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FOREST OIL CORPORATION INDEX TO FORM 10-Q June 30, 2004



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


FORM 10-Q

(Mark One)  

ý

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

For the quarterly period ended June 30, 2004

Or

o

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

For the transition period from N/A to N/A

Commission File Number 1-13515

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

New York   25-0484900
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

1600 Broadway Suite 2200 Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

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


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

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

        As of July 31, 2004 there were 58,930,591 shares of common stock, par value $.10 per share, outstanding.





FOREST OIL CORPORATION
INDEX TO FORM 10-Q
June 30, 2004

Part I—FINANCIAL INFORMATION
 
Item 1—Financial Statements
   
Condensed Consolidated Balance Sheets
   
Condensed Consolidated Statements of Production and Operations
   
Condensed Consolidated Statements of Cash Flows
   
Notes to Condensed Consolidated Financial Statements
 
Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
 
Item 3—Quantitative and Qualitative Disclosures about Market Risk
 
Item 4—Controls and Procedures

Part II—OTHER INFORMATION
 
Item 1—Legal Proceedings
 
Item 4—Submission of Matters to a Vote of Security Holders
 
Item 6—Exhibits and Reports on Form 8-K

Signatures

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS


FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

 
  June 30, 2004
  December 31, 2003
 
 
  (In Thousands)

 
ASSETS            
Current assets:            
  Cash and cash equivalents   $ 52,188   11,509  
  Accounts receivable     157,723   158,954  
  Derivative instruments     4,300   4,130  
  Current deferred tax asset     38,407   23,302  
  Other current assets     25,038   17,465  
   
 
 
    Total current assets     277,656   215,360  
Net property and equipment     2,778,591   2,433,966  
Assets held for sale related to discontinued operations       8,589  
Goodwill     64,357    
Other assets     27,319   25,633  
   
 
 
    $ 3,147,923   2,683,548  
   
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY            
Current liabilities:            
  Accounts payable   $ 200,460   192,001  
  Accrued interest     5,102   3,869  
  Derivative instruments     88,112   49,838  
  Asset retirement obligation     24,746   23,243  
  Other current liabilities     6,042   4,158  
   
 
 
    Total current liabilities     324,462   273,109  
Long-term debt     1,084,469   929,971  
Asset retirement obligation     215,908   188,189  
Other liabilities     51,195   33,758  
Deferred income taxes     150,910   72,723  
Shareholders' equity:            
  Common stock     6,089   5,563  
  Capital surplus     1,423,234   1,302,340  
  Accumulated deficit     (9,336 ) (56,495 )
  Accumulated other comprehensive loss     (43,661 ) (9,740 )
  Treasury stock, at cost     (55,347 ) (55,870 )
   
 
 
    Total shareholders' equity     1,320,979   1,185,798  
   
 
 
    $ 3,147,923   2,683,548  
   
 
 

See accompanying notes to condensed consolidated financial statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF PRODUCTION AND OPERATIONS

(Unaudited)

 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
 
  2004
  2003
  2004
  2003
 
 
  (In Thousands Except Per Share Amounts)

 
SALES VOLUMES                    
Natural gas (MMCF)     25,235   22,769   49,646   45,839  
   
 
 
 
 
Oil, condensate and natural gas liquids (thousands of barrels)     2,558   2,260   5,003   4,335  
   
 
 
 
 
STATEMENTS OF CONSOLIDATED OPERATIONS                    
Revenue:                    
  Oil and gas sales:                    
    Natural gas   $ 131,153   99,870   255,215   213,828  
    Oil, condensate and natural gas liquids     76,735   53,705   146,510   107,947  
   
 
 
 
 
      Total oil and gas sales     207,888   153,575   401,725   321,775  
  Processing income, net     590   670   1,006   542  
   
 
 
 
 
      Total revenue     208,478   154,245   402,731   322,317  
Operating expenses:                    
  Oil and gas production     54,691   35,512   114,020   70,712  
  General and administrative     8,169   9,745   14,529   18,307  
  Depreciation and depletion     83,474   51,211   163,102   99,502  
  Accretion of asset retirement obligation     4,153   3,147   8,428   6,267  
  Impairment of oil and gas properties     1,690   135   1,690   135  
   
 
 
 
 
      Total operating expenses     152,177   99,750   301,769   194,923  
   
 
 
 
 
Earnings from operations     56,301   54,495   100,962   127,394  
   
 
 
 
 
Other income and expense:                    
  Other (income) expense, net     (1,133 ) 2,779   (1,557 ) 6,664  
  Interest expense     13,084   12,490   26,031   25,450  
   
 
 
 
 
      Total other income and expense     11,951   15,269   24,474   32,114  
   
 
 
 
 
Earnings before income taxes, discontinued operations, and cumulative effect of change in accounting principle     44,350   39,226   76,488   95,280  
Income tax expense:                    
  Current     157   361   868   414  
  Deferred     16,063   15,328   27,853   37,073  
   
 
 
 
 
      16,220   15,689   28,721   37,487  
   
 
 
 
 
Earnings from continuing operations     28,130   23,537   47,767   57,793  
Loss from discontinued operations (net of tax)       (125 ) (575 ) (1,364 )
Cumulative effect of change in accounting principle for recording asset retirement obligation (net of tax)           5,854  
   
 
 
 
 
Net earnings   $ 28,130   23,412   47,192   62,283  
   
 
 
 
 
Weighted average number of common shares outstanding:                    
  Basic     55,437   48,188   54,560   48,024  
   
 
 
 
 
  Diluted     56,437   49,068   55,594   48,901  
   
 
 
 
 
Basic earnings per common share:                    
  Earnings from continuing operations   $ 0.51   0.49   0.88   1.20  
  Loss from discontinued operations (net of tax)         (0.01 ) (0.02 )
  Cumulative effect of change in accounting principle (net of tax)           0.12  
   
 
 
 
 
  Net earnings per common share   $ 0.51   0.49   0.87   1.30  
   
 
 
 
 
Diluted earnings per common share:                    
  Earnings from continuing operations   $ 0.50   0.48   0.86   1.18  
  Loss from discontinued operations (net of tax)         (0.01 ) (0.03 )
  Cumulative effect of change in accounting principle (net of tax)           0.12  
   
 
 
 
 
  Net earnings per common share   $ 0.50   0.48   0.85   1.27  
   
 
 
 
 

See accompanying notes to condensed consolidated financial statements.

