural gas liquids will be set at 40% for pentanes, from the previous 22% to 50% for old tiers and 22% to 35% for new. The new royalties for butanes and propane will be 30%, from the current 15% to 30%. The Alberta government will extinguish the option to use the Corporate Average Price to

22



determine natural gas royalties in lieu of a single reference price. If adopted in its current form, we expect that our royalty payments on our Canadian oil and gas sales will increase.

        Although we do not have material operations in Italy, Gabon, and South Africa, our ongoing operations may be adversely affected by political, economic, and regulatory developments, changes in the local royalty and tax regimes, and currency fluctuations. In Italy, we have increased the level of our drilling and related exploration and development activities over the last several years. In 2007, we successfully completed two wells in Italy and are currently planning to construct pipelines and facilities to deliver the natural gas. During 2007, we assigned estimated proved reserves to these properties and expect to bring these wells on production in the first half of 2009.

        In South Africa, we have an interest in offshore properties that have tested natural gas, although we have not assigned any proved reserves to these properties as we have not yet established commercial sales contracts. 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. In 2004, the South African government implemented new legislation that revises the regulations and 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 and have applied for a production right covering the geographic area of our other existing prospecting sublease. The government has not taken final action on these applications. We cannot predict whether these applications will be granted. Further, because not all of the regulations implementing the new legislation are final and the potential work obligations that may be imposed pursuant to the rights, when and if they are granted, are still uncertain, we cannot predict whether these rights will meet our economic or operational requirements. If the rights do not meet our internal requirements, we may choose to relinquish these leases and lose our investment, which totals approximately $50 million.

        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 than we have. 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 depends 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;

    our ability to reasonably estimate or assess the recoverable volumes of reserves;

    rates of future production and future net revenues attainable from reserves;

23


    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.

        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 regulations, Canadian federal and provincial governmental laws and regulations, and local and federal regulations in Italy. These regulations may be changed in response to economic or political conditions. Matters subject to these governmental regulations include permits for discharge 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 our operations, the spacing of wells, and unitization and pooling of properties, and taxation. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions that could delay, limit or prohibit certain of our operations. 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. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive position, or financial condition. The laws in the United States, Canada, and Italy regulate, among other things, the 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 may not be able to recover some or any of these costs from insurance.

        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 or production activities on properties operated 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 Bylaws 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

24



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 shareholder rights plan, may discourage transactions involving actual or potential changes of control.

Item 1B.    Unresolved Staff Comments.

        As of December 31, 2007, we did not have any SEC staff comments that have been unresolved for more than 180 days.

Item 2.    Properties.

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

Item 3.    Legal Proceedings.

        We are a party to various lawsuits, claims, and proceedings in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, 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.

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, 2007.

25


Item 4A.    Executive Officers of Forest.

        The following persons were serving as executive officers of Forest as of February 27, 2008.

Name

  Age
  Years with Forest
  Office(1)
H. Craig Clark   51   7   President and Chief Executive Officer, and a member of the Board of Directors since July 2003. Mr. Clark joined Forest in September 2001 and served as President and Chief Operating Officer through July 2003. Mr. Clark was employed by Apache Corporation, an oil and gas exploration and production company, from 1989 to 2001, where he served in various management positions including Executive Vice President—U.S. Operations and Chairman and Chief Executive Officer of Pro Energy, an affiliate of Apache.
David H. Keyte   51   20   Executive Vice President and Chief Financial Officer since November 1997. Mr. Keyte served as our Vice President and Chief Financial Officer from December 1995 to November 1997 and our Vice President and Chief Accounting Officer from December 1993 until December 1995.
J.C. Ridens   52   4   Executive Vice President and Chief Operating Officer since November 2007. Since joining Forest in April 2004, Mr. Ridens has served as Senior Vice President for the Gulf Region, the Southern Region and most recently the Western Region. From 2001 to 2004, Mr. Ridens was employed by Cordillera Energy Partners, LLC, as Vice President of Operations and Exploitation. From 1996 to 2001, he served in various capacities at Apache Corporation.
Cecil N. Colwell   57   19   Senior Vice President, Worldwide Drilling since May 2004. Between 2000 and May 2004, Mr. Colwell served as our Vice President, Drilling, and from 1988 to 2000 he served as our Drilling Manager, Gulf Coast.
Leonard C. Gurule   51   5   Senior Vice President since September 2003. From 1987 to 2000, he served in various capacities at Atlantic Richfield Co. Before joining Forest Mr. Gurule served on the boards of several local community and non-profit organizations and managed his own investment portfolio.
Cyrus D. Marter IV   44   6   Senior Vice President, General Counsel and Secretary since November 2007. Mr. Marter served as Vice President, General Counsel and Secretary from January 2005 to November 2007, as Associate General Counsel from October 2004 to January 2005, and as Senior Counsel from June 2002 until October 2004. Prior to joining Forest, Mr. Marter was a partner of the law firm of Susman Godfrey L.L.P. in Houston, Texas.
Glen J. Mizenko   45   7   Senior Vice President, Business Development and Engineering since May 2007. Mr. Mizenko joined Forest in January 2001 as Manager Corporate Development and New Ventures. In October 2003, he was promoted to the position of Director, Business Development. In May 2005, he was promoted to Vice President, Business Development. Prior to joining Forest, Mr. Mizenko held various positions in reservoir engineering, reserves reporting, development planning, and operations management with Shell Oil, Benton Oil & Gas, and British Borneo Oil and Gas PLC.
Mark E. Bush   48   10   Vice President, Eastern Region since April 2007. Mr. Bush joined Forest in June 1997 as Production Engineer in the Gulf of Mexico Region and was subsequently promoted to Offshore Production Engineering Manager and Production Engineering Manager, both in the Gulf Coast Region and its successor, the Eastern Region. Prior to joining Forest Oil, he worked for Oryx Energy Company (formerly Sun E&P) in various production engineering assignments in the Gulf of Mexico and South Texas.
Stephen T. Harpham   46   6   Vice President, Western Region since November 2007. Mr. Harpham joined Forest in January 2002 and served as a Reservoir Engineer and subsequently Reservoir Engineering Manager. Prior to joining Forest, Mr. Harpham was a Technical Advisor with Ensign Oil & Gas Inc.
Ronald C. Nutt   50   *   Vice President, Southern Region since July 2007. Prior to joining Forest, from March 2007 to July 2007, Mr. Nutt worked for Constellation Energy Group as an Engineer, and from January 2003 to March 2007 at Scotia Waterous as Vice President, Engineering.

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Victor A. Wind   34   3   Corporate Controller. Mr. Wind joined Forest in January 2005. Mr. Wind was previously employed by Evergreen Resources, Inc. from July 2001 to December 2004. He served in various management positions during this period, including Director of Financial Reporting and Controller. From 1997 to 2001, he served in various capacities at BDO Seidman, LLP.

(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.

(*)
Denotes less than one year of service.

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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 15, 2008, our Common Stock was held by 1,119 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 2006 or 2007. On February 27, 2008, the closing price of Forest Common Stock was $49.54.

 
   
  Common Stock
  Common Stock (As Adjusted)(1)
 
   
  High
  Low
  High
  Low
2006   First Quarter   $ 52.99   32.51   37.82   30.80
    Second Quarter     39.75   28.00   39.75   28.00
    Third Quarter     35.28   29.06   35.28   29.06
    Fourth Quarter     36.17   29.13   36.17   29.13

2007

 

First Quarter

 

$

34.25

 

28.84

 

34.25

 

28.84
    Second Quarter     45.05   33.26   45.05   33.26
    Third Quarter     44.72   37.43   44.72   37.43
    Fourth Quarter     52.25   42.78   52.25   42.78

(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 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) the indentures concerning Forest's 8% senior notes due 2008, Forest's 8% senior notes due 2011, Forest's 73/4% senior notes due 2014, and Forest's 71/4% senior notes due 2019, and (iv) Forest's United States and Canadian bank credit facilities dated as of June 6, 2007. 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. As noted above, on March 2, 2006, Forest distributed a

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special stock dividend; however, Forest has not paid cash dividends on its Common Stock during the past five years. The 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. 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."

Issuer Purchases of Equity Securities

        The table below sets forth information regarding repurchases of our Common Stock during the 3-month fiscal quarter and year ended December 31, 2007. The shares repurchased represent shares of our Common Stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of shares of restricted stock. Forest does not consider this a share buyback program.

Period

  Total # of
Shares Purchased

  Average Price
Per Share

  Total # of Shares (or
units) Purchased as
Part of Publicly
Announced Plans or
Programs

  Maximum # (or
Approximate Dollar
Value) of Shares that
May yet be Purchased
Under the Plans or
Programs

 
January 2007     $      
February 2007   8,258     33.51      
March 2007   38     31.53      
April 2007            
May 2007   75     40.86      
June 2007   1,400     43.78      
July 2007            
August 2007            
September 2007   38     40.71      
October 2007            
November 2007            
December 2007   19,760     48.83      

Fourth Quarter Total

 

19,760

 

 

48.83

 


 


 
2007 Total   29,569     44.26    

29


Stock Performance Graph

        The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2002 (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.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Forest Oil Corporation, The S&P 500 Index
And The Dow Jones US Exploration & Production Index

Performance Graph

*$100 Invested on 12/31/02 in stock or index-including reinvestment of dividends. Fiscal year ending December 31.

        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.

30


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, 2007. 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 June 6, 2007, Forest completed the acquisition of Houston Exploration. On August 27, 2007, we sold all of our Alaska assets. On March 2, 2006, Forest completed the spin-off of its offshore Gulf of Mexico operations. See "Acquisition of Houston Exploration," "Sale of Alaska Assets," and "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.

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
  2004
  2003
 
 
  (In Thousands, Except Per Share Amounts,
Volumes, and Prices)

 
FINANCIAL DATA                        
Revenues   $ 1,083,892   819,992   1,072,045   912,898   657,178  
Earnings from continuing operations     169,306   166,080   151,568   123,126   90,228  
Income (loss) from discontinued operations, net of tax(1)       2,422     (575 ) (7,731 )
Cumulative effect of change in accounting principle, net of tax(2)             5,854  
   
 
 
 
 
 
Net earnings   $ 169,306   168,502   151,568   122,551   88,351  
Basic earnings per share:                        
  Earnings from continuing operations   $ 2.22   2.67   2.47   2.16   1.82  
  Income (loss) from discontinued operations, net of tax       .04     (.01 ) (.15 )
  Cumulative effect of change in accounting principle, net of tax             .12  
   
 
 
 
 
 
  Basic earnings per common share   $ 2.22   2.71   2.47   2.15   1.79  
Diluted earnings per share:                        
  Earnings from continuing operations   $ 2.18   2.62   2.41   2.12   1.79  
  Income (loss) from discontinued operations, net of tax       .04     (.01 ) (.15 )
  Cumulative effect of change in accounting principle, net of tax             .11  
   
 
 
 
 
 
  Diluted earnings per common share   $ 2.18   2.66   2.41   2.11   1.75  
Total assets   $ 5,695,548   3,189,072   3,645,546   3,122,505   2,683,548  
Long-term debt   $ 1,503,035   1,204,709   884,807   888,819   929,971  
Shareholders' equity   $ 2,411,811   1,434,006   1,684,522   1,472,147   1,185,798  

OPERATING DATA

 

 

 

 

 

 

 

 

 

 

 

 
Annual production:                        
  Gas (MMcf)     108,042   73,024   101,833   107,366   96,977  
  Liquids (MBbls)     7,945   8,026   10,568   10,837   8,701  
Average sales price(3):                        
  Gas (per Mcf)   $ 5.79   5.58   6.36   5.34   4.53  
  Liquids (per Bbl)   $ 57.54   50.70   39.23   31.05   24.77  

(1)
Discontinued operations relate to the sale of the business assets of our Canadian marketing subsidiary on March 1, 2004. The results for this business' operations have been reported as discontinued operations in the selected financial data for all periods presented.
(2)
Cumulative effect of change in accounting principle for 2003 relates to the adoption of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003.
(3)
Includes the effects of hedging under cash flow hedge accounting in 2003 to 2006.

31


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

        All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are forward-looking statements, as described in more detail in Part I, Item 1 under the heading "Forward-Looking Statements." Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Item 1A—"Risk Factors," and elsewhere in this Form 10-K. Historical statements made herein are accurate only as of the date of filing of this Form 10-K with the Securities and Exchange Commission, and may be relied upon only as of that date.

        The following discussion and analysis should be read in conjunction with Forest's Consolidated Financial Statements and the Notes to Consolidated Financial Statements.

Overview

        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. We conduct our operations in three geographical segments and five business units. The geographical segments are: the United States, Canada, and International. The business units are: Western, Eastern, Southern, Canada, and International. We conduct exploration and development activities in each of our geographical segments; however, substantially all of our estimated proved reserves and all of our producing properties are located in North America. Forest's total estimated proved reserves as of December 31, 2007 were approximately 2.1 Tcfe. At December 31, 2007, approximately 85% of our estimated proved oil and gas reserves were in the United States, approximately 12% were in Canada, and approximately 3% were in Italy.