2



FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 
  Six Months Ended
June 30,

 
 
  2004
  2003
 
 
  (In Thousands)

 
Cash flows from operating activities:            
Net earnings before cumulative effect of change in accounting principle   $ 47,192   56,429  
  Adjustments to reconcile net earnings before cumulative effect of change in accounting principle to net cash provided by operating activities:            
    Depreciation and depletion     163,102   100,206  
    Accretion of asset retirement obligation     8,428   6,267  
    Impairment of oil and gas properties     1,690   135  
    Amortization of deferred hedge gain     (2,453 ) (2,202 )
    Amortization of deferred debt costs     1,404   1,121  
    Unrealized loss on derivative instruments, net     (217 ) 127  
    Deferred income tax expense     28,574   38,243  
    Loss on extinguishment of debt       3,975  
    Loss (earnings) in equity method investee     (1,310 ) 1,580  
    Other, net       (174 )
    (Increase) decrease in accounts receivable     24,251   (22,720 )
    (Increase) decrease in other current assets     (5,046 ) 624  
    Decrease in accounts payable     (23,318 ) (9,867 )
    Increase (decrease) in accrued interest and other current liabilities     898   (10,897 )
   
 
 
      Net cash provided by operating activities     243,195   162,847  
Cash flows from investing activities:            
  Acquisition of subsidiary     (167,968 )  
  Capital expenditures for property and equipment:            
    Exploration, development and other acquisition costs     (163,603 ) (166,102 )
    Other fixed assets     (1,229 ) (1,202 )
  Proceeds from sales of assets     8,510   65  
  Sale of goodwill and contract value     8,493    
  Decrease (increase) in other assets, net     1,168   (1,112 )
   
 
 
      Net cash used by investing activities     (314,629 ) (168,351 )
Cash flows from financing activities:            
  Proceeds from bank borrowings     493,490   321,000  
  Repayments of bank borrowings     (500,000 ) (275,000 )
  Repurchases of 101/2% senior subordinated notes       (69,441 )
  Proceeds of common stock offering, net of offering costs     117,143   20,968  
  Proceeds from the exercise of options and warrants     4,541   4,152  
  Purchase of treasury stock     42    
  (Increase) decrease in other liabilities, net     (2,608 ) 126  
   
 
 
      Net cash provided by financing activities     112,608   1,805  
Effect of exchange rate changes on cash     (495 ) 754  
   
 
 
Net increase (decrease) in cash and cash equivalents     40,679   (2,945 )
Cash and cash equivalents at beginning of period     11,509   13,166  
   
 
 
Cash and cash equivalents at end of period   $ 52,188   10,221  
   
 
 
Cash paid during the period for:            
  Interest   $ 26,703   29,877  
  Income taxes   $ 2,993   1,562  

See accompanying notes to condensed consolidated financial statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND SIX MONTHS ENDED JUNE 30, 2004 AND 2003

(Unaudited)

(1) BASIS OF PRESENTATION

        The condensed consolidated financial statements included herein are unaudited. The consolidated financial statements include the accounts of Forest Oil Corporation and its consolidated subsidiaries (collectively, Forest or the Company). In the opinion of management, all adjustments, consisting of normal recurring accruals, have been made which are necessary for a fair presentation of the financial position of Forest at June 30, 2004 and the results of operations for the three and six months ended June 30, 2004 and 2003. Quarterly results are not necessarily indicative of expected annual results because of the impact of fluctuations in prices received for liquids (oil, condensate and natural gas liquids) and natural gas and other factors.

        In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amount 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 initially 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.

        Certain amounts in the prior year financial statements have been reclassified to conform to the 2004 financial statement presentation. As a result of the Company's fourth quarter 2003 decision to sell the gas marketing business of its Canadian marketing subsidiary, Producers Marketing Ltd. (ProMark), ProMark's results of operations have been presented as discontinued operations in the accompanying statements of operations. In prior years' financial statements, ProMark's marketing revenue, net of related expenses, was reported in processing income, net.

        For a more complete understanding of Forest's operations, financial position and accounting policies, reference is made to the consolidated financial statements of Forest, and related notes thereto, filed with Forest's annual report on Form 10-K for the year ended December 31, 2003, previously filed with the Securities and Exchange Commission.

(2) ACQUISITIONS

        On June 25, 2004, Forest completed its tender offer for all of the common stock of The Wiser Oil Company (Wiser) with oil and gas assets located in the Company's Canadian, Western and Gulf Coast business units (the Wiser Acquisition). The acquisition also included working capital and certain other financial assets and liabilities of Wiser. The purchase price was allocated to assets and liabilities, adjusted for tax effects, based on the fair values at the date of acquisition. The acquisition was accounted for using the purchase method of accounting and has been included in the consolidated financial statements of Forest since the date of acquisition.

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        The cash consideration paid for Wiser was allocated as follows:

 
  (In Thousands)
 
Current assets   $ 25,969  
Proved properties     301,210  
Other plant and equipment assets     2,450  
Undeveloped leasehold costs     45,803  
Goodwill     64,357  
Current liabilities     (35,858 )
Derivative liability—short-term     (8,028 )
Long-term debt     (163,325 )
Asset retirement obligation     (7,997 )
Other liabilities     (3,061 )
Deferred taxes     (53,552 )
   
 
  Net cash consideration   $ 167,968  
   
 

        Goodwill of $64,357,000 has been 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 principal factors that contributed to the recognition of goodwill are as follows:

addition of significant reserves and producing assets in Forest's core areas, primarily the Canadian and Western U.S. business units.

opportunities for cost savings through administrative and operational synergies.

addition of significant Gulf Coast and Canadian exploration acreage.

The allocation of the purchase price is preliminary because certain items such as the determination of the final tax basis and the fair value of certain assets and liabilities as of the acquisition date have not been finalized.

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

5



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

 
  Pro Forma
 
  Three Months Ended
June 30,

  Six Months Ended
June 30,

 
  2004
  2003
  2004
  2003
 
  (In Thousands Except Per Share Amounts)

Total revenue   $ 243,311   230,137   465,961   477,044
Net earnings from continuing operations     30,604   28,379   46,691   85,518
Net earnings     30,604   28,254   46,116   90,008
Basic earnings per share     .55   .48   .85   1.55
Diluted earnings per share     .54   .48   .83   1.52

(3) EARNINGS PER SHARE AND COMPREHENSIVE EARNINGS (LOSS)

Earnings (Loss) per Share:

        Basic earnings per share is computed by dividing net earnings attributable to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares.

        Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options and warrants.

        The following sets forth the calculation of basic and diluted earnings per share:

 
  Three Months
Ended June 30,

  Six Months
Ended June 30,

 
  2004(1)
  2003(2)
  2004(3)
  2003(4)
 
  (In Thousands Except Per Share Amounts)

Earnings from continuing operations   $ 28,130   23,537   47,767   57,793
   
 
 
 
Weighted average common shares outstanding during the period     55,437   48,188   54,560   48,024
  Add dilutive effects of stock options     281   208   301   210
  Add dilutive effects of warrants     719   672   733   667
   
 
 
 
Weighted average common shares outstanding including the effects of dilutive securities     56,437   49,068   55,594   48,901
   
 
 
 
Basic earnings per share from continuing operations   $ 0.51   0.49   0.88   1.20
   
 
 
 
Diluted earnings per share from continuing operations   $ 0.50   0.48   0.86   1.18
   
 
 
 

(1)
For the three months ended June 30, 2004, options to purchase 1,545,450 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2006 to 2014.

6


(2)
For the three months ended June 30, 2003, options to purchase 2,428,075 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2013.

(3)
For the six months ended June 30, 2004, options to purchase 1,539,950 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2006 to 2014.

(4)
For the six months ended June 30, 2003, options to purchase 2,949,275 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2013.

Comprehensive Earnings (Loss):

        Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in the Company's other comprehensive income (loss) for the three and six months ended June 30, 2004 and 2003 are foreign currency gains (losses) related to the translation of the assets and liabilities of the Company's Canadian operations; unrealized gains (losses) related to the change in fair value of securities available for sale; and unrealized gains (losses) related to the change in fair value of derivative instruments designated as cash flow hedges.

        The components of comprehensive (loss) earnings are as follows:

 
  Three Months
Ended June 30,

  Six Months
Ended June 30,

 
 
  2004
  2003
  2004
  2003
 
 
  (In Thousands Except Per Share Amounts)

 
Net earnings   $ 28,130   23,412   47,192   62,283  
Other comprehensive income (loss)                    
  Foreign currency translation (losses) gains     (4,327 ) 21,507   (7,369 ) 37,932  
  Unrealized loss on derivative instruments, net     (4,707 ) (1,492 ) (27,433 ) (8,319 )
  Unrealized gain on securities available for sale     875   346   881   781  
   
 
 
 
 
Total comprehensive earnings   $ 19,971   43,773   13,271   92,677  
   
 
 
 
 

(4) STOCK-BASED COMPENSATION

        The Company applies APB Opinion 25, Accounting for Stock Issued to Employees, and related Interpretations to account for its stock-based compensation plans. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common

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stock. Compensation cost is recognized over the vesting period of options granted at a price less than the fair market value of the common stock at the date of the grant. No compensation cost is recognized for stock purchase rights that qualify under Section 423 of the Internal Revenue Code as a non-compensatory plan. Had compensation cost for the Company's stock-based compensation plans been determined using the fair value of the options at the grant date as prescribed by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the Company's pro forma net earnings and earnings per common share would be as follows:

 
  Three Months
Ended June 30,

  Six Months
Ended June 30,

 
  2004
  2003
  2004
  2003
 
  (In Thousands Except Per Share Amounts)

Net earnings:                  
  As reported   $ 28,130   23,412   47,192   62,283
   
 
 
 
  Pro forma   $ 25,171   19,643   41,577   55,506
   
 
 
 
Basic earnings per share:                  
  As reported   $ 0.51   0.49   0.87   1.30
   
 
 
 
  Pro forma   $ 0.45   0.41   0.76   1.16
   
 
 
 
Diluted earnings per share:                  
  As reported   $ 0.50   0.48   0.85   1.27
   
 
 
 
  Pro forma   $ 0.45   0.40   0.75   1.14
   
 
 
 

(5) NET PROPERTY AND EQUIPMENT

        Components of net property and equipment are as follows:

 
  June 30, 2004
  December 31, 2003
 
 
  (In Thousands)

 
Oil and gas properties   $ 5,248,925   4,748,477  
Furniture and fixtures, computer hardware and software     34,774   32,640  
   
 
 
      5,283,699   4,781,117  
Less accumulated depreciation, depletion and valuation allowance     (2,505,108 ) (2,347,151 )
   
 
 
    $ 2,778,591   2,433,966  
   
 
 

(6) ASSET RETIREMENT OBLIGATIONS

        The Company records estimated future asset retirement obligations pursuant to the provisions of Statement of Financial Accounting Standards 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

8



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 liability is required to be accreted each period to present value. Capitalized costs are depleted as a component of the full cost pool using the units of production method. The Company's asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

        The following table summarizes the activity for the Company's asset retirement obligation for the six months ended June 30, 2004 and 2003:

 
  Six Months Ended
 
 
  June 30, 2004
  June 30, 2003
 
 
  (In Thousands)

 
Asset retirement obligation at beginning of period   $ 211,432    
Liability recognized in transition       155,972  
Accretion     8,428   6,267  
Liabilities incurred     10,025   2,893  
Liabilities assumed     7,997    
Liabilities settled     (913 ) (5,798 )
Revisions in estimated liabilities     3,898    
Impact of foreign currency exchange     (213 ) 985  
   
 
 
Asset retirement obligation at end of period     240,654   160,319  
Less: current asset retirement obligation at end of period     (24,746 ) (14,357 )
   
 
 
Long-term asset retirement obligation at end of period   $ 215,908   145,962  
   
 
 

(7) PROMARK SALE

        On March 1, 2004, the assets and business operations of the Company's Canadian marketing subsidiary, ProMark, were sold to Cinergy Canada, Inc. (Cinergy) for approximately $11,200,000 CDN. Under the terms of the purchase and sale agreement, Cinergy will market natural gas on behalf of the Company's Canadian exploration and production subsidiary, Canadian Forest Oil Ltd., for five years, unless subject to prior contractual commitments, and will also administer the netback pool formerly administered by ProMark. Forest could receive additional contingent payments over the next five years if Cinergy meets certain earnings goals with respect to the acquired business.

9



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

 
  December 31, 2003
 
 
  (In Thousands)

 
Goodwill   $ 17,680  
Long-term gas marketing contracts     15,425  
   
 
      33,105  
Less accumulated amortization and valuation allowance     (24,516 )
   
 
    $ 8,589  
   
 

        The components of loss from discontinued operations for the three months ended June 30, 2003 and the six months ended June 30, 2004 and 2003 are as follows:

 
  Three Months Ended June 30,
  Six Months Ended June 30,
 
 
  2003
  2004
  2003
 
 
  (In Thousands)

 
Marketing revenue, net   $ 604   597   1,276  
General and administrative expense     (429 ) (280 ) (758 )
Interest expense     (1 ) (2 ) (1 )
Other (expense) income     5   (166 ) 5  
Depreciation     (365 )   (704 )
Current income tax expense     (7 ) (2 ) (12 )
Deferred income tax benefit (expense)     68   (722 ) (1,170 )
   
 
 
 
Loss from discontinued operations   $ (125 ) (575 ) (1,364 )
   
 
 
 

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(8) LONG-TERM DEBT

        Components of long-term debt are as follows:

 
  June 30, 2004
  December 31, 2003
 
  Principal
  Unamortized
Discount

  Other
  Total
  Principal
  Unamortized
Discount

  Other
  Total
 
  (In Thousands)

U.S. Credit Facility   $ 316,000       316,000   291,000       291,000
Canadian Credit Facility             1,542       1,542
Bank debt assumed in acquisition     36,354(3 )     36,354   30,000 (2)     30,000
8% Senior Notes Due 2008     265,000   (390 ) 9,111 (1) 273,721   265,000   (439 ) 10,258 (1) 274,819
8% Senior Notes Due 2011     160,000     6,253 (1) 166,253   160,000     6,671 (1) 166,671
73/4% Senior Notes Due 2014     150,000   (2,348 ) 17,518 (1) 165,170   150,000   (2,467 ) 18,406 (1) 165,939
91/2% Senior Subordinated Notes assumed in acquisition(4).     125,000     1,971 (5) 126,971        
   
 
 
 
 
 
 
 
    $ 1,052,354   (2,738 ) 34,853   1,084,469   897,542   (2,906 ) 35,335   929,971
   
 
 
 
 
 
 
 

(1)
Represents the unamortized portion of gains realized upon termination of interest rate swaps that were accounted for as fair value hedges. The gains are being amortized as a reduction of interest expense over the terms of the note issues.

(2)
Paid in January 2004 with borrowings under the Company's U.S. credit facility.