Acquisition of Houston Exploration

        On June 6, 2007, Forest completed the acquisition of The Houston Exploration Company ("Houston Exploration") in a cash and stock transaction totaling approximately $1.5 billion and the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. Houston Exploration had operations in four producing regions within the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. The principal factors management considered in making the acquisition included the mix of complementary high-quality assets in certain of our existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies. At the time of the acquisition in June 2007, Forest estimated the Houston Exploration oil and gas reserves to be 653 Bcfe, of which 71% were classified as proved developed and the remaining amounts were classified as proved undeveloped. Pursuant to the terms and conditions of the agreement and plan of merger ("Merger Agreement"), Forest paid total merger consideration of $750 million in cash and issued approximately 24 million common shares, valued at $30.28 per share. The per share value of the Forest common shares issued was calculated as the average of Forest's closing share price for a five day period surrounding the announcement date of the acquisition on January 7, 2007. The cash component of the merger consideration was financed from a private placement of $750 million of 71/4% senior notes due 2019 and borrowings under our $1.0 billion second amended and restated credit facilities that were executed on June 6, 2007. Immediately following the completion of the merger, Forest repaid all of Houston Exploration's outstanding bank debt totaling $177 million. The revenues and expenses associated with Houston Exploration have been included in Forest's Consolidated Statement of Operations since June 6, 2007, the date the acquisition closed.

32


Sale of Alaska Assets

        On August 27, 2007, Forest sold all of its assets located in Alaska (the "Alaska Assets") to Pacific Energy Resources Ltd. ("PERL"). Forest estimated the proved oil and gas reserves associated with the Alaska Assets at closing to be 173 Bcfe. The total consideration received for the Alaska Assets included $400 million in cash, 10 million shares of PERL common stock (subject to certain restrictions), and a zero coupon senior subordinated note from PERL due 2014 in the principal amount at stated maturity of $60.8 million.

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 special 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 approximately 50.6 million 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. Forest estimated the proved oil and gas reserves associated with the Spin-off to be 313 Bcfe.

        The Spin-off was a tax-free transaction for federal income tax purposes. Prior to the Merger, as part of the Spin-off, MERI paid Forest approximately $176.1 million. The $176.1 million was drawn on a newly created bank credit facility established by MERI immediately prior to the Spin-off. This credit facility and the associated liability were included in the Spin-off. Subsequent to the closing, in 2006 Forest received additional net cash proceeds of $21.7 million from MERI for a total of $197.8 million. In accordance with the transaction agreements, Forest and MERI each submitted post-closing adjustments, from which Forest paid MERI a total of $5.8 million during 2007. Additional adjustments to the cash amount may occur during 2008 pending the resolution of certain accounting matters that are the subject of ongoing arbitration between Forest and MERI. The arbitration is currently expected to be concluded in the second half of 2008.

Other 2007 Highlights

        Forest's other 2007 highlights were as follows:

    Oil and gas production in 2007 increased 28% to 156 Bcfe from 121 Bcfe in 2006.

    Forest's year-end estimated proved reserves were a record 2,119 Bcfe, 664 Bcfe higher than 2006's year-end estimated proved reserves of 1,455 Bcfe, primarily as a result of the Houston Exploration acquisition and additional discoveries offset by the sale of the Alaska Assets.

    On June 6, 2007, Forest issued $750 million of 71/4% senior notes due 2019 (the "71/4% Notes"). The net proceeds from the 71/4% Notes offering of $739.2 million, after deducting initial purchaser discounts, were used to fund a portion of the cash consideration for Forest's acquisition of Houston Exploration.

    On June 6, 2007, Forest entered into second amended and restated U.S. and Canadian credit facilities in connection with the Houston Exploration acquisition which will mature in 2012. Initial commitments consist of a U.S. facility of $850 million and a Canadian facility of $150 million for a total of $1.0 billion.

2008 Outlook

        In 2008, we expect to continue our development and exploitation activities on our North American assets for which we expect continued production growth. Our exploration and development

33



expenditures budget for 2008 is $900 million to $1 billion. Most of this capital budget will be directed to our large drilling programs in the Buffalo Wallow field in the Texas Panhandle, the Deep Basin in Alberta, Canada, the Rincon, Charco, Katy, and McAllen Ranch fields in South Texas, the Cotton Valley in East Texas, and the Arkoma Basin in Arkansas. Our inventory of exploitation and development projects is significant, which should provide us good visibility of future production growth.

        Additionally, together with our continued production cost reduction initiatives, the acquired lower-cost natural gas producing assets from Houston Exploration, and the sale of higher-cost oil producing Alaska Assets, we expect our future per-unit production costs in 2008 to be lower than previous years. However, with our production mix more heavily weighted towards natural gas production, our revenues will be more heavily dependent on natural gas prices than they have been in the past. Natural gas production is expected to make up approximately 75% of our total production mix in 2008 compared to approximately 60% in 2006.

        We expect to continue to pursue asset acquisition opportunities in 2008, but expect to continue to confront intense competition for these assets. Also, due to a relatively high commodity price environment, we anticipate service costs as well as costs of equipment and raw materials to remain consistent with the levels experienced in 2007. Our challenge will be to economically add reserves, through drilling and acquisitions, and operate our productive assets in a cost-efficient manner that achieves attractive returns for our shareholders.

Results of Operations

        For the year ended December 31, 2007, Forest reported net earnings of $169.3 million or $2.22 per basic share compared to net earnings of $168.5 million or $2.71 per basic share in 2006. The increase in net earnings in 2007 compared to 2006 was primarily due to increases in earnings from operations and realized hedging gains, offset by increased unrealized mark-to-market hedging losses and interest expense. For the year ended December 31, 2006, Forest reported net earnings of $168.5 million or $2.71 per basic share, an 11% increase compared to net earnings of $151.6 million or $2.47 per basic share in 2005. The increase in net earnings in 2006 compared to 2005 was primarily due to an increase in net unrealized mark-to-market hedging gains, offset by decreased earnings from operations as a result of the Spin-off transaction discussed above. Discussion of the components of the changes in our annual results follows.

34


Revenues

        Oil and gas production volumes, revenues, and weighted average sales prices, by product and location for the years ended December 31, 2007, 2006, and 2005, are set forth in the table below. This table does not include miscellaneous marketing and processing revenues of $.8 million, $5.5 million, and $9.5 million for the years ended December 31, 2007, 2006, and 2005, respectively.

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  Gas
  Oil
  NGLs
  Total
  Gas
  Oil
  NGLs
  Total
  Gas
  Oil
  NGLs
  Total
 
 
  (MMcf)
  (MBbls)
  (MBbls)
  (MMcfe)
  (MMcf)
  (MBbls)
  (MBbls)
  (MMcfe)
  (MMcf)
  (MBbls)
  (MBbls)
  (MMcfe)
 
Production volumes:                                                    
  United States     82,963   4,504   2,381   124,273   48,674   5,243   1,644   89,996   82,912   7,412   1,904   138,808  
  Canada     25,079   793   267   31,439   24,350   739   400   31,184   18,921   844   408   26,433  
   
 
 
 
 
 
 
 
 
 
 
 
 
Totals     108,042   5,297   2,648   155,712   73,024   5,982   2,044   121,180   101,833   8,256   2,312   165,241  
   
 
 
 
 
 
 
 
 
 
 
 
 

Revenues (In Thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  United States   $ 493,321   305,873   93,624   892,818   302,050   326,024   52,636   680,710   624,457   391,226   56,375   1,072,058  
  Canada     132,601   46,037   11,625   190,263   123,408   37,605   16,559   177,572   126,771   35,382   14,748   176,901  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Total before hedging     625,922   351,910   105,249   1,083,081   425,458   363,629   69,195   858,282   751,228   426,608   71,123   1,248,959  
  Less hedging effects(1)             (17,893 ) (25,920 )   (43,813 ) (103,292 ) (83,150 )   (186,442 )
   
 
 
 
 
 
 
 
 
 
 
 
 
Totals   $ 625,922   351,910   105,249   1,083,081   407,565   337,709   69,195   814,469   647,936   343,458   71,123   1,062,517  
   
 
 
 
 
 
 
 
 
 
 
 
 

Average sales price:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
  United States   $ 5.95   67.91   39.32   7.18   6.21   62.18   32.02   7.56   7.53   52.78   29.61   7.72  
  Canada     5.29   58.05   43.54   6.05   5.07   50.89   41.40   5.69   6.70   41.92   36.15   6.69  
   
 
 
 
 
 
 
 
 
 
 
 
 
  Combined     5.79   66.44   39.75   6.96   5.83   60.79   33.85   7.08   7.38   51.67   30.76   7.56  
  Less hedging effects(1)             (.25 ) (4.34 )   (.36 ) (1.02 ) (10.07 )   (1.13 )
   
 
 
 
 
 
 
 
 
 
 
 
 
Totals   $ 5.79   66.44   39.75   6.96   5.58   56.45   33.85   6.72   6.36   41.60   30.76   6.43  
   
 
 
 
 
 
 
 
 
 
 
 
 

(1)
Commodity swaps and collars accounted for as cash flow hedges. See Part II, Item 7A—"Quantitative and Qualitative Disclosures about Market Risk" below concerning our hedging activities.

Production Volumes and Oil and Gas Revenues

        Net oil and gas production in 2007 was 155.7 Bcfe or an average of 426.6 MMcfe per day, a 28% increase from 121.2 Bcfe or an average of 332.0 MMcfe per day in 2006. The net increase in oil and gas production was primarily attributable to the additional production associated with the Houston Exploration acquisition in June 2007, which was partially offset by the Spin-off in early March 2006 and the sale of the Alaska Assets in August 2007. Oil and natural gas revenues before hedging effects in 2007 were $1.1 billion, a 26% increase as compared to $858.3 million in 2006. The increase in oil and natural gas revenues before hedging effects of $224.8 million was due to the 28% increase in production, offset by a 2% decrease in the average realized sales price (before the effects of hedging), to $6.96 per Mcfe in 2007 from $7.08 per Mcfe in 2006.

        Net oil and gas production in 2006 was 121.2 Bcfe or an average of 332.0 MMcfe per day, a 27% decrease from 165.2 Bcfe or an average of 452.7 MMcfe per day in 2005. The net decrease in oil and gas production was primarily attributable to the spin-off of our offshore Gulf of Mexico properties on March 2, 2006, partially offset by production increases in the Buffalo Wallow area and the Canadian Deep Basin as well as the East Texas property acquisition in March 2006. Oil and natural gas revenues before hedging effects were $858.3 million in 2006, a 31% decrease as compared to $1.2 billion in 2005. The decrease in oil and natural gas revenues before hedging effects was due to the 27% decrease in production as well as a 6% decrease in the average realized sales price (before the effects of hedging) to $7.08 per Mcfe in 2006 from $7.56 in 2005.

35


Hedge Effects

        The table above also presents the effects of the derivative instruments (e.g., commodity swaps and collars) we designated as cash flow hedges. Beginning in March 2006, we elected to discontinue the use of cash flow hedge accounting for all of our commodity derivatives. Accordingly, all gains or losses recognized (i.e., cash settlements) in connection with hedging activities for the majority of 2006 and all of 2007 are reflected in "Realized gains and losses on derivative instruments" in other income and expense in our Consolidated Statements of Operations rather than being included as part of "Revenues". See Realized and Unrealized Gains and Losses on Derivative Instruments below for information on gains and losses recognized on derivative instruments not designated as cash flow hedges during the last three years.

Oil and Gas Production Expense

        The table below sets forth the detail of oil and gas production expense for the years ended December 31, 2007, 2006, and 2005:

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands, Except per Mcfe Data)

Lease operating expenses ("LOE"):              
  Direct operating expense and overhead   $ 146,868   132,568   166,119
  Workover expense     20,605   22,130   30,011
  Hurricane repairs       176   3,631
   
 
 
    Total LOE   $ 167,473   154,874   199,761
   
 
 
LOE per Mcfe   $ 1.08   1.28   1.21

Production and property taxes

 

$

55,264

 

39,041

 

42,615
Production and property taxes per Mcfe   $ .35   .32   .26

Transportation and processing costs

 

$

20,200

 

21,876

 

19,499
Transportation and processing costs per Mcfe   $ .13   .18   .12

Total oil and gas production expense

 

$

242,937

 

215,791

 

261,875
Total oil and gas production expense per Mcfe   $ 1.56   1.78   1.58

Lease Operating Expenses

        Lease operating expenses were $167.5 million in 2007, an increase of 8% compared to $154.9 million in 2006. On a per-Mcfe basis, LOE decreased 16% to $1.08 per Mcfe in 2007 from $1.28 per Mcfe in 2006. The decrease in LOE on a per-Mcfe basis is primarily due to lower average per-unit lease operating expenses from the assets acquired from Houston Exploration in June 2007, the divestiture of the Alaska Assets in August 2007, and continued cost reduction initiatives. Lease operating expenses decreased 22%, or $44.9 million, to $154.9 million in 2006 from $199.8 million in 2005. The decrease in lease operating expenses is primarily due to the spin-off of our Gulf of Mexico operations on March 2, 2006, partially offset by increases in operating expenses associated with our acquisition of East Texas properties in March 2006. On a per-Mcfe basis, LOE increased to $1.28 per Mcfe in 2006 from $1.21 per Mcfe in 2005.