(3)
Paid in July 2004 with borrowings under the Company's U.S. credit facility.

(4)
Redeemed in July 2004 with borrowings under the Company's U.S. credit facility.

(5)
Represents the premium paid upon redemption. The premium was recorded through purchase accounting in connection with the Wiser Acquisition.

        In July 2004, Forest issued $125,000,000 principal amount of 8% Senior Notes due 2011 at 107.75% of par for proceeds of $133,313,000 (net of related offering costs). Net proceeds from this offering were used to reduce the balance outstanding under Forest's U.S. credit facility.

(9) EMPLOYEE BENEFITS

        The following table sets forth the components of the net periodic cost of the Company's defined benefit pension plans and post retirement benefits in the United States for the three and six months ended June 30, 2004 and 2003:

 
  Pension Benefits
  Postretirement Benefits
  Pension Benefits
  Postretirement Benefits
 
  Three Months Ended June 30,
  Three Months Ended June 30,
  Six Months Ended June 30,
  Six Months Ended June 30,
 
  2004
  2003
  2004
  2003
  2004
  2003
  2004
  2003
 
  (In Thousands)

  (In Thousands)

  (In Thousands)

  (In Thousands)

Service cost   $     158   133   $     316   266
Interest cost     431   454   138   131     832   908   276   262
Expected return on plan assets     (381 ) (341 )       (762 ) (682 )  
Recognized actuarial loss     173   182   12       346   364   24  
   
 
 
 
 
 
 
 
Total net periodic expense   $ 223   295   308   264   $ 416   590   616   528
   
 
 
 
 
 
 
 

11


(10) FINANCIAL INSTRUMENTS

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

Interest Rate Swaps:

        In prior years, the Company entered into interest rate swaps as fair value hedges of fixed rate debt. The swaps were intended to exchange the fixed interest rates on the notes for variable rates over the terms of the notes. The Company terminated these interest rate swaps. The aggregate gains were deferred and added to the carrying value of the related debt, and are being amortized as a reduction of interest expense over the remaining terms of the notes. During the three months ended June 30, 2004 and 2003, the Company recognized reductions of interest expense of $1,226,878 and $1,107,069, respectively, related to the terminated interest rate swaps. During the six months ended June 30, 2004 and 2003, the reductions of interest expense were $2,453,756 and $2,214,138, respectively.

Commodity Swaps, Collars and Basis Swaps:

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

        With the exception of certain derivative instruments related to the Wiser Acquisition, all of the Company's commodity swaps and collar agreements and a portion of its basis swaps in place at June 30, 2004 have been designated as cash flow hedges. At June 30, 2004, the Company had a derivative asset of $6,219,000 (of which $4,300,000 was classified as current), a derivative liability of $114,910,000 (of which $88,112,000 was classified as current), a deferred tax asset of $38,579,000 (of which $29,126,000 was classified as current) and accumulated other comprehensive loss of $99,782,000 ($62,569,000 net of tax).

12



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

 
  Three Months Ended June 30,
  Six Months Ended June 30,
 
 
  2004
  2003
  2004
  2003
 
 
  (In Thousands)

 
Derivatives designated as cash flow hedges   $ (30,211 ) (18,089 ) (49,662 ) (53,446 )
Derivatives not designated as cash flow hedges     1,716   (127 ) 1,201   (89 )
   
 
 
 
 
  Total loss   $ (28,495 ) (18,216 ) (48,461 ) (53,535 )
   
 
 
 
 

        In a typical swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon, published third-party index if the index price is lower. If the index price is higher, Forest pays the difference. By entering into swap agreements the Company effectively fixes the price that it will receive in the future for the hedged production. Forest's current swaps are settled in cash on a monthly basis. As of June 30, 2004, Forest had entered into the following swaps accounted for as cash flow hedges:

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs Per Day
  Average Hedged Price Per MMBTU
  Barrels Per Day
  Average Hedged Price Per BBL
Third Quarter 2004   157.3   $ 5.19   13,850   $ 28.30
Fourth Quarter 2004   117.5   $ 5.24   9,850   $ 29.60
First Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Second Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Third Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Fourth Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
First Quarter 2006   30.0   $ 5.47   4,000   $ 31.58

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

        Collars are also settled in cash, either on a monthly basis or at the end of their terms. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged

13



production. As of June 30, 2004, the Company had entered into the following natural gas collars accounted for as cash flow hedges:

 
  Natural Gas
 
  BBTUs per Day
  Average Floor MMBTU Price per
  Average Ceiling Price per MMBTU
Third Quarter 2004   10.0   $ 5.50   $ 6.25
Fourth Quarter 2004   16.6   $ 5.30   $ 6.76
First Quarter 2005   20.0   $ 5.25   $ 6.89

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

        As of June 30, 2004, Forest had entered into the following 3-way gas and oil collars accounted for as cash flow hedges:

 
  Natural Gas
 
  BBTU's Per Day
  Average Lower Floor
Price Per MBTU

  Average Upper Floor
Price Per MMBTU

  Average Ceiling Price Per MMBTU
Third Quarter 2004   25.0   $ 3.50   $ 4.75   $ 5.80
Fourth Quarter 2004   11.7   $ 3.50   $ 4.75   $ 6.14

 


 

Oil (NYMEX WTI)

 
  Barrels Per Day
  Average Lower Floor
Price Per Barrel

  Average Upper Floor
Price Per Barrel

  Average Ceiling Price Per Barrel
First Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Second Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Third Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Fourth Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00

The Company also uses basis swaps in connection with natural gas swaps in order to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. At June 30, 2004 there were basis swaps designated as cash flow hedges in place with weighted average volumes of 29.0 BBTUs per day for the remainder of 2004. At June 30, 2004 there were basis swaps

14


not designated as cash flow hedges in place with weighted average volumes of 91.7 BBTUs per day for the remainder of 2004 and weighted average volumes of 72.5 BBTUs per day for 2005.

        Forest has the following swap agreements as a result of the Wiser Acquisition. These swap agreements were not designated as cash flow hedges by Wiser but were designated as cash flow hedges by Forest on July 15, 2004.

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs Per Day
  Average Hedged
Price Per MMBTU

  Barrels Per Day
  Average Hedged
Price Per BBL

Third Quarter 2004   10.0   $ 4.85   2,000   $ 28.23
Fourth Quarter 2004   10.0   $ 4.85   1,000   $ 29.60

        Forest also has the following collar agreements as a result of the Wiser Acquisition. These collar agreements cannot be designated as cash flow hedges by Forest under generally accepted accounting principles because the collars had unrealized losses at the date of the Wiser Acquisition.

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs
Per Day

  Average Floor Price per MMBTU
  Average Ceiling Price per MMBTU
  Barrels
Per Day

  Average Floor
Price per BBL

  Average Ceiling
Price per BBL

Third Quarter 2004   15.0   $ 4.35   $ 5.48          
Fourth Quarter 2004   5.0   $ 5.50   $ 7.40          
First Quarter 2005   5.0   $ 5.50   $ 8.00   1,000   $ 32.00   $ 35.30

        In addition, Forest has call derivative instruments as a result of the Wiser Acquisition. Call derivative instruments require the Company to pay the difference between the actual market price and the call price only if the actual market price is above the call price. If the actual market price is equal to or below the call price, the Company does not pay or receive any settlement amount. Calls are speculative arrangements and are not cash flow hedges under generally accepted accounting principles. The Company has the following oil calls as a result of the Wiser Acquisition.