Production and Property Taxes

        Production and property taxes, which are primarily made up of severance taxes paid on the value of the oil and gas produced, generally fluctuate proportionately to our oil and gas revenues. As a percentage of oil and natural gas revenue, excluding hedging losses recognized in 2006 and 2005,

36



production and property taxes were 5.1%, 4.5%, and 3.4% for the years ended December 31, 2007, 2006, and 2005, respectively. The increase in each period is primarily the result of a change in our production mix to a higher percentage of onshore production, which is generally subject to production taxes, versus offshore Gulf of Mexico production, which is generally not subject to production taxes. In addition, normal fluctuations will occur between periods based on the approval of incentive tax credits, changes in tax rates, and changes in the assessed values of property and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

        Transportation and processing costs were $20.2 million, or $.13 per Mcfe, in 2007 compared to $21.9 million, or $.18 per Mcfe, in 2006. The decrease of $.05 on a per-Mcfe basis in 2007 was due primarily to lower per-unit transportation costs incurred in Alaska in 2007 compared to the prior year and due to the sale of the Alaska Assets in August 2007. Transportation and processing costs were $21.9 million, or $.18 per Mcfe, in 2006 compared to $19.5 million, or $.12 per Mcfe, in 2005. The $.06 per Mcfe increase was primarily due to higher transportation and processing costs in Canada and due to lower average per-unit transportation and processing costs associated with our offshore Gulf of Mexico operations, which were included in the Spin-off in March 2006.

General and Administrative Expense

        The following table summarizes the components of general and administrative expense incurred during the periods indicated:

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (In Thousands, Except Per Mcfe Data)
 
Stock-based compensation costs   $ 17,681   22,048   1,275  
Other general and administrative costs     89,697   58,108   68,934  
General and administrative costs capitalized     (43,627 ) (31,848 ) (26,506 )
   
 
 
 
General and administrative expense   $ 63,751   48,308   43,703  
   
 
 
 
General and administrative expense per Mcfe   $ .41   .40   .26  

        General and administrative expense increased $15.5 million to $63.8 million in 2007 from $48.3 million in 2006. The increase in net general and administrative expense was primarily related to increased employee salary and benefit costs resulting from the acquisition of Houston Exploration, offset by a reduction to stock-based compensation costs in 2007. The increase in general and administrative expense of $4.6 million to $48.3 million in 2006 from $43.7 million in 2005 was primarily related to higher stock-based compensation costs (discussed below), offset by salary and benefit savings related to a reduction in the number of employees subsequent to the Spin-off. The increase of $.14 on a per-unit basis from 2005 to 2006 was also primarily due to stock-based compensation costs. The percentage of general and administrative costs capitalized remained relatively constant between the three years, ranging between 38% and 41%.

        The increase in stock-based compensation costs beginning in 2006 was due to the implementation of Statement of Financial Accounting Standards ("SFAS") No. 123 (Revised), "Share-Based Payment" ("SFAS 123(R)"). Under the fair value recognition provisions of SFAS 123(R), stock-based compensation is measured at the grant date based on the value of the awards and is recognized over the requisite service period (usually the vesting period). Prior to January 1, 2006, we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under APB Opinion No. 25, no compensation expense was recognized for stock options issued to

37



employees, because the grant price equaled or was above the market price on the date of the option grant.

        In accordance with the provisions of SFAS 123(R), we recorded stock-based compensation cost in the amount of $17.7 million in 2007 and $22.0 million in 2006, of which approximately $9.7 million was attributed to a partial settlement of Forest's restricted stock awards and phantom stock unit awards in connection with the Spin-off. The decrease in stock-based compensation of $4.3 million in 2007 from 2006 was due to the $9.7 million partial settlement in 2006, partially offset by the recognition of stock-based compensation associated with restricted stock and stock options granted in 2007.

Depreciation and Depletion; Undeveloped Properties

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands, Except Per Mcfe Amounts)

Depreciation and depletion expense   $ 390,338   266,881   368,679
Depreciation and depletion expense per Mcfe   $ 2.51   2.20   2.23

        Depreciation, depletion, and amortization expense ("DD&A") in 2007 was $390.3 million compared to $266.9 million in 2006. On an equivalent Mcf basis, DD&A expense increased to $2.51 per Mcfe in 2007 compared to $2.20 per Mcfe in 2006. The increase of $.31 per Mcfe in 2007 was primarily due to the acquisition of the Houston Exploration properties, which had higher-than-historical per-unit depletion rates. DD&A in 2006 was $266.9 million compared to $368.7 million in 2005.

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

December 31,

  United States
  Canada
  International
  Total
 
  (In Thousands)

2007   $ 445,949   63,951   58,610   568,510
2006     149,687   53,034   58,538   261,259
2005     174,249   44,798   56,637   275,684

        The increase in the total undeveloped properties of $307.3 million in 2007 from $261.3 million in 2006 is primarily attributable to the Houston Exploration acquisition completed in 2007. The decrease in the total undeveloped properties of $14.4 million in 2006 from $275.7 million in 2005 was due primarily to the Spin-off transaction noted above, offset by property acquisitions completed during 2006, including the Cotton Valley assets in East Texas. See Note 2 to the Consolidated Financial Statements for additional information on acquisitions and divestitures.

Accretion of Asset Retirement Obligations

        Accretion expense of $6.1 million in 2007, $7.1 million in 2006, and $17.3 million in 2005 was related to the accretion of Forest's asset retirement obligations pursuant to SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to its present value. The significant decrease from 2005 to 2006 is attributable to the large reduction in future abandonment liabilities associated with the Spin-off in March 2006, discussed above. See Note 1 to the Consolidated Financial Statements for additional information on our asset retirement obligations.

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International Impairments

        Forest recorded impairments related to its international properties of $3.7 million in 2006, with $2.1 million recorded during the second quarter of 2006 related to a dry hole drilled in Gabon and $1.6 million recorded during the fourth quarter of 2006 related to expired concessions in Italy. In 2005, Forest recorded an impairment of $2.9 million related to certain international properties, principally related to its leaseholds in Romania. The Romania impairment was recorded in the first quarter of 2005 in connection with our decision to exit the country as we rationalized our international assets to concentrate on fewer areas.

Gain on Sale of Assets

        During the year ended December 31, 2007, Forest sold overriding royalty interests in Australia for net proceeds of $7.2 million that resulted in a gain on the sale of $7.2 million.

Interest Expense

        Interest expense of $113.2 million in 2007 increased by $41.4 million, or 58%, from $71.8 million in 2006. The increase in interest expense in 2007 from 2006 is primarily due to the 71/4% senior notes due 2019 that we issued in June 2007 and the Alaska term loan credit facilities, which were entered into in December 2006 and were paid off in August 2007. Interest expense of $71.8 million in 2006 was 17% greater than in 2005, primarily due to higher average interest rates and higher average debt balances. Interest costs related to significant unproved properties that are under development are capitalized to oil and gas properties under the full cost method of accounting. Forest capitalized interest of $13.9 million, $3.7 million, and $.9 million during the years ended December 31, 2007, 2006, and 2005, respectively. The increase in interest capitalized in 2007 from 2006 is due to the acquisition of Houston Exploration, which included a large investment in unproved properties.

Realized and Unrealized Gains and Losses on Derivative Instruments

        The table below sets forth realized and unrealized gains and losses on derivatives recognized under "Other income and expense" in our Consolidated Statements of Operations for the periods indicated. Since March 2006, when Forest elected to discontinue cash flow hedge accounting for all of its derivative instruments, Forest has recognized all mark-to-market gains and losses as "Unrealized gains and losses on derivative instruments" in other income and expense in the Consolidated Statements of Operations rather than deferring any such amounts in "Accumulated other comprehensive income" in shareholders' equity. In addition, cash settlements on derivative instruments are recorded as "Realized gains and losses on derivative instruments" in other income and expense in the Consolidated Statements of Operations rather than as an adjustment to "Revenues" or "Interest expense." The amounts shown in the table below for 2006 and 2005, prior to our discontinuance of cash flow hedge accounting, represent amounts related to ineffective hedges or derivatives that did not meet the criteria

39



to qualify for cash flow hedge accounting. See Note 9 to the Consolidated Financial Statements for more information on our derivative instruments.

 
  Year Ended December, 31
 
 
  2007
  2006
  2005
 
 
  (In Thousands)

 
Realized (gains) and losses on derivatives, net:                
  Oil(1)   $ (2,587 ) 29,743   (527 )
  Gas     (72,904 ) (5,879 ) 35,917  
  Interest     (474 )    
   
 
 
 
Total   $ (75,965 ) 23,864   35,390  
   
 
 
 
Unrealized losses (gains) on derivatives, net:                
  Oil   $ 123,099   (36,953 ) 3,475  
  Gas     (10,321 ) (46,676 ) 17,898  
  Interest     4,721      
   
 
 
 
Total   $ 117,499   (83,629 ) 21,373  
   
 
 
 

(1)
Includes total proceeds of $6.9 million for two oil swap agreements that we unwound in 2007, which covered 1,000 Bbl per day in 2009 and 500 Bbl per day in 2010.

Other Income and Expense

        The components of other income and expense for the years ended December 31, 2007, 2006, and 2005 were as follows:

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands)

Realized foreign currency exchange gains   $ (7,721 ) (315 )
Unrealized foreign currency exchange (gain) loss     (7,694 ) 3,931  
Franchise taxes     2,322   1,410   1,963
Share of (income) loss of equity method investee     (275 ) (2,334 ) 562
Unrealized loss on other investments     4,948    
Debt extinguishment costs     12,215    
Other, net     (2,214 ) 1,135   3,722
   
 
 
  Total other expense, net   $ 1,581   3,827   6,247
   
 
 

        The realized foreign currency exchange gains relate to the repayments of intercompany debt owed to Forest Oil Corporation by our Canadian subsidiary. The unrealized foreign currency exchange gains and losses relate to the outstanding intercompany indebtedness between Forest Oil Corporation and our Canadian subsidiary. Franchise taxes are paid to the states of Texas and Louisiana based on capital investment deployed in these states, determined by apportioning total capital as defined by statute. Forest's share of income or loss of equity method investee related to our 40% ownership of a pipeline company that transports crude oil in Alaska, which was included in the sale of the Alaska Assets in August 2007. The unrealized loss on other investments relates to the mark-to-market adjustment of the PERL common stock we received as a portion of the consideration in the sale of the Alaska Assets in August 2007. Debt extinguishment costs related to the complete repayment of the Alaska credit agreements and include $5.0 million in prepayment premiums and $7.2 million of unamortized debt issue costs.

40


Income Tax Expense

        The table below sets forth Forest's total income tax expense from continuing operations and effective tax rates for the periods presented:

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (In Thousands, Except Percentages)

 
Current income tax expense   $ 5,999   2,126   3,498  
Deferred income tax expense     56,396   88,777   89,860  
   
 
 
 
Total income tax expense   $ 62,395   90,903   93,358  
   
 
 
 
Effective tax rate     27 % 35 % 38 %

        The increase in our current income tax expense in 2007 is primarily due to the sale of our Alaska Assets, which increased our income subject to federal alternative minimum tax and the implementation of a margin tax by the state of Texas effective January 1, 2007. The decrease in our effective tax rate in 2007 to 27%, from 35% in 2006, was primarily due to a reduction in income taxes of approximately $21.0 million related to statutory rate reductions enacted in Canada, release of valuation allowances, and a lower apportioned effective state income tax rate. The decrease in our effective tax rate in 2006 to 35%, from 38% in 2005, was due to a reduction in income taxes of approximately $18.0 million also related to statutory rate reductions enacted in Canada as well as changes in the Texas income tax law, both offset in part by an increase of $7.2 million related to the effects of the Spin-off of our offshore Gulf of Mexico operations (which includes the tax effects of non-deductible Spin-off costs and an increase in Forest's combined state income tax rates). See Note 5 to the Consolidated Financial Statements for a reconciliation of our income taxes at the statutory rate to income taxes at our effective rate for each period presented.

Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary were sold to Cinergy Canada, Inc. ("Cinergy") for $11.2 million CDN. The subsidiary's results of operations have been reported as discontinued operations in the Consolidated Statements of Operations for all years presented. Under the terms of the purchase and sale agreement, Cinergy will market natural gas on behalf of Canadian Forest for five years through February 2009 (unless subject to prior contractual commitment), and will also administer the netback pool that we formerly administered. We could receive additional contingent payments related to this sale over the next two years if Cinergy meets certain earnings goals with respect to the acquired business. During the years ended December 31, 2007 and 2005, Forest did not receive any additional contingent payments. During 2006, Forest received an additional $3.6 million contingent payment ($2.4 million net of tax) under the agreement, which has been reflected as income from discontinued operations in the Consolidated Statements of Operations.