 
  Oil (NYMEX WTI)
 
  Barrels Per Day
  Average Hedged
Price Per Barrel

Third Quarter 2004   1,000   $ 31.25
Fourth Quarter 2004   1,000   $ 33.00

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

(11) COMMON STOCK OFFERING

        In June 2004, Forest issued 5.0 million shares of common stock at a price of $24.40 per share. Net proceeds from this offering were approximately $117.4 million after deducting underwriting discounts

15



and commissions and estimated offering expenses. The net proceeds from the offering were used to fund a portion of the Wiser Acquisition.

(12) BUSINESS AND GEOGRAPHICAL SEGMENTS

        Segment information has been prepared in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. At June 30, 2004, Forest had five reportable segments consisting of oil and gas operations in five business units (Gulf Coast, Western United States, Alaska, Canada and International). On March 1, 2004, the assets and business operations of the Company's gas marketing subsidiary, ProMark, were sold to Cinergy, as discussed in Note 7. Accordingly, in conjunction with the Company's fourth quarter 2003 decision to sell the gas marketing business of ProMark, ProMark's results of operations have been reported as discontinued operations and the segment reporting for 2003 has been restated to exclude the marketing activities of ProMark. The Company's remaining processing activities are not significant and therefore are not reported as a separate segment, but are included as a reconciling item in the information below. The segments were determined based upon the type of operations in each business unit and geographical location of each. The segment data presented below was prepared on the same basis as the consolidated financial statements.

16



Three Months Ended June 30, 2004

 
  Oil and Gas Operations
 
  Gulf Coast
  Western
  Alaska
  Total U.S.
  Canada
  Int'l
  Total
Company

 
  (In Thousands)

Revenue   $ 137,222   33,977   17,069   188,268   19,620     207,888
Expenses:                              
  Oil and gas production     30,484   9,521   11,425   51,430   3,261     54,691
  General and administrative     2,202   584   929   3,715   674     4,389
  Depletion     52,369   6,569   15,322   74,260   8,327     82,587
  Accretion of asset retirement obligation     3,340   298   367   4,005   148     4,153
  Impairment of oil and gas properties               1,690   1,690
   
 
 
 
 
 
 
Earnings from operations   $ 48,827   17,005   (10,974 ) 54,858   7,210   (1,690 ) 60,378
   
 
 
 
 
 
 
Capital expenditures:                              
  Acquisitions   $ 80,148   163,513     243,661   109,791     353,452
  Exploration costs     21,740   979   852   23,571   2,711   1,004   27,286
  Development costs     47,421   12,674   1,641   61,736   2,726     64,462
   
 
 
 
 
 
 
      Total capital expenditures(1)   $ 149,309   177,166   2,493   328,968   115,228   1,004   445,200
   
 
 
 
 
 
 
Property and equipment, net   $ 1,347,039   578,819   379,436   2,305,294   408,387   56,516   2,770,197
   
 
 
 
 
 
 
Goodwill(2)   $ 16,102   35,472     51,574   12,783     64,357
   
 
 
 
 
 
 

(1)
Does not include estimated discounted asset retirement obligations of $15.1 million related to assets placed in service during the three months ended June 30, 2004.

(2)
Represents a preliminary allocation of goodwill to business units.

        Information for reportable segments relates to the Company's June 30, 2004 consolidated totals as follows:

 
  (In Thousands)
 
Earnings from operations for reportable segments   $ 60,378  
Processing income, net     590  
Corporate general and administrative expense     (3,780 )
Administrative asset depreciation     (887 )
Other income, net     1,133  
Interest expense     (13,084 )
   
 
Earnings before income taxes, discontinued operations and cumulative effect of change in accounting principle   $ 44,350  
   
 

17


Six Months Ended June 30, 2004

 
  Oil and Gas Operations
 
  Gulf Coast
  Western
  Alaska
  Total U.S.
  Canada
  Int'l
  Total
Company

 
  (In Thousands)

Revenue   $ 261,442   69,189   34,028   364,659   37,066     401,725
Expenses:                              
  Oil and gas production     63,046   18,562   25,642   107,250   6,770     114,020
  General and administrative     3,849   945   1,778   6,572   1,484     8,056
  Depletion     100,169   13,841   31,226   145,236   16,109     161,345
  Accretion of asset retirement obligation     6,866   590   725   8,181   247     8,428
Impairment of oil and gas properties               1,690   1,690
   
 
 
 
 
 
 
Earnings from operations   $ 87,512   35,251   (25,343 ) 97,420   12,456   (1,690 ) 108,186
   
 
 
 
 
 
 
Capital expenditures:                              
  Acquisitions   $ 89,072   164,706     253,778   109,791     363,569
  Exploration costs     44,823   1,840   1,382   48,045   6,842   2,525   57,412
  Development costs     54,399   18,927   3,503   76,829   6,807     83,636
   
 
 
 
 
 
 
      Total capital expenditures(1)   $ 188,294   185,473   4,885   378,652   123,440   2,525   504,617
   
 
 
 
 
 
 
Property and equipment, net   $ 1,347,039   578,819   379,436   2,305,294   408,387   56,516   2,770,197
   
 
 
 
 
 
 
Goodwill(2)   $ 16,102   35,472     51,574   12,783     64,357
   
 
 
 
 
 
 

(1)
Does not include estimated discounted asset retirement obligations of $21.9 million related to assets placed in service during the six months ended June 30, 2004.

(2)
Represents a preliminary allocation of goodwill to business units.

        Information for reportable segments relates to the Company's June 30, 2004 consolidated totals as follows:

 
  (In Thousands)
 
Earnings from operations for reportable segments   $ 108,186  
Processing income, net     1,006  
Corporate general and administrative expense     (6,473 )
Administrative asset depreciation     (1,757 )
Other expense, net     1,557  
Interest expense     (26,031 )
   
 
Earnings before income taxes, discontinued operations and cumulative effect of change in accounting principle   $ 76,488  
   
 

18


Three Months Ended June 30, 2003

 
  Oil and Gas Operations
 
  Gulf Coast
  Western
  Alaska
  Total U.S.
  Canada
  Int'l
  Total
Company

 
  (In Thousands)

Revenue   $ 94,888   22,936   21,488   139,312   14,263     153,575
Expenses:                              
  Oil and gas production     17,178   5,559   9,680   32,417   3,095     35,512
  General and administrative     2,812   732   1,251   4,795   1,348     6,143
  Depletion     31,778   4,092   7,594   43,464   6,913     50,377
  Accretion of asset retirement obligation     2,250   220   536   3,006   141     3,147
  Impairment of oil and gas properties               135   135
   
 
 
 
 
 
 
Earnings from operations   $ 40,870   12,333   2,427   55,630   2,766   (135 ) 58,261
   
 
 
 
 
 
 
Capital expenditures:                              
  Acquisitions   $ 18,403   3,620     22,023       22,023
  Exploration costs     7,951   727   1,016   9,694   10,585   1,738   22,017
  Development costs     30,112   7,112   11,182   48,406   905     49,311
   
 
 
 
 
 
 
      Total capital expenditures(1)   $ 56,466   11,459   12,198   80,123   11,490   1,738   93,351
   
 
 
 
 
 
 
Property and equipment, net   $ 928,600   258,247   418,998   1,605,845   281,383   69,741   1,956,969
   
 
 
 
 
 
 

(1)
Does not include estimated discounted asset retirement obligations of $2.0 million related to assets placed in service during the three months ended June 30, 2003.

        Information for reportable segments relates to the Company's June 30, 2003 consolidated totals as follows:

 
  (In Thousands)
 
Earnings from operations for reportable segments   $ 58,261  
Processing income, net     670  
Corporate general and administrative expense     (3,602 )
Administrative asset depreciation     (834 )
Other expense, net     (2,779 )
Interest expense     (12,490 )
   
 
Earnings before income taxes, discontinued operations and cumulative effect of change in accounting principle   $ 39,226  
   
 

19


Six Months Ended June 30, 2003

 
  Oil and Gas Operations
 
  Gulf Coast
  Western
  Alaska
  Total U.S.
  Canada
  Int'l
  Total
Company

 
  (In Thousands)

Revenue   $ 202,506   51,163   36,437   290,106   31,669     321,775
Expenses:                              
  Oil and gas production     32,241   11,621   20,655   64,517   6,195     70,712
  General and administrative     5,477   1,446   2,710   9,633   2,667     12,300
  Depletion     62,898   8,423   13,569   84,890   13,006     97,896
  Accretion of asset retirement obligation     4,499   440   1,072   6,011   256     6,267
  Impairment of oil and gas properties               135   135
   
 
 
 
 
 
 
Earnings from operations   $ 97,391   29,233   (1,569 ) 125,055   9,545   (135 ) 134,465
   
 
 
 
 
 
 
Capital expenditures:                              
  Acquisitions   $ 18,470   3,620     22,090       22,090
  Exploration costs     21,173   1,235   2,405   24,813   14,442   2,136   41,391
  Development costs     46,023   13,513   38,094   97,630   4,991     102,621
   
 
 
 
 
 
 
    Total capital expenditures(1)   $ 85,666   18,368   40,499   144,533   19,433   2,136   166,102
   
 
 
 
 
 
 
Property and equipment, net   $ 928,600   258,247   418,998   1,605,845   281,383   69,741   1,956,969
   
 
 
 
 
 
 

(1)
Does not include estimated discounted asset retirement obligations of $2.9 million related to assets placed in service during the six months ended June 30, 2003.

        Information for reportable segments relates to the Company's June 30, 2003 consolidated totals as follows:

 
  (In Thousands)
 
Earnings from operations for reportable segments   $ 134,465  
Processing income, net     542  
Corporate general and administrative expense     (6,007 )
Administrative asset depreciation     (1,606 )
Other expense, net     (6,664 )
Interest expense     (25,450 )
   
 
Earnings before income taxes, discontinued operations and cumulative effect of change in accounting principle   $ 95,280  
   
 

20


Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        The following discussion and analysis should be read in conjunction with Forest's Condensed Consolidated Financial Statements and Notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Factors, and—Critical Accounting Policies, Estimates, Judgments and Assumptions" included in Forest's 2003 Annual Report on Form 10-K. Unless the context otherwise indicates, references in this quarterly report on Form 10-Q to "Forest," "Company," "we," "ours," "us" or like terms refer to Forest Oil Corporation and its subsidiaries.

Forward-Looking Statements

        This Form 10-Q 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 or present facts, that address activities, events, outcomes and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Forest cautions that these forward-looking statements, including without limitation those relating to estimates of our future natural gas and liquids production, including estimates of any increases in oil and gas production, our outlook on oil and gas prices, estimates of our oil and gas reserves, estimates of asset retirement obligations, planned capital expenditures and availability of capital resources to fund capital expenditures, 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, are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil and gas, many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures and other risks as described in Management's Discussion and Analysis of Financial Condition and Results of Operations in Forest's 2003 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. The financial results of our foreign operations are also subject to currency exchange rate risks. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Forest's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements express or implied 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-Q with the Securities and Exchange Commission, except as required by law.

Second Quarter 2004 Overview

        Highlights of the second quarter of 2004 included better production performance of approximately 41 BCFE versus approximately 36 BCFE in the second quarter of 2003 and 39 BCFE in the first quarter of 2004, led by strong results from the Gulf Coast drilling program. Our revenue was significantly higher, primarily as a result of higher sales volumes and higher oil and gas prices. General and administrative expense in the second quarter of 2004 decreased 16% to approximately $8.2 million compared to $9.7 million in the corresponding 2003 period primarily as a result of corporate-wide cost reduction measures.

21



        Our second quarter 2004 results reflect decreased oil and gas production expense on both an absolute and per-unit basis when compared to the first quarter of 2004. For the second quarter of 2004 total oil and gas production expense was approximately $55 million or $1.34 per MCFE compared to approximately $59 million or $1.52 per MCFE in the first quarter of 2004.

        On June 25, 2004, Forest completed its tender offer for all of the common stock of The Wiser Oil Company (Wiser), acquiring oil and gas assets located in our Canadian, Western and Gulf Coast business units (the Wiser Acquisition). The acquisition also included working capital and certain other financial assets and liabilities of Wiser. 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.

Results of Operations for the Three Months Ended June 30, 2004

        Net earnings for the second quarter of 2004 were $28.1 million compared to net earnings of $23.4 million in the second quarter of 2003. The increase in earnings was due primarily to increases in production and product prices, offset partially by higher depreciation and depletion expense.

22



Oil and Gas Sales

        Sales volumes, weighted average sales prices and oil and gas sales revenue for the second quarter of 2004 and 2003 were as follows:

 
  Three Months Ended June 30
 
 
  2004
  2003
  % Change
 
Natural Gas                
Sales volumes (MMCF):                
  United States     21,975   19,821      
  Canada     3,260   2,948      
   
 
     
  Total     25,235   22,769   11 %
  Sales price received (per MCF)   $ 5.81   4.96      
  Effects of energy swaps and collars (per MCF)(1)     (.61 ) (0.57 )    
   
 
     
  Average sales price (per MCF)   $ 5.20   4.39   18 %
Liquids                
Oil and condensate:                
  Sales volumes (MBBLS)     2,315   2,034      
  Sales price received (per BBL)   $ 37.23   26.81      
  Effects of energy swaps and collars (per BBL)(1)     (6.39 ) (2.52 )    
   
 
     
  Average sales price (per BBL)   $ 30.84   24.29      
Natural gas liquids:                
  Sales volumes (MBBLS)     243   226      
  Average sales price (per BBL)   $ 21.96   19.07      
Total liquids sales volumes (MBBLS):                
  United States     2,323   2,000      
  Canada     235   260      
   
 
     
    Total     2,558   2,260   13 %
  Average sales price (per BBL)   $ 30.00   23.76   26 %
Total Sales Volumes (MMCFE)                
  United States     35,913   31,821      
  Canada     4,670   4,508      
   
 
     
    Total     40,583   36,329   12 %
Average sales price (per MCFE)(1)   $ 5.12   4.23   21 %
Total Oil and Gas Sales (in thousands)                
  Natural gas   $ 131,153   99,870      
  Oil, condensate and natural gas liquids     76,735   53,705      
   
 
     
    Total   $ 207,888   153,575   35 %
   
 
     

(1)
Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 14,009 MMCF and 12,740 MMCF in the second quarter of 2004 and 2003, respectively. Hedged oil volumes were 1,169,350 barrels and 1,228,500 barrels in the second quarter of 2004 and 2003, respectively. These arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the effective portion of the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net losses related to our cash flow hedges were $30,211,000 and $18,089,000 in the second quarter of 2004 and 2003, respectively. Average sales prices have been adjusted to reflect effects of energy swaps and collars. Derivative instruments that are not designated as cash flow hedges for accounting purposes are recorded as other income or expense.