Liquidity and Capital Resources

        In 2008, as in 2007, we expect our cash flow from operations to be our primary source of liquidity to meet operating expenses and fund capital expenditures other than large acquisitions. Any remaining cash flow from operations will be available for acquisitions, in whole or in part, or other corporate purposes, including the repayment of senior notes that will come due in June 2008.

        The prices we receive for our oil and natural gas production have a significant impact on operating cash flows. While significant price declines in 2008 would adversely affect the amount of cash flow generated from operations, we utilize a hedging program to partially mitigate that risk. As of February 27, 2008, Forest has hedged approximately 75 Bcfe of its 2008 production. This level of

41


hedging provides some certainty of the cash flow we will receive for a portion of our expected 2008 production. Depending on changes in oil and gas futures markets and management's view of underlying oil and natural gas supply and demand trends, we may increase or decrease our current hedging positions. For further information concerning our 2008 hedging contracts, see Item 7A—"Quantitative and Qualitative Disclosures about Market Risk—Hedging Program," below.

        Our revolving U.S. and Canadian bank credit facilities, which were amended and restated in June 2007, provide another source of liquidity. These credit facilities, which mature in June 2012, are used to fund daily operating activities and acquisitions in the United States and Canada as needed. See "Bank Credit Facilities" below for details.

        The public capital markets have been our principal source of funds to finance large acquisitions. We have sold debt and equity securities in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, ready access to capital on reasonable terms can be impacted by our debt ratings assigned by independent rating agencies and are subject to many uncertainties, including restrictions contained in our bank credit facilities and indentures for our senior notes, macroeconomic factors outside of our control, and other risks as explained in Part 1, Item 1A—"Risk Factors."

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

Bank Credit Facilities

        On June 6, 2007, Forest entered into amended and restated credit facilities totaling $1.0 billion. The amended and restated facilities consist of an $850 million U.S. credit facility (the "U.S. Facility") through a syndicate of banks led by JPMorgan Chase Bank, N.A. and a $150 million Canadian credit facility (the "Canadian Facility", and together with the U.S. Facility, the "Credit Facilities") through a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Credit Facilities mature in June 2012. Subject to the agreement of Forest and the applicable lenders, the size of the Credit Facilities may be increased by $800 million in the aggregate.

        Forest's availability under the Credit Facilities will be governed by a borrowing base ("Global Borrowing Base") which currently is set at $1.4 billion, with $1.25 billion allocated to the U.S. credit facility and $150 million allocated to the Canadian credit facility. The determination of the Global Borrowing Base is made by the lenders in their sole discretion taking into consideration the estimated value of Forest's oil and gas properties in accordance with the lenders' customary practices for oil and gas loans. The Global Borrowing Base is redetermined semi-annually and the available borrowing amount could be increased or decreased as a result of such redeterminations. In addition, Forest and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the Global Borrowing Base redetermined.

        The Credit Facilities include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and include financial covenants. Interest rates and collateral requirements under the Credit Facilities will vary based on Forest's credit ratings and financial condition, as governed by certain financial tests.

        Under certain conditions, amounts outstanding under the Credit Facilities may be accelerated. Bankruptcy and insolvency events with respect to Forest or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facilities. Subject to notice and cure periods in certain cases, other events of default under either of the Credit Facilities will result in

42



acceleration of the indebtedness under the facilities at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facilities (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, a failure of the liens securing the Credit Facilities, and an event of default under the Canadian Facility.

        The Credit Facilities include provisions and conditions linked to Forest's credit ratings. Forest's ability to raise funds and the cost of any financing activities may be affected by our credit ratings at the time any such activities are conducted. See Note 4 to the Consolidated Financial Statements for more information on the Credit Facilities.

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

        From time to time, Forest and the syndication agents, documentation agents, global administrative agent, and the other lenders party to the Credit Facilities engage in other transactions, including securities offerings where such parties or their affiliates may serve as an underwriter or initial purchaser of Forest's securities and, or serve as counterparties to Forest's derivative agreements.

        At December 31, 2007, there were outstanding borrowings of $165.0 million under the U.S. Facility at a weighted average interest rate of 6.2%, and there were outstanding borrowings of $129.1 million under the Canadian Facility at a weighted average interest rate of 5.9%. We also had used the Credit Facilities for approximately $2.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facilities of approximately $703.3 million at December 31, 2007. At January 31, 2008, there were outstanding borrowings of $192.0 million under the U.S. Facility at a weighted average interest rate of 5.6%, and there were outstanding borrowings of $116.6 million under the Canadian Facility at a weighted average interest rate of 5.6%. We also had used the Credit Facilities for approximately $2.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facilities of approximately $688.8 million at January 31, 2008.

Alaska Credit Agreements

        On December 8, 2006, Forest, through its wholly-owned subsidiaries, Forest Alaska Operating LLC and Forest Alaska Holding LLC (together "Forest Alaska"), issued, on a non-recourse basis to Forest, term loan financing facilities in the aggregate principal amount of $375 million. The issuance was comprised of two term loan facilities, including a $250 million first lien credit agreement and a $125 million second lien credit agreement (together the "Alaska Credit Agreements"). The loan proceeds were used to fund a $350 million distribution to Forest, which Forest used to pay down its U.S. credit facility, and to provide Forest Alaska working capital for its operations and pay transaction fees and expenses.

        During the year ended December 31, 2007, Forest Alaska made scheduled repayments of $1.3 million and a voluntary prepayment of $110.0 million on the first lien credit agreement. In conjunction with the sale of the Alaska Assets on August 27, 2007, Forest used a portion of the $400 million cash consideration to repay the remaining $263.7 million principal balance outstanding under the Alaska Credit Agreements. During the year ended December 31, 2007, Forest recognized debt extinguishment costs of $12.2 million associated with payments on the Alaska Credit Agreements. The debt extinguishment costs included $5.0 million in prepayment premiums on the Alaska Credit Agreements and $7.2 million of unamortized debt issuance costs.

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Credit Ratings

        Our senior notes are separately rated by two ratings agencies: Moody's and S&P. In addition, Moody's and S&P have assigned Forest a general corporate credit rating. From time to time, our assigned credit ratings may change. In assigning ratings, the ratings agencies evaluate a number of factors, such as our industry segment, volatility of our industry segment, the geographical mix and diversity of our asset portfolio, the allocation of properties and exploration and drilling activities among short-lived and longer-lived properties, the need and ability to replace reserves, our cost structure, our debt and capital structure, and our general financial condition and prospects.

        Our bank credit facilities include conditions that are linked to our credit ratings. The fees and interest rates on our commitments and loans, as well as our collateral obligations, are affected by our credit ratings. The indentures governing our senior notes do not include adverse triggers that are tied to our credit ratings. The indentures include terms that will allow us greater flexibility if our credit ratings improve to investment grade and other tests have been satisfied. In this event, we would have no further obligation to comply with certain restrictive covenants contained in the indentures. Our ability to raise funds and the costs of any financing activities may be affected by our credit rating at the time any such activities are conducted.

Historical Cash Flow

        Net cash provided by operating activities, net cash used by investing activities, and net cash provided (used) by financing activities for the years ended December 31, 2007, 2006, and 2005 were as follows:

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (In Thousands)

 
Net cash provided by operating activities   $ 708,245   422,478   628,565  
Net cash used by investing activities     (1,093,221 ) (909,891 ) (671,230 )
Net cash provided (used) by financing activities     359,552   513,832   (4,596 )

        The increase in net cash provided by operating activities of $285.8 million in 2007 as compared to 2006 was primarily due to higher net income before non-cash charges and a decreased investment in net operating assets in 2007 as compared to 2006. The decrease in net cash provided by operating activities in 2006 compared to 2005 of approximately $206.1 million was due primarily to the Spin-off in March 2006.

        Cash used by investing activities increased in 2007 by $183.3 million as compared to 2006 primarily due to an increase in cash used for acquisitions, exploration, and development of oil and gas properties, offset by an increase in proceeds from the sale of oil and gas properties. The increase in cash used by investing activities in 2006 of $238.7 million compared to 2005 was also primarily due to an increase in cash used for the acquisition, exploration, and development of oil and gas properties. The major

44



components of cash used by investing activities for the years ended December 31, 2007, 2006 and 2005 were as follows:

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (In Thousands)

 
Acquisitions   $ (778,880 ) (292,807 ) (204,450 )
Exploration and development costs     (784,220 ) (601,641 ) (475,524 )
Other fixed assets     (32,169 ) (21,950 ) (10,743 )
Proceeds from sale of Alaska Assets     400,000      
Proceeds from sale of other assets     102,048   6,507   24,046  
Other         (4,559 )
   
 
 
 
Net cash used by investing activities   $ (1,093,221 ) (909,891 ) (671,230 )
   
 
 
 

        Net cash provided by financing activities of $359.6 million in 2007 included the issuance of the 71/4% Notes for net proceeds of $739.2 million, net bank proceeds of $171.3 million, and proceeds from the exercise of stock options and from the employee stock purchase plan of $12.8 million, offset by the repayment of the Alaska Credit Agreements of $375.0 million and repayment of Houston Exploration's bank debt of $176.9 million. Net cash provided by financing activities in 2006 of $513.8 million included net bank proceeds of $130.2 million, proceeds from the Alaska Credit Agreements (net of issuance costs) of $367.7 million, $21.7 million of proceeds from the Spin-off, and proceeds from the exercise of stock options and from the employee stock purchase plan of approximately $6.8 million. Net cash used by financing activities in 2005 of $4.6 million primarily included the net repayment of bank borrowings of $33.3 million, more than offset by net proceeds from the exercise of options and warrants of approximately $43.4 million.

Capital Expenditures

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

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands)

Property acquisitions:(1)              
  Proved properties   $ 1,744,093   262,534   239,647
  Undeveloped properties     449,346   53,788   73,868
   
 
 
      2,193,439   316,322   313,515

Exploration:

 

 

 

 

 

 

 
  Direct costs     137,475   250,344   247,331
  Overhead capitalized     10,722   12,121   12,811
   
 
 
      148,197   262,465   260,142

Development:

 

 

 

 

 

 

 
  Direct costs     622,466   344,725   266,330
  Overhead capitalized     32,905   19,727   13,695
   
 
 
      655,371   364,452   280,025
   
 
 
Total capital expenditures(1)(2)   $ 2,997,007   943,239   853,682
   
 
 

(1)
Total capital expenditures include both cash expenditures and accrued expenditures. In addition, property acquisitions include a gross up for deferred income taxes of approximately $559.1 million in 2007 and $71.5 million in 2005 and exclude goodwill recorded in connection with business combinations of approximately $176.8 million in 2007 and $23.0 million in 2005. See Note 2 to the Consolidated Financial Statements for the allocation of purchase consideration for the larger acquisitions completed in 2007, 2006, and 2005.
(2)
Includes estimated discounted asset retirement obligations of $37.8 million, $2.4 million, and $16.3 million related to assets placed in service during the years ended December 31, 2007, 2006, and 2005, respectively.

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        Forest's anticipated expenditures for exploration and development in 2008 are estimated to range from $900 million to $1 billion. Some of the factors impacting the level of capital expenditures in 2008 include crude oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market conditions, and weather disruptions.

Contractual Obligations

        The following table summarizes our contractual obligations as of December 31, 2007:

 
  2008
  2009
  2010
  2011
  2012
  After 2012
  Total
 
  (In Thousands)

Bank debt(1)   $ 17,892   17,892   17,892   17,892   303,073     374,641
Senior notes(2)     364,808   89,208   89,208   374,208   66,204   1,275,167   2,258,803
Operating leases(3)     18,113   16,643   14,499   14,364   13,496   27,449   104,564
Unconditional purchase obligations(4)     42,881   27,099   1,607   513   123     72,223
Other liabilities(5)     6,580   8,950   8,970   11,439   10,500   82,454   128,893
Derivative liabilities(6)     72,675   30,545   7,626         110,846
Approved capital projects(7)     52,903             52,903
   
 
 
 
 
 
 
Total contractual obligations   $ 575,852   190,337   139,802   418,416   393,396   1,385,070   3,102,873
   
 
 
 
 
 
 

(1)
Bank debt consists of commitments related to our United States and Canadian credit facilities and anticipated interest payments due under the terms of the credit facilities using the interest rates in effect at December 31, 2007.
(2)
Senior notes consist of the principal obligations on our senior notes and senior subordinated notes and anticipated interest payments due on each.
(3)
Consists primarily of leases for office space, drilling rigs, and well equipment rentals.
(4)
Consists primarily of firm commitments for drilling, gathering, processing, and pipeline capacity.
(5)
Other liabilities represent current and noncurrent liabilities that are comprised of benefit obligations and asset retirement obligations, for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See "Critical Accounting Policies, Estimates, Judgments, and Assumptions" below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(6)
Derivative liabilities represent the fair value of liabilities for oil and gas commodity and interest rate derivatives as of December 31, 2007. The ultimate settlement amounts of our derivative liabilities are unknown, because they are subject to continuing market risk. See "Critical Accounting Policies, Estimates, Judgments, and Assumptions," below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
(7)
Consists of our net share of budgeted expenditures under Authorizations for Expenditure ("AFE") that were approved by us and our joint venture partners as of December 31, 2007. Includes AFEs for which Forest is the operator as well as those operated by others.