23


        The increase in oil and gas sales revenue in the second quarter of 2004 compared to the second quarter of 2003 was the result of increased price realizations for both oil and gas combined with higher sales volumes. The increase in our sales volumes was due primarily to acquisitions of producing properties made in the fourth quarter of 2003.

Oil and Gas Production Expense

        Oil and gas production expense increased in the quarter ended June 30, 2004 compared to the corresponding 2003 period. The increase was attributable primarily to properties acquired in the fourth quarter of 2003. The components of oil and gas production expense were as follows:

 
  Three Months Ended June 30,
 
 
  2004
  Per Mcfe
  2003
  Per Mcfe
  % Change in cost
 
 
  (In Thousands Except Per Mcfe Amounts)

 
Direct operating expense   $ 39,511   0.97   27,634   0.77   43 %
Workovers     4,807   0.11        
Product transportation     3,458   0.09   2,648   0.07   31 %
Production and ad valorem taxes     6,915   0.17   5,230   0.14   32 %
   
 
 
 
 
 
  Total oil and gas production expense   $ 54,691   1.34   35,512   0.98   54 %
   
 
 
 
 
 

        Oil and gas production expense includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of expensed workovers, product transportation costs from the wellhead to the sales point and production and ad valorem taxes. Direct operating expenses were higher in the three months ended June 30, 2004 than in the corresponding prior year period due to the acquisition of properties with higher lease operating expense than our base properties. Workovers included approximately $4 million for well repairs on acquired properties in the Gulf Coast.

General and Administrative Expense; Overhead

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

 
  Three Months Ended June 30,
 
 
  2004
  2003
  % Change
 
 
  (In Thousands)

 
Overhead costs capitalized   $ 5,984   5,832   3 %
General and administrative costs expensed     8,169   9,745   (16 )%
   
 
 
 
  Total overhead costs   $ 14,153   15,577   (9 )%
   
 
 
 

        The decrease in total overhead costs and general and administrative expense in the second quarter of 2004 resulted primarily from cost reduction measures in corporate areas.

24



Depreciation and Depletion

        Depreciation and depletion expense for the three months ended June 30, 2004 and 2003 was as follows:

 
  Three Months Ended June 30,
 
 
  2004
  2003
  % Change
 
 
  (In Thousands)

 
Depreciation and depletion expense   $ 83,474   51,211   63 %
   
 
 
 
Depletion expense per MCFE   $ 2.04   1.39   47 %
   
 
 
 

        The increases in depletion expense and in the per-unit depletion rate in the three months ended June 30, 2004 compared to the same period of 2003 were due primarily to downward revisions in estimated proved reserves in the fourth quarter of 2003.

Accretion of Asset Retirement Obligation

        Accretion expense of approximately $4.2 million and $3.1 million in the second quarter of 2004 and 2003, respectively, was related to the accretion of Forest's asset retirement obligation pursuant to Statement of Financial Accounting Standards No. 143 (SFAS No. 143), adopted January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Using a cumulative effect approach, in the first quarter of 2003 Forest recorded an increase to net property and equipment of approximately $102.3 million (net of tax), an asset retirement obligation liability of approximately $96.5 million (net of tax) and an after tax credit of approximately $5.9 million for the cumulative effect of the change in accounting principle.

Other Income and Expense

        Other income of $1.1 million reported in the second quarter of 2004 consisted primarily of franchise taxes, offset by Forest's share of the net income recorded by Cook Inlet Pipeline Company (an equity method investee in which Forest owns a 40% interest) and realized and unrealized gains on derivative instruments. In the three months ended June 30, 2003, other expense of $2.8 million consisted primarily of Forest's share of the net loss recorded by Cook Inlet Pipeline Company.

Interest Expense

        Interest expense of $13.1 million in the three months ended June 30, 2004 increased slightly compared to the same period of 2003. Higher average debt balances were partially offset by lower average interest rates on variable and fixed rate debt and by amortization of gains recognized on termination of interest rate swaps.

Current and Deferred Income Tax Expense

        Forest recorded current income tax expense of $157,000 in the three months ended June 30, 2004 compared to $361,000 in the comparable period of 2003.

        Deferred income tax expense was $16.1 million in the three months ended June 30, 2004 compared to $15.3 million in the comparable period of 2003. The increase was primarily attributable to higher pre-tax profitability.

25



Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary, Producers Marketing Inc. (ProMark), were sold to Cinergy Canada, Inc. (Cinergy) for $11.2 million CDN. As a result of Forest's fourth quarter 2003 decision to sell its gas marketing operations, ProMark's results of operations have been reported as discontinued operations in the consolidated statements of operations for all periods prior to March 1, 2004. The components of loss from discontinued operations for the three months ended June 30, 2003 are as follows:

 
  Three Months Ended
June 30, 2003

 
 
  (In Thousands)

 
Marketing revenue, net   $ 604  
General and administrative expense     (429 )
Interest expense     (1 )
Other (expense) income     5  
Depreciation     (365 )
Current income tax expense     (7 )
Deferred income tax expense     68  
   
 
Loss from discontinued operations   $ (125 )
   
 

Results of Operations for the Six Months Ended June 30, 2004

        Net earnings for the first six months of 2004 were approximately $47.2 million compared to net earnings of approximately $62.3 million in the first six months of 2003. The decrease in earnings was due primarily to increases in depreciation and depletion expense caused primarily by downward revisions in estimated proved reserves in the fourth quarter of 2003.