        Forest also makes delay rental payments to lessors during the primary terms of oil and gas leases to delay drilling or production of wells, usually for one year. Although we are not obligated to make such payments, discontinuing them would result in the loss of the oil and gas lease. Our total maximum commitment under these leases, through 2015 totaled approximately $1.2 million as of December 31, 2007.

Off-balance Sheet Arrangements

        From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2007, the off-balance sheet arrangements and transactions that we have entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, and (iv) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as gas transportation commitments and derivative contracts that are sensitive to future changes in commodity prices and interest rates. Forest does not believe that any of these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

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Surety Bonds

        In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including governmental agencies. As of February 27, 2008, we had obtained surety bonds from a number of insurance and bonding institutions covering certain of our operations in the United States and Canada in the aggregate amount of approximately $19.6 million. See Part I, Item 1—"Business—Regulation" for further information.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Full Cost Method of Accounting

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

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

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

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

        In countries or areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities

47



cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. An impairment of unproved property costs may be indicated through evaluation of drilling results, relinquishment of drilling rights or other information.

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

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

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

Oil and Gas Reserve Estimates

        Our estimates of proved reserves are based on the quantities of oil and gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a "ceiling test" limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures included in Note 16 to the Consolidated Financial Statements.

        Reference should be made to "Independent Audit of Reserves" under Part I, Item 1—"Business," and "Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimate", under Part I, Item 1A—"Risk Factors," in this Form 10-K.

Accounting for Derivative Instruments

        We follow the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Under the provisions of SFAS 133, we may or may not elect to designate a derivative instrument as a hedge against changes in the fair value of an asset or a liability (a "fair value hedge") or against exposure to variability in expected future cash flows (a "cash flow hedge"). The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the

48



statement of operations due to the fact that changes in fair value of the derivative offsets changes in the fair value of the hedged item. Where hedge accounting is not elected or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as other income or expense. Since March 2006, we have elected not to use hedge accounting. Accordingly, after March 2006, all changes in the fair values of our derivative instruments have been and will continue to be recognized in earnings as "Unrealized gains or losses on derivative instruments" in our Consolidated Statements of Operations.

        The estimated fair values of our derivative instruments require substantial judgment. These values are based upon, among other things, future prices, volatility, time to maturity, and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions, or other factors, many of which are beyond our control.

        Due to the volatility of oil and natural gas prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. For example, a hypothetical 10% increase in the forward oil and natural gas prices used to calculate the fair values of our commodity derivative instruments at December 31, 2007 would decrease the net fair value of our commodity derivative instruments at December 31, 2007 by approximately $78 million. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at December 31, 2007 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

Valuation of Deferred Tax Assets

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

        In assessing the value of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon future taxable income during the periods in which related temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets will reverse, management believes it is more likely than not that we will realize the benefits of these deferred tax assets, net of the existing valuation allowances at December 31, 2007. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during relevant periods are reduced.

Asset Retirement Obligations

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

49


        Inherent in the calculation of the present value of our asset retirement obligations ("ARO") under SFAS No. 143 are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.

Impact of Recently Issued Accounting Pronouncements

        In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, "Fair Value Measurements" ("SFAS 157"). This statement clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position ("FSP") No. 157-1 and FSP No. 157-2. FSP No. 157-1 amends SFAS 157 to exclude lease transactions accounted for under SFAS No. 13, "Accounting for Leases" ("SFAS 13") and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. This scope exception does not apply to assets acquired and liabilities assumed in a business combination that are required to be measured at fair value under SFAS No. 141, "Business Combinations" or SFAS 141(R), regardless of whether those assets and liabilities are related to leases. FSP No. 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We are currently evaluating the impact the adoption of these pronouncements will have on our financial position and results of operations.

        In September 2006, the FASB ratified the consensus reached by the Emerging Issues Task Force ("EITF") related to EITF Issue No. 06-4, "Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements" ("EITF 06-4"), which requires the recognition of a liability for future benefits based on the substantive agreement with the employee. The liability is required to be recognized in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS 106"), or APB Opinion No. 12, "Omnibus Opinion—1967", as appropriate. EITF 06-4 is effective for fiscal years beginning after December 15, 2007 and requires transition through a cumulative effect adjustment to retained earnings or a retrospective application to all prior periods. We maintain a number of split-dollar life insurance arrangements for certain former employees. We are currently evaluating the impact the adoption of this pronouncement will have on our financial position and results of operations.

        In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("SFAS 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.

        In March 2007, the FASB ratified the consensus reached by the EITF in Issue No. 06-10, "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" ("EITF 06-10"). Under this consensus, an employer should recognize a liability for any postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 or APB Opinion No. 12, as appropriate, and should recognize and measure the underlying asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. EITF 06-10 is

50



effective for fiscal years beginning after December 15, 2007 and requires transition through a cumulative effect adjustment to retained earnings or a retrospective application to all prior periods. We maintain a number of split-dollar life insurance arrangements for certain former employees. We are currently evaluating the impact the adoption of this pronouncement will have on our financial position and results of operations.

        In December 2007, the FASB issued SFAS No. 141 (Revised), "Business Combinations" ("SFAS 141(R)"), which significantly changes the financial accounting and reporting of business combination transactions. SFAS 141(R) establishes principles and requirements for how an acquirer in a business combination: (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of this pronouncement may have a material impact on the accounting for any acquisitions we may make after January 1, 2009.

        In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51" ("SFAS 160"). This statement amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We do not expect the adoption of this pronouncement to have a material impact on our financial position or results of operations.

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

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

Commodity Price Risk

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

Hedging Program

        In order to reduce the impact of fluctuations in commodity prices, or to protect the economics of property acquisitions, we make use of an oil and gas hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other financial instruments with counterparties who, in general, are participants in our credit facilities. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

51


Swaps

        In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of December 31, 2007, we had entered into the following swaps:

 
  Swaps
 
 
  Natural Gas (NYMEX HH)
  Oil (NYMEX WTI)
 
 
  Bbtu
Per Day(1)

  Weighted Average
Hedged Price
per MMBtu

  Fair Value
(In Thousands)

  Barrels
Per Day

  Weighted Average
Hedged Price
per Bbl

  Fair Value
(In Thousands)

 
Calendar 2008   50   $ 8.38   $ 9,930   6,500   $ 69.72   $ (54,592 )
Calendar 2009             4,500     69.01     (28,563 )
Calendar 2010             1,500     72.95     (6,951 )

(1)
10 Bbtu per day is subject to a $6.00 written put.

Costless Collars

        Forest also enters into collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price; and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. As of December 31, 2007, we had entered into the following collars:

 
  Costless Collars(1)
 
 
  Natural Gas (NYMEX HH)
 
 
  Bbtu Per Day
  Weighted Average
Hedged Floor and
Ceiling Price
per MMBtu

  Fair Value
(In Thousands)

 
January – February 2008   130   $7.39/8.89   $ 1,138  
March – December 2008   80     7.33/8.87     (1,385 )

(1)
Included in Forest's outstanding natural gas costless collars at December 31, 2007 are natural gas costless collars assumed in the Houston Exploration acquisition with a fair value of $(12.8) million. At December 31, 2007, these costless collars had weighted average hedged floor and ceiling prices per MMBtu of $7.20/8.51 for 100 Bbtu per day for January – February 2008, and $5.00/5.72 for 20 Bbtu per day for March – December 2008.

Three-Way Costless Collars

        Forest also enters into three-way costless collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, Forest receives the difference between the two floors. If the index price is between the two floors, Forest receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, Forest does not receive or pay any amounts. If the index price is above the

52



ceiling, Forest pays the excess over the ceiling price. As of December 31, 2007, we had entered into the following three-way collars:

 
  Three-Way Costless Collars
 
  Natural Gas (NYMEX HH)
 
  Bbtu Per Day
  Weighted Average
Hedged Lower Floor,
Upper Floor, and
Ceiling Price per
MMBtu

  Fair Value
(In Thousands)

January – February 2008   20   $6.00/8.00/10.00   $ 903
March – December 2008   30     6.00/8.00/10.00     3,861

Basis Swaps

        Forest also uses basis swaps in connection with natural gas swaps in order to fix the price differential between the NYMEX price and the index price at which the natural gas production is sold. As of December 31, 2007, we had entered into the following basis swaps:

 
  Basis Swaps(1)
 
 
  Bbtu per Day
  Fair Values
(In Thousands)

 
Calendar 2008   80   $ (460 )

(1)
Included in Forest's outstanding basis swaps at December 31, 2007 are basis swaps assumed in the Houston Exploration acquisition with a fair value of $.1 million. At December 31, 2007, these basis swaps are for 80 Bbtu per day for January – February 2008.

        The fair value of all our commodity derivative instruments based on the futures prices quoted on December 31, 2007 was a net liability of approximately $76.1 million.

        In January and February 2008, we entered into six additional gas swap agreements for 60 Bbtu per day at a weighted average hedged price per MMBtu of $8.99 for calendar 2009. In February 2008, we entered into an additional gas costless collar agreement for 20 Bbtu per day with a hedged floor and ceiling price per MMBtu of $8.00 and $10.56, respectively, for calendar 2009.

Fair Value Reconciliation

        The following table reconciles the changes that occurred in the fair values of our open derivative contracts during the year ended December 31, 2007 (see discussion of interest rate swaps under "Interest Rate Risk" below):

 
  Fair Value of Derivative Contracts
 
 
  Commodity
  Interest Rate
  Total
 
 
  (In Thousands)

 
As of December 31, 2006   $ 66,119     66,119  
Fair value of acquired derivatives     (45,170 )   (45,170 )
Settlements of acquired derivatives     15,710     15,710  
Net decrease in fair value     (37,287 ) (4,247 ) (41,534 )
Net contract gains recognized     (75,491 ) (474 ) (75,965 )
   
 
 
 
As of December 31, 2007   $ (76,119 ) (4,721 ) (80,840 )
   
 
 
 

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Foreign Currency Exchange Risk

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

Interest Rate Risk

        The following table presents principal amounts and related interest rates by year of maturity for Forest's debt obligations at December 31, 2007:

 
  2008
  2011
  2012
  2013
  2014
  2019
  Total
  Fair Value
 
  (Dollar Amounts in Thousands)

Bank credit facilities:                                  
  Variable rate   $     294,126         294,126   294,126
  Average interest rate(1)         6.08 %       6.08 %  
Short-term debt:                                  
  Fixed rate   $ 265,000             265,000   267,650
  Coupon interest rate     8.00 %           8.00 %  
  Effective interest rate(2)     7.13 %           7.13 %  
Long-term debt:                                  
  Fixed rate   $   285,000     5,822   150,000   750,000   1,190,822   1,208,018
  Coupon interest rate       8.00 %   7.00 % 7.75 % 7.25 % 7.49 %  
  Effective interest rate(2)       7.71 %   7.00 % 6.56 % 7.25 % 7.27 %  

(1)
As of December 31, 2007.

(2)
The effective interest rate on the 8% senior notes due 2008, the 8% senior notes due 2011, and the 73/4% senior notes due 2014 is reduced from the coupon rate as a result of amortization of gains related to the termination of related interest rate swaps.

Interest Rate Swaps

        Forest may enter into interest rate swap agreements in an attempt to normalize the mix of fixed and floating interest rates within its debt portfolio. Unrealized gains, losses, or any settlements are recorded in other income and expense in the Consolidated Statement of Operations. Pursuant to the requirements under the Alaska Credit Agreements, Forest Alaska entered into two floating to fixed interest rate swaps. In August 2007, Forest Alaska novated these interest rate swaps to Forest. Forest has maintained these interest rate swaps to fix a portion of its variable rate interest on its credit facility borrowings that are LIBOR based. As of December 31, 2007, we had entered into the following interest rate swaps:

 
  Term
  Notional Amount
  Floating Rate
  Fixed Rate
  Fair Value
 
 
  (Dollar Amounts in Thousands)

 
Interest Rate Swap A   April 2007 – April 2010   $ 75,000   1 month LIBOR   4.80 % $ (1,726 )
Interest Rate Swap B   April 2007 – April 2010     112,500   1 month LIBOR   4.96 %   (2,995 )

        In January 2008, we entered into a $100 million floating to fixed interest rate swap for three years commencing on June 13, 2008. The floating rate is one month LIBOR and the fixed rate is 2.75%.

Item 8.    Financial Statements and Supplementary Data.

        Information concerning this Item begins on the following page.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Forest Oil Corporation

        We have audited the accompanying consolidated balance sheets of Forest Oil Corporation and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forest Oil Corporation and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

        As discussed in Notes 1 and 7 to the consolidated financial statements, Forest Oil Corporation changed its method of accounting for Share-Based Payments in accordance with Statement of Financial Accounting Standards No. 123 (revised 2004) on January 1, 2006.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forest Oil Corporation's internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2008 expressed an unqualified opinion thereon.

    Ernst & Young LLP

Denver, Colorado
February 27, 2008

 

 

55



Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders
Forest Oil Corporation:

        We have audited the accompanying consolidated statements of operations, shareholders' equity, and cash flows of Forest Oil Corporation and subsidiaries for the year ended December 31, 2005. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

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

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of the operations and cash flows of Forest Oil Corporation and subsidiaries for the year ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

KPMG LLP

Denver, Colorado
March 13, 2006

56



FOREST OIL CORPORATION
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Data)

 
  December 31,
 
  2007
  2006
ASSETS
Current assets:          
  Cash and cash equivalents   $ 9,685   33,164
  Accounts receivable     201,617   125,446
  Derivative instruments     30,006   53,205
  Deferred income taxes     23,854  
  Other investments     34,694  
  Other current assets     61,518   49,185
   
 
    Total current assets     361,374   261,000
Property and equipment, at cost:          
  Oil and gas properties, full cost method of accounting:          
    Proved, net of accumulated depletion of $2,742,539 and $2,265,018     4,414,710   2,486,153
    Unproved     568,510   261,259
   
 
  Net oil and gas properties     4,983,220   2,747,412
  Other property and equipment, net of accumulated depreciation and amortization of $30,011 and $32,504     42,595   42,514
   
 
    Net property and equipment     5,025,815   2,789,926
Derivative instruments       15,019
Goodwill     265,618   86,246
Other assets     42,741   36,881
   
 
    $ 5,695,548   3,189,072
   
 
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:          
  Accounts payable   $ 361,089   224,933
  Accrued interest     7,693   6,235
  Derivative instruments     72,675   1,294
  Current portion of long-term debt     266,002   2,500
  Asset retirement obligations     2,562   2,694
  Deferred income taxes       14,907
  Other current liabilities     28,361   11,378
   
 
    Total current liabilities     738,382   263,941
Long-term debt     1,503,035   1,204,709
Asset retirement obligations     87,943   61,408
Derivative instruments     38,171   811
Deferred income taxes     853,427   191,957
Other liabilities     62,779   32,240
   
 
    Total liabilities     3,283,737   1,755,066
Commitments and contingencies (Note 11)          
Shareholders' equity:          
  Preferred stock, none issued and outstanding      
  Common stock, 88,379,409 and 62,998,155 shares issued and outstanding     8,838   6,300
  Capital surplus     1,966,569   1,215,660
  Retained earnings     306,062   137,796
  Accumulated other comprehensive income     130,342   74,250
   
 
    Total shareholders' equity     2,411,811   1,434,006
   
 
    $ 5,695,548   3,189,072
   
 

See accompanying Notes to Consolidated Financial Statements.

57



FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands, Except
Per Share Amounts)

Revenues   $ 1,083,892   819,992   1,072,045
Operating expenses:              
  Lease operating expenses     167,473   154,874   199,761
  Production and property taxes     55,264   39,041   42,615
  Transportation and processing costs     20,200   21,876   19,499
  General and administrative (including stock-based compensation)     63,751   48,308   43,703
  Depreciation and depletion     390,338   266,881   368,679
  Accretion of asset retirement obligations     6,064   7,096   17,317
  Impairment and other       3,668   11,132
  Gain on sale of assets     (7,176 )  
  Spin-off costs       5,416  
   
 
 
      Total operating expenses     695,914   547,160   702,706
   
 
 
Earnings from operations     387,978   272,832   369,339
Other income and expense:              
  Interest expense     113,162   71,787   61,403
  Unrealized losses (gains) on derivative instruments, net     117,499   (83,629 ) 21,373
  Realized (gains) losses on derivative instruments, net     (75,965 ) 23,864   35,390
  Other expense, net     1,581   3,827   6,247
   
 
 
      Total other income and expense     156,277   15,849   124,413
   
 
 
Earnings before income taxes and discontinued operations     231,701   256,983   244,926
Income tax expense:              
  Current     5,999   2,126   3,498
  Deferred     56,396   88,777   89,860
   
 
 
      Total income tax expense     62,395   90,903   93,358
   
 
 
Earnings from continuing operations     169,306   166,080   151,568
  Income from discontinued operations, net of tax       2,422  
   
 
 
Net earnings   $ 169,306   168,502   151,568
   
 
 
Basic earnings per common share:              
    Earnings from continuing operations   $ 2.22   2.67   2.47
    Income from discontinued operations, net of tax       .04  
   
 
 
    Basic earnings per common share   $ 2.22   2.71   2.47
   
 
 
Diluted earnings per common share:              
    Earnings from continuing operations   $ 2.18   2.62   2.41
    Income from discontinued operations, net of tax       .04  
   
 
 
    Diluted earnings per common share   $ 2.18   2.66   2.41
   
 
 

See accompanying Notes to Consolidated Financial Statements.

58


FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

 
  Common Stock
  Capital
Surplus

  Retained
Earnings

  Accumulated
Other
Comprehensive
(Loss) Income

  Treasury
Stock

  Total
Shareholders'
Equity

 
 
  (In Thousands)

 
Balances at January 1, 2005   61,595   $ 6,159   1,444,367   66,007   6,780   (51,166 ) 1,472,147  
  Exercise of warrants to purchase 1,358,350 shares of common stock   1,358     137   14,248         14,385  
  Exercise of stock options   1,040     104   27,624   (376 )   1,006   28,358  
  Tax benefit of stock options exercised         4,587         4,587  
  Employee stock purchase plan   19     1   633         634  
  Restricted stock issued, net of forfeitures   536     54   (200 ) 94     52    
  Amortization of deferred stock compensation, net of forfeitures and other         1,235         1,235  
  Tax benefit of acquired net operating losses         36,608         36,608  
Comprehensive earnings:                                
  Net earnings           151,568       151,568  
  Reclassification of hedges to earnings, net of tax             144,290     144,290  
  Change in fair value of hedges, net of tax             (180,591 )   (180,591 )
  Increase in unfunded postretirement benefits, net of tax             (210 )   (210 )
  Foreign currency translation             11,511     11,511  
                             
 
  Total comprehensive earnings                             126,568  
   
 
 
 
 
 
 
 
Balances at December 31, 2005   64,548     6,455   1,529,102   217,293   (18,220 ) (50,108 ) 1,684,522  
  Exercise of stock options   289     28   6,019   (8 )   27   6,066  
  Tax benefit of stock options exercised         25         25  
  Employee stock purchase plan   28     4   741         745  
  Restricted stock issued, net of forfeitures   (6 )   (1 )         (1 )
  Retirement of treasury stock   (1,861 )   (186 ) (49,895 )     50,081    
  Amortization of stock-based compensation         20,158         20,158  
  Tax benefit of acquired net operating losses         8,337         8,337  
  Pro rata distribution of MERI common stock to shareholders (Note 2)         (298,827 ) (247,991 ) 7,549     (539,269 )
Comprehensive earnings:                                
  Net earnings           168,502       168,502  
  Reclassification of hedges to earnings, net of tax             50,581     50,581  
  Change in fair value of hedges, net of tax             30,873     30,873  
  Decrease in unfunded postretirement benefits, net of tax             2,333     2,333  
  Foreign currency translation             1,134     1,134  
                             
 
  Total comprehensive earnings                             253,423  
   
 
 
 
 
 
 
 
Balances at December 31, 2006   62,998   $ 6,300   1,215,660   137,796   74,250     1,434,006  
   
 
 
 
 
 
 
 

See accompanying Notes to Consolidated Financial Statements.

59


FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Continued)

 
  Common Stock
  Capital
Surplus

  Retained
Earnings

  Accumulated
Other
Comprehensive
Income

  Total
Shareholders'
Equity

 
 
  (In Thousands)

 
Balances at December 31, 2006   62,998   $ 6,300   1,215,660   137,796   74,250   1,434,006  
  Acquisition of Houston Exploration   23,990     2,399   724,013       726,412  
  Exercise of stock options   652     65   11,720       11,785  
  Employee stock purchase plan   33     3   1,057       1,060  
  Restricted stock issued, net of cancellations   736     74   (74 )      
  Amortization of stock-based compensation         15,504       15,504  
  Adoption of FIN 48           (1,040 )   (1,040 )
  Restricted stock redeemed and other   (30 )   (3 ) (1,311 )     (1,314 )
Comprehensive earnings:                            
  Net earnings           169,306     169,306  
  Decrease in unfunded postretirement benefits, net of tax             1,295   1,295  
  Foreign currency translation             54,797   54,797  
                         
 
  Total comprehensive earnings                         225,398  
   
 
 
 
 
 
 
Balances at December 31, 2007   88,379   $ 8,838   1,966,569   306,062   130,342   2,411,811  
   
 
 
 
 
 
 

See accompanying Notes to Consolidated Financial Statements.

60



FOREST OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

 
  Year Ended December 31,
 
 
  2007
  2006
  2005
 
 
  (In Thousands)

 
Operating activities:                
  Net earnings   $ 169,306   168,502   151,568  
    Adjustments to reconcile net earnings to net cash provided by operating activities:                
      Depreciation and depletion     390,338   266,881   368,679  
      Unrealized losses (gains) on derivative instruments, net     117,499   (83,629 ) 21,373  
      Deferred income tax expense     56,396   90,004   89,860  
      Stock-based compensation expense     10,895   13,240   763  
      Accretion of asset retirement obligations     6,064   7,096   17,317  
      Impairments       3,668   2,924  
      Gain on sale of assets     (7,176 )    
      Unrealized foreign currency exchange (gain) loss     (7,694 ) 3,931    
      Other, net     6,350   5,899   1,111  
      Changes in operating assets and liabilities, net of effects of acquisitions and divestitures:                
        Accounts receivable     353   (640 ) (15,350 )
        Other current assets     1,557   (39,860 ) (25,858 )
        Accounts payable     (9,592 ) 9,200   9,528  
        Accrued interest and other current liabilities     (26,051 ) (21,814 ) 6,650  
   
 
 
 
      Net cash provided by operating activities     708,245   422,478   628,565  
Investing activities:                
  Capital expenditures for property and equipment:                
      Acquisition of Houston Exploration, net of cash acquired (Note 2)     (775,365 )    
      Exploration, development, and other acquisition costs     (787,735 ) (894,448 ) (679,974 )
      Other fixed assets     (32,169 ) (21,950 ) (10,743 )
  Proceeds from sale of Alaska Assets (Note 2)     400,000      
  Proceeds from sales of other assets     102,048   6,507   24,046  
  Other, net         (4,559 )
   
 
 
 
      Net cash used by investing activities     (1,093,221 ) (909,891 ) (671,230 )
Financing activities:                
  Proceeds from bank borrowings     1,536,526   1,562,778   906,741  
  Repayments of bank borrowings     (1,365,178 ) (1,432,574 ) (905,000 )
  Issuance of 71/4% senior notes, net of issuance costs     739,176      
  Repayment of Alaska Credit Agreements     (375,000 )    
  Repayments of bank debt assumed in acquisitions     (176,885 )   (35,000 )
  Proceeds from Alaska Credit Agreements, net of issuance costs       367,706    
  Proceeds from Spin-off       21,670    
  Proceeds from the exercise of options and warrants and from employee stock purchase plan     12,845   6,811   43,377  
  Other, net     (11,932 ) (12,559 ) (14,714 )
   
 
 
 
      Net cash provided (used) by financing activities     359,552   513,832   (4,596 )
Effect of exchange rate changes on cash     1,945   (486 ) (759 )
   
 
 
 
Net (decrease) increase in cash and cash equivalents     (23,479 ) 25,933   (48,020 )
Cash and cash equivalents at beginning of year     33,164   7,231   55,251  
   
 
 
 
Cash and cash equivalents at end of year   $ 9,685   33,164   7,231  
   
 
 
 
Cash paid during the year for:                
  Interest   $ 125,276   76,979   66,140  
  Income taxes     6,445   5,590   7,900  

See accompanying Notes to Consolidated Financial Statements.

61



FOREST OIL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007, 2006, and 2005

(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Description of the Business

        Forest Oil Corporation 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. The Company is active in several of the major exploration and producing areas in the United States and in Canada and has exploratory and development interests in various other foreign countries.

Basis of Presentation and Principles of Consolidation

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

        Certain amounts in prior years' financial statements have been reclassified to conform to the 2007 financial statement presentation.

Assumptions, Judgments, and Estimates

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

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

Cash Equivalents

        The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

Property and Equipment

        The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the Company has operations. During 2007, 2006, and 2005, the Company's primary oil and gas operations were conducted in the United States and Canada.

62


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)


All costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. For the years ended December 31, 2007, 2006, and 2005, Forest capitalized $43.6 million, $31.8 million, and $26.5 million of general and administrative costs, respectively. Interest costs related to significant unproved properties which are under development are also capitalized to oil and gas properties. During 2007, 2006, and 2005, the Company capitalized approximately $13.9 million, $3.7 million, and $.9 million, respectively, of interest expense attributed to unproved properties.

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

        Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and gas assets. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, an impairment charge would be recognized to the extent of the excess capitalized costs. There were no provisions for impairment of proved oil and gas properties in 2007, 2006, or 2005.

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

        Depletion of proved oil and gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserves. Furniture and fixtures, leasehold improvements, computer hardware and software, and other equipment are depreciated on the straight-line or declining balance method, based upon estimated useful lives of the assets ranging from three to 15 years.

Asset Retirement Obligations

        Forest records estimated future asset retirement obligations pursuant to the provisions of Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to its present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest's asset retirement

63


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)


obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

        The following table summarizes the activities for the Company's asset retirement obligations for the years ended December 31, 2007 and 2006:

 
  Year Ended December 31,
 
 
  2007
  2006
 
 
  (In Thousands)

 
Asset retirement obligations at beginning of period   $ 64,102   211,554  
Accretion expense     6,064   7,096  
Liabilities incurred     5,195   3,033  
Liabilities settled     (2,512 ) (6,652 )
Disposition of properties     (17,476 ) (150,182 )
Liabilities assumed     36,424   1,009  
Revisions of estimated liabilities     (3,843 ) (1,687 )
Impact of foreign currency exchange rate     2,551   (69 )
   
 
 
Asset retirement obligations at end of period     90,505   64,102  
Less: current asset retirement obligations     (2,562 ) (2,694 )
   
 
 
Long-term asset retirement obligations   $ 87,943   61,408  
   
 
 

Financial Instruments

        The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, derivative instruments, and accounts receivable. The Company's cash equivalents and derivative instruments are placed with major financial institutions. The Company attempts to minimize credit risk exposure to purchasers of the Company's oil and natural gas through formal credit policies, monitoring procedures, and letters of credit when considered necessary.

        The Company used various assumptions and methods in estimating fair value disclosures for financial instruments. The carrying amounts of cash and cash equivalents and accounts receivable approximated their fair value due to the short maturity of these instruments. The fair values of derivative instruments were based on quoted market prices and option pricing models. The carrying amount of the Company's credit facilities approximated fair value, because the interest rates on the credit facilities are variable. The fair values of the Company's senior notes, senior subordinated notes, and Alaska credit agreements were estimated based on quoted market prices, if available, or quoted

64


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)


market prices of comparable instruments. The carrying values and fair values of the Company's debt instruments (other than its credit facilities) are summarized below for the periods presented:

 
  December 31, 2007
  December 31, 2006
 
  Carrying
Amount

  Fair
Value

  Carrying
Amount

  Fair
Value

 
  (In Thousands)

8% Senior Notes due 2008   $ 266,002   267,650   268,200   271,294
8% Senior Notes due 2011     293,482   296,400   295,610   296,400
7% Senior Subordinated Notes due 2013     5,664   5,618    
73/4% Senior Notes due 2014     159,763   152,250   161,305   152,625
71/4% Senior Notes due 2019     750,000   753,750    
Alaska Credit Agreement—first lien         250,000   251,250
Alaska Credit Agreement—second lien         125,000   130,000

Revenues

Oil and Gas Sales

        Natural gas revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company's net interest. The Company records its entitled share of revenues based on its entitled share of gas proceeds. Since there is a ready market for natural gas, the Company sells the majority of its products soon after production at various locations, including the wellhead, at which time title and risk of loss pass to the buyer.

        Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess of the Company's share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. At December 31, 2007 and 2006, the Company had gas imbalance payables of $8.4 million and $5.6 million, respectively, and gas imbalance receivables of $9.2 million and $5.1 million, respectively.

        Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title is transferred.

        In 2007 and 2005, there were no purchasers who exceeded 10% of total revenue. In 2006, sales to two purchasers were approximately 13% and 12% of total revenue.

Marketing, Processing, and Other

        Marketing, processing, and other primarily consists of marketing fees earned from third party marketing arrangements and fees earned attributable to volumes processed on behalf of third parties through Company-owned gas processing plants.

65


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

Accounts Receivable

        The components of accounts receivable include the following:

 
  December 31,
 
 
  2007
  2006
 
 
  (In Thousands)

 
Oil and gas sales   $ 150,258   89,082  
Joint interest billings     44,810   27,891  
Other     7,011   8,814  
Allowance for doubtful accounts     (462 ) (341 )
   
 
 
  Total accounts receivable   $ 201,617   125,446  
   
 
 

Income Taxes

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

Foreign Currency Translation

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

        During 2007 and 2006, Forest realized approximately $7.7 million and $.3 million, respectively, of foreign currency exchange gains in connection with the repayment of intercompany debt owed to the Forest Oil Corporation by Canadian Forest.

Earnings per Share

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

66


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)


units, and warrants. The following sets forth the calculation of basic and diluted earnings per share for the periods presented:

 
  Year Ended December 31,
 
  2007
  2006
  2005
 
  (In Thousands,
Except Per Share Amounts)

Earnings from continuing operations   $ 169,306   166,080   151,568
Income from discontinued operations, net of tax       2,422  
   
 
 
Net earnings   $ 169,306   168,502   151,568
   
 
 
Weighted average common shares outstanding during the period     76,101   62,226   61,405
Add dilutive effects of stock options, unvested restricted stock grants, and unvested phantom stock units     1,650   1,205   1,145
Add dilutive effects of warrants         328
   
 
 
Weighted average common shares outstanding during the period, including the effects of dilutive securities     77,751   63,431   62,878
   
 
 
Basic earnings per common share:              
  From continuing operations   $ 2.22   2.67   2.47
  From discontinued operations       .04  
   
 
 
  Basic earnings per common share   $ 2.22   2.71   2.47
   
 
 
Diluted earnings per common share:              
  From continuing operations   $ 2.18   2.62   2.41
  From discontinued operations       .04  
   
 
 
  Diluted earnings per common share   $ 2.18   2.66   2.41
   
 
 

Stock-Based Compensation

        Prior to January 1, 2006, the Company accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. Under APB Opinion No. 25, no compensation expense was recognized for stock options issued to employees if the grant price equaled or was above the market price on the date of the option grant. Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123 (Revised), "Share-Based Payment" ("SFAS 123(R)") using the modified prospective method. Under this method, compensation cost is recorded for all unvested stock options, restricted stock, and phantom stock units beginning in the period of adoption and prior period financial statements are not restated. Under the fair value recognition provisions of SFAS 123(R), stock-based compensation is measured at the grant date based on the value of the awards and the value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

Treasury Stock

        In May 2006, Forest retired its treasury stock. The Company had historically accounted for treasury stock acquisitions using the cost method. Under this method, for reissuance of treasury stock, to the extent that the reissuance price was more than the cost, the excess was recorded as an increase to capital surplus. If the reissuance price was less than the cost, the difference was also recorded to capital surplus to the extent there was a cumulative treasury stock paid in capital balance.

67


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

Debt Issue Costs

        Included in other assets are costs associated with the issuance of our senior notes and our revolving bank credit facilities. The remaining unamortized debt issue costs at December 31, 2007 and 2006 totaled $19.7 million and $13.0 million, respectively, and are being amortized over the life of the respective debt instruments. The increase in 2007 includes the debt issue costs associated with the issuance of the $750 million 71/4% senior notes due 2019, in June 2007.

Goodwill

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

        A portion of our goodwill is assigned to the Canadian geographical business segment and normal fluctuations will occur between periods based upon changes in foreign currency exchange rates. During the year ended December 31, 2007, Forest recognized $176.8 million of goodwill associated with the Houston Exploration acquisition, as discussed in Note 2.

Comprehensive Earnings (Loss)

        Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in the Company's other comprehensive income (loss) during the last three years include: foreign currency gains (losses) related to the translation of the assets and liabilities of the Company's Canadian operations; changes in the unfunded postretirement benefits; and unrealized gains (losses) related to the changes in fair value of derivative instruments designated as cash flow hedges.

68


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

        The components of accumulated other comprehensive earnings (loss) for the years ended December 31, 2007, 2006, and 2005 are as follows:

 
  Foreign
Currency
Translation

  Unfunded
Postretirement
Benefits(1)

  Unrealized
Gain (Loss)
on Derivative
Instruments, Net(1)

  Accumulated
Other
Comprehensive
Income (Loss)

 
 
  (In Thousands)

 
Balance at January 1, 2005   $ 67,902   (8,420 ) (52,702 ) 6,780  
2005 activity     11,511   (210 ) (36,301 ) (25,000 )
   
 
 
 
 
Balance at December 31, 2005     79,413   (8,630 ) (89,003 ) (18,220 )
2006 activity     1,134   2,333   89,003   92,470  
   
 
 
 
 
Balance at December 31, 2006     80,547   (6,297 )   74,250  
2007 activity     54,797   1,295     56,092  
   
 
 
 
 
Balance at December 31, 2007   $ 135,344   (5,002 )   130,342  
   
 
 
 
 

(1)
Net of tax.

Impact of Recently Issued Accounting Pronouncements

        In September 2006, the Financial Accounting Standards Board ("FASB") issued SFAS No. 157, "Fair Value Measurements" ("SFAS 157"). This statement clarifies the definition of fair value, establishes a framework for measuring fair value, and expands the disclosures on fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position ("FSP") No. 157-1 and FSP No. 157-2. FSP No. 157-1 amends SFAS 157 to exclude lease transactions accounted for under SFAS No. 13, "Accounting for Leases" ("SFAS 13") and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. This scope exception does not apply to assets acquired and liabilities assumed in a business combination that are required to be measured at fair value under SFAS No. 141, "Business Combinations" or SFAS 141(R), regardless of whether those assets and liabilities are related to leases. FSP No. 157-2 delays the effective date of SFAS 157 for one year for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Company is currently evaluating the impact the adoption of these pronouncements will have on the Company's financial position and results of operations.

        In September 2006, the FASB ratified the consensus reached by the Emerging Issues Task Force ("EITF") related to EITF Issue No. 06-4, "Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements" ("EITF 06-4"), which requires the recognition of a liability for future benefits based on the substantive agreement with the employee. The liability is required to be recognized in accordance with SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("SFAS 106"), or APB Opinion No. 12, "Omnibus Opinion—1967", as appropriate. EITF 06-4 is effective for fiscal years beginning after December 15, 2007 and requires transition through a cumulative effect adjustment to retained earnings or a retrospective application to all prior periods. The Company maintains a number of split-dollar life insurance arrangements for certain former employees. The Company is currently evaluating the impact the adoption of this pronouncement will have on the Company's financial position and results of operations.

69


(1)    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

        In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities" ("SFAS 159"). This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement expands the use of fair value measurement and applies to entities that elect the fair value option. The fair value option established by this Statement permits all entities to choose to measure eligible items at fair value at specified election dates. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of this pronouncement to have a material impact on the Company's financial position or results of operations.

        In March 2007, the FASB ratified the consensus reached by the EITF in Issue No. 06-10, "Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements" ("EITF 06-10"). Under this consensus, an employer should recognize a liability for any postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 or APB Opinion No. 12, as appropriate, and should recognize and measure the underlying asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement. EITF 06-10 is effective for fiscal years beginning after December 15, 2007 and requires transition through a cumulative effect adjustment to retained earnings or a retrospective application to all prior periods. The Company maintains a number of split-dollar life insurance arrangements for certain former employees. The Company is currently evaluating the impact the adoption of this pronouncement will have on the Company's financial position and results of operations.

        In December 2007, the FASB issued SFAS No. 141 (Revised), "Business Combinations" ("SFAS 141(R)"), which significantly changes the financial accounting and reporting of business combination transactions. SFAS 141(R) establishes principles and requirements for how an acquirer in a business combination: (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of this pronouncement may have a material impact on the accounting for any acquisition the Company may make after January 1, 2009.

        In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51" ("SFAS 160"). This statement amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the noncontrolling interest. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The Company does not expect the adoption of this pronouncement to have a material impact on the Company's financial position or results of operations.

70


(2)    ACQUISITIONS AND DIVESTITURES:

Acquisitions

Acquisition of Houston Exploration

        On June 6, 2007, Forest completed the acquisition of The Houston Exploration Company ("Houston Exploration") in a cash and stock transaction totaling approximately $1.5 billion and the assumption of Houston Exploration's debt. Houston Exploration was an independent natural gas and oil producer engaged in the exploration, development, exploitation, and acquisition of natural gas and oil reserves in North America. Houston Exploration had operations in four producing regions within the United States: South Texas, East Texas, the Arkoma Basin of Arkansas, and the Uinta and DJ Basins in the Rocky Mountains. The principal factors considered by management in making the acquisition included the mix of complementary high-quality assets in certain of the Company's existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies. Pursuant to the terms and conditions of the agreement and plan of merger ("Merger Agreement"), Forest paid total merger consideration of $750 million in cash and issued approximately 24 million common shares, valued at $30.28 per share. The per share value of the Forest common shares issued was calculated as the average of Forest's closing share price for a five day period surrounding the announcement date of the acquisition on January 7, 2007. The cash component of the merger consideration was financed from a private placement of $750 million of 71/4% senior notes due 2019 and borrowings under the Company's $1.0 billion second amended and restated credit facilities that were executed on June 6, 2007. Immediately following the completion of the merger, Forest repaid all of Houston Exploration's outstanding bank debt totaling $177 million.

        The acquisition, which was accounted for using the purchase method of accounting, has been included in Forest's Consolidated Financial Statements since June 6, 2007, the date the acquisition closed. The following table represents the preliminary allocation of the total purchase price of Houston Exploration to the acquired assets and liabilities of Houston Exploration as of December 31, 2007. The allocation represents the estimated fair values assigned to each of the assets acquired and liabilities assumed. The purchase price allocation is preliminary, subject to the completion of evaluations of proved and unproved oil and gas properties, deferred income taxes, contractual arrangements, and legal

71


(2)    ACQUISITIONS AND DIVESTITURES: (Continued)


and environmental matters. These and other estimates are subject to change as additional information becomes available and is assessed by Forest.

 
  (In Thousands)
 
Fair value of Houston Exploration's net assets:        
  Net working capital, including cash of $3.5 million   $ (33,551 )
  Proved oil and gas properties     1,741,823  
  Unproved oil and gas properties     448,100  
  Goodwill     176,761  
  Other assets     14,537  
  Derivative instruments     (45,170 )
  Long-term debt     (182,532 )
  Asset retirement obligations     (36,424 )
  Deferred income taxes     (559,136 )
  Other liabilities     (19,099 )
   
 
  Total fair value of net assets   $ 1,505,309  
   
 
Consideration paid for Houston Exploration's net assets:        
  Forest common stock issued   $ 726,412  
  Cash consideration paid     749,694  
   
 
  Aggregate purchase consideration paid to Houston Exploration stockholders     1,476,106  
  Plus:        
    Cash settlement for Houston Exploration stock options     20,075  
    Direct merger costs incurred     9,128  
   
 
  Total consideration paid   $ 1,505,309  
   
 

        Goodwill of $176.8 million has been recognized to the extent that the consideration paid exceeded the fair value of the net assets acquired and has been assigned to the U.S. geographical business segment. Goodwill is not expected to be deductible for tax purposes. The principal factors that contributed to the recognition of goodwill include the mix of complementary high-quality assets in certain of our existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies.

        Included in the working capital assumed at the acquisition date was a severance accrual of $28.9 million for costs to involuntarily terminate employees of Houston Exploration. Management determined it would be necessary to eliminate certain overlapping positions to achieve cost savings through administrative and operational synergies. Management is still finalizing its business integration plans as a result of the acquisition and, accordingly, the severance accrual will be finalized once these

72


(2)    ACQUISITIONS AND DIVESTITURES: (Continued)


plans are complete. The following table summarizes the activity in the severance accrual through December 31, 2007 since the acquisition date:

 
  (In Thousands)
 
Severance accrual at June 6, 2007   $ 28,850  
Cash payments(1)     (11,519 )
Net adjustment(2)     (1,694 )
   
 
Severance accrual at December 31, 2007   $ 15,637  
   
 

(1)
Represents cash severance and excise tax payments to involuntarily terminated employees of Houston Exploration as well as the related employer tax payments paid by the Company.
(2)
Represents the net adjustment made to the accrual as the Company continues to finalize the termination plan. This net adjustment was made to the cost of the acquired company.

        The remaining severance payments are expected to be made during 2008.

        The following summary pro forma combined statement of operations data of Forest for the years ended December 31, 2007 and 2006 has been prepared to give effect to the merger as if the merger had occurred on January 1, 2007 and 2006, respectively. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2007 and 2006, and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors. The pro forma financial information also gives pro forma effect to Forest's spin-off of its offshore Gulf of Mexico operations completed in March 2006 and Houston Exploration's sale of substantially all of its offshore Gulf of Mexico operations completed in June 2006, as though each disposition occurred on January 1, 2006.

 
  Year Ended December 31,
 
  2007
  2006
 
  (In Thousands, Except
Per Share Amounts)

Revenues   $ 1,304,849   1,220,447
Earnings from continuing operations     181,591   172,101
Net earnings     181,591   174,523
Basic earnings per common share:          
  From continuing operations   $ 2.09   2.00
  Basic earnings per common share     2.09   2.02
Diluted earnings per common share:          
  From continuing operations   $ 2.06   1.98
  Diluted earnings per common share     2.06   2.00

Cotton Valley Acquisition

        On March 31, 2006, Forest completed the acquisition of oil and gas properties located primarily in the Cotton Valley trend in East Texas. Forest paid approximately $255 million, as adjusted to reflect an economic effective date of February 1, 2006. Forest funded this acquisition utilizing its bank credit facilities.

73


(2)    ACQUISITIONS AND DIVESTITURES: (Continued)

Buffalo Wallow Acquisition

        On April 1, 2005, Forest purchased a private company whose primary assets were located in the Buffalo Wallow field, primarily in Hemphill and Wheeler Counties, Texas ("the Buffalo Wallow Acquisition"). The purchase price was allocated to assets and liabilities, adjusted for tax effects, based on their estimated fair values at the date of acquisition. The acquisition was accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Forest since the date of acquisition.

        The total cash consideration paid for the Buffalo Wallow Acquisition was allocated as follows:

 
  Purchase Price
Allocation

 
 
  (In Thousands)

 
Current assets   $ 9,434  
Oil and gas properties     305,005  
Goodwill     22,959  
Other assets     68  
Current liabilities     (27,251 )
Derivative liability—current     (6,373 )
Long-term debt     (35,000 )
Asset retirement obligations     (705 )
Deferred income taxes     (71,492 )
   
 
Total cash consideration   $ 196,645  
   
 

        Goodwill of $23.0 million was recognized to the extent that cost exceeded the fair value of net assets acquired. Goodwill is not expected to be deductible for tax purposes. The goodwill was assigned to Forest's U.S. geographical business segment. The principal factors that contributed to the recognition of goodwill include the mix of complementary high-quality assets in one of our existing core areas, lower-risk exploitation opportunities, expected increased cash flow from operations available for investing activities, and opportunities for cost savings through administrative and operational synergies.

Divestitures

Sale of Alaska Assets

        On August 27, 2007, Forest sold all of its assets located in Alaska (the "Alaska Assets") to Pacific Energy Resources Ltd. ("PERL"). The total consideration received for the Alaska Assets included $400 million in cash, 10 million shares of PERL common stock (subject to certain restrictions), and a zero coupon senior subordinated note from PERL due 2014 in the principal amount at stated maturity of $60.8 million. A portion of the cash consideration, $269 million, was applied to prepay all amounts due under the term loan agreements, including accrued interest and prepayment premiums. Consideration received by Forest in the form of the PERL common stock and the zero coupon senior subordinated note are being held in other investments within the Consolidated Balance Sheet. Forest accounts for these investments as trading securities in accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Investments in debt and equity securities classified as trading securities are recorded at fair value with unrealized gains and losses recognized in "Other income and expense" in the Consolidated Statements of Operations.

74


(2)    ACQUISITIONS AND DIVESTITURES: (Continued)

Spin-off and Merger 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 special 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 approximately 50.6 million 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 a tax-free transaction for federal income tax purposes. Prior to the Merger, as part of the Spin-off, MERI paid Forest $176.1 million. The $176.1 million was drawn on a newly created bank credit facility established by MERI immediately prior to the Spin-off. This credit facility and associated liability were included in the Spin-off. Subsequent to the closing, Forest received additional net cash proceeds of $21.7 million from MERI for a total of $197.8 million. In accordance with the transaction agreements, Forest and MERI had submitted post-closing adjustments from which Forest paid MERI a total of $5.8 million during 2007. Additional adjustments to the cash amount may occur pending the resolution of certain accounting matters that are the subject of ongoing arbitration between Forest and MERI. The arbitration is currently expected to be concluded in the second half of 2008.

        The table below sets forth the assets and liabilities included in the Spin-off (in thousands):

  Working capital   $ (12,383 )
  Proved oil and gas properties, net of accumulated depletion     1,033,289  
  Unproved oil and gas properties     38,523  
  Other assets     7,919  
  Derivative instruments     (17,087 )
  MERI credit facility     (176,102 )
  Asset retirement obligations     (150,182 )
  Deferred income taxes     (184,483 )
  Other liabilities     (225 )
  Accumulated other comprehensive income     7,549  
   
 
Net decrease to capital surplus and retained earnings   $ 546,818  
   
 

        The following table presents the revenues and direct operating expenses of the offshore Gulf of Mexico operations reported in the Consolidated Statements of Operations for all periods presented. As

75


(2)    ACQUISITIONS AND DIVESTITURES: (Continued)


the spin-off of the offshore Gulf of Mexico operations were concluded in 2006, the Company did not have operating activity from offshore Gulf of Mexico operations during 2007.

 
  Year Ended December 31,
 
  2006
  2005
 
  (In Thousands)

Revenues   $ 46,289   392,272
Oil and gas production expense:          
  Lease operating expenses     18,296   78,524
  Transportation and processing costs     344   3,383
  Production and property taxes     151   2,215
   
 
Revenues in excess of direct operating expenses   $ 27,498   308,150
   
 

Sale of ProMark

        On March 1, 2004, the Company sold the assets and business operations of Producers Marketing, Ltd. ("ProMark") to Cinergy Canada, Inc. ("Cinergy") for $11.2 million CDN. As a result of the sale, ProMark's results of operations were reported as discontinued operations in the historical financial statements. Under the terms of the purchase and sale agreement, Forest may receive additional contingent consideration over a period of five years through February 2009. During the years ended December 31, 2007 and 2005, Forest did not receive any additional contingent payments. During the year ended December 31, 2006, Forest received an additional $3.6 million contingent payment ($2.4 million net of tax) under the agreement, which has been reflected as income from discontinued operations in the Consolidated Statements of Operations.

Other Divestitures

        During the year ended December 31, 2007, Forest sold properties in addition to the Alaska Assets for total proceeds of $39.4 million, including an overriding royalty interest in Australia for net proceeds of $7.2 million that resulted in a gain on the sale of $7.2 million. In addition, in August 2007, the Company entered into a sale-leaseback transaction whereby the Company sold its drilling rigs for cash proceeds of $62.6 million and simultaneously entered into an operating lease with the buyer which provides for monthly rental payments of $.9 million for a term of seven years. A deferred gain of $33.3 million resulted from the sale of the drilling rigs and will be amortized over the term of the lease.

76


(3)    PROPERTY AND EQUIPMENT:

        Net property and equipment at December 31, 2007 and 2006 consists of the following:

 
  2007
  2006
 
 
  (In Thousands)

 
Oil and gas properties:            
Proved   $ 7,157,249   4,751,171  
Unproved     568,510   261,259  
Accumulated depletion     (2,742,539 ) (2,265,018 )
   
 
 
  Net oil and gas properties     4,983,220   2,747,412  
Other property and equipment:            
Furniture and fixtures, computer hardware and software, and other equipment     72,606   75,018  
Accumulated depreciation and amortization     (30,011 ) (32,504 )
   
 
 
  Net other property and equipment     42,595   42,514  
   
 
 
Total net property and equipment   $ 5,025,815   2,789,926  
   
 
 

        The following table sets forth a summary of oil and gas property costs not being depleted at December 31, 2007, by the year in which such costs were incurred:

 
  Total
  2007
  2006
  2005
  2004 and Prior
 
  (In Thousands)

United States:                      
  Acquisition costs   $ 382,531   357,849   18,836   985   4,861
  Exploration costs     63,418   27,061   26,907   8,117   1,333
   
 
 
 
 
  Total United States     445,949   384,910   45,743   9,102   6,194
Canada:                      
  Acquisition costs     25,512       4,142   21,370
  Exploration costs     38,439   20,495   13,568   65   4,311
   
 
 
 
 
  Total Canada     63,951   20,495   13,568   4,207   25,681
International:                      
  Acquisition costs     740         740
  Exploration costs     57,870   1,911   5,151   1,360   49,448
   
 
 
 
 
  Total International     58,610   1,911   5,151   1,360   50,188
   
 
 
 
 
Total   $ 568,510   407,316   64,462   14,669   82,063
   
 
 
 
 

        The majority of the United States and Canada unproved oil and gas property costs, or those not being depleted, relate to oil and gas property acquisitions discussed in Note 2 as well as work-in-progress on various exploration projects. The Company expects that substantially all of its unproved property costs in the U.S. and Canada as of December 31, 2007 will be reclassified to proved properties within five years. Forest also holds interests in various projects located outside North America. Costs related to these international interests of $58.6 million are not being depleted pending determination of the existence of estimated proved reserves. Forest's exploration project in South Africa accounts for the majority of the international costs not being amortized. In 2007, the Company continued to pursue commercial development of the Ibhubesi field discovery in South Africa. The Company also filed a production right application and also continued efforts toward securing gas contracts for the Ibhubesi field.

77


(4)    DEBT:

        Components of debt are as follows:

 
  December 31, 2007
  December 31, 2006
 
 
  Principal
  Unamortized Premium (Discount)
  Other(3)
  Total
  Principal
  Unamortized Premium (Discount)
  Other(3)
  Total
 
 
  (In Thousands)

 
U.S. Credit Facility   $ 165,000       165,000   23,000       23,000  
Canadian Credit Facility     129,126       129,126   84,094       84,094  
Alaska Credit Agreements(1)             375,000       375,000  
8% Senior Notes due 2008     265,000   (48