26



Oil and Gas Sales

        Sales volumes, weighted average sales prices and oil and gas sales revenue for the first six months of 2004 and 2003 were as follows:

 
  Six Months Ended June 30
 
 
  2004
  2003
  % Change
 
Natural Gas                
Sales volumes (MMCF):                
  United States     43,249   39,986      
  Canada     6,397   5,853      
   
 
     
  Total     49,646   45,839   8 %
  Sales price received (per MCF)   $ 5.60   5.48      
  Effects of energy swaps and collars (per MCF)(1)     (.46 ) (0.82 )    
   
 
     
  Average sales price (per MCF)   $ 5.14   4.66   10 %
Liquids                
Oil and condensate:                
  Sales volumes (MBBLS)     4,575   3,869      
  Sales price received (per BBL)   $ 35.62   29.50      
  Effects of energy swaps and collars (per BBL)(1)     (5.88 ) (4.08 )    
   
 
     
  Average sales price (per BBL)   $ 29.74   25.42      
Natural gas liquids:                
  Sales volumes (MBBLS)     428   466      
  Average sales price (per BBL)   $ 24.42   20.57      
Total liquids sales volumes (MBBLS):                
  United States     4,541   3,807      
  Canada     462   528      
   
 
     
    Total     5,003   4,335   15 %
  Average sales price (per BBL)   $ 29.28   24.90   18 %
Total Sales Volumes (MMCFE)                
  United States     70,495   62,828      
  Canada     9,169   9,021      
   
 
     
    Total     79,664   71,849   11 %
Average sales price (per MCFE)(1)   $ 5.04   4.48   13 %
Total Oil and Gas Sales (in thousands)                
  Natural gas   $ 255,215   213,828      
  Oil, condensate and natural gas liquids     146,510   107,947      
   
 
     
    Total   $ 401,725   321,775   25 %
   
 
     

(1)
Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 30,905 MMCF and 24,860 MMCF in the first six months of 2004 and 2003, respectively. Hedged oil volumes were 2,429,700 barrels and 2,443,500 barrels in the first six months of 2004 and 2003, respectively. These arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the effective portion of the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net losses related to our cash flow hedges were $49,662,000 and $53,446,000 in the first six months of 2004 and 2003, respectively. Average sales prices have been adjusted to reflect effects of energy swaps and collars. Derivative instruments that are not designated as cash flow hedges for accounting purposes are recorded as other income or expense.

27


        The increase in oil and gas sales revenue in the first six months of 2004 compared to the first six months of 2003 was the result of increased price realizations for both oil and gas combined with higher sales volumes. The increase in our sales volumes was due primarily to acquisitions of producing properties made in the fourth quarter of 2003.

Oil and Gas Production Expense

        Oil and gas production expense increased in the first six months of June 30, 2004 compared to the corresponding 2003 period. The increase was attributable primarily to properties acquired in the fourth quarter of 2003. The components of oil and gas production expense were as follows:

 
  Six Months Ended June 30,
 
 
  2004
  Per Mcfe
  2003
  Per Mcfe
  % Change
in cost

 
 
  (In Thousands Except Per Mcfe Amounts)

 
Direct operating expense   $ 82,159   1.03   54,914   0.76   50 %
Workovers     11,107   .14   957   0.01   1,061 %
Product transportation     7,103   .09   5,132   0.07   38 %
Production and ad valorem taxes     13,651   .17   9,709   0.14   41 %
   
 
 
 
 
 
  Total oil and gas production expense   $ 114,020   1.43   70,712   0.98   61 %
   
 
 
 
 
 

        Oil and gas production expense includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of expensed workovers, product transportation costs from the wellhead to the sales point and production and ad valorem taxes. Direct operating expenses were higher in the six months ended June 30, 2004 compared to the corresponding prior year period due to the acquisition of properties with higher lease operating expense than our base properties. Workovers included repairs on wells in Alaska and the Gulf Coast.

General and Administrative Expense; Overhead

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

 
  Six Months Ended June 30,
 
 
  2004
  2003
  % Change
 
 
  (In Thousands)

 
Overhead costs capitalized   $ 11,831   10,929   8 %
General and administrative costs expensed     14,529   18,307   (21 )%
   
 
 
 
  Total overhead costs   $ 26,360   29,236   (10 )%
   
 
 
 

        The decrease in total overhead costs and general and administrative expense in the first six months of 2004 resulted primarily from cost reduction measures in corporate areas.

28



Depreciation and Depletion

        Depreciation and depletion expense for the six months ended June 30, 2004 and 2003 was as follows:

 
  Six Months Ended June 30,
 
 
  2004
  2003
  % Change
 
 
  (In Thousands)

 
Depreciation and depletion expense   $ 163,102   99,502   64 %
   
 
     
Depletion expense per MCFE   $ 2.03   1.36   49 %
   
 
     

        The increases in depletion expense and in the per-unit depletion rate in the six months ended June 30, 2004 compared to the same period of 2003 were due primarily to downward revisions in estimated proved reserves in the fourth quarter of 2003.

Accretion of Asset Retirement Obligation

        Accretion expense of approximately $8.4 million and $6.3 million in the first six months of 2004 and 2003, respectively, was related to the accretion of Forest's asset retirement obligation pursuant to Statement of Financial Accounting Standards No. 143 (SFAS No. 143), adopted January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Using a cumulative effect approach, in the first quarter of 2003 Forest recorded an increase to net property and equipment of approximately $102.3 million (net of tax), an asset retirement obligation liability of approximately $96.5 million (net of tax) and an after tax credit of approximately $5.9 million for the cumulative effect of the change in accounting principle.

Other Income and Expense

        Other income of $1.6 million reported in the second quarter of 2004 primarily consisted of Forest's share of the net income recorded by the Cook Inlet Pipeline Company, realized and unrealized gains on derivative instruments, and collection of accounts receivable previously written off and proceeds of a litigation settlement related to our former properties in Australia, offset partially by franchise tax expense. In the six months ended June 30, 2003, other expense of $6.7 million consisted primarily of a loss on early extinguishment of debt of approximately $4 million related to Forest's redemption in January 2003 of its remaining 101/2% Senior Subordinated Notes at 105.25% of par value, and Forest's share of the net loss recorded by the Cook Inlet Pipeline Company.

Interest Expense

        Interest expense of $26.0 million in the six months ended June 30, 2004 increased slightly compared to the same period of 2003. Higher average debt balances were partially offset by lower average interest rates on variable and fixed rate debt and by amortization of gains recognized on termination of interest rate swaps.

Current and Deferred Income Tax Expense

        Forest recorded current income tax expense of $868,000 in the six months ended June 30, 2004 compared to $414,000 in the comparable period of 2003.

        Deferred income tax expense was $27.9 million in the six months ended June 30, 2004 compared to $37.1 million in the comparable period of 2003. The decrease was attributable primarily to lower pre-tax profitability.

29


Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary, Producers Marketing Inc. (ProMark), were sold to Cinergy Canada, Inc. (Cinergy) for $11.2 million CDN. As a result of Forest's fourth quarter 2003 decision to sell its gas marketing operations, ProMark's results of operations have been reported as discontinued operations in the consolidated statements of operations for all periods prior to March 1, 2004. The components of loss from discontinued operations for the six months ended June 30, 2004 and 2003 are as follows:

 
  Six Months Ended June 30,
 
 
  2004
  2003
 
 
  (In Thousands)

 
Marketing revenue, net   $ 597   1,276  
General and administrative expense     (280 ) (758 )
Interest expense     (2 ) (1 )
Other (expense) income     (166 ) 5  
Depreciation       (704 )
Current income tax expense     (2 ) (12 )
Deferred income tax expense     (722 ) (1,170 )
   
 
 
Loss from discontinued operations   $ (575 ) (1,364 )
   
 
 

Liquidity and Capital Resources

        Liquidity is a measure of a company's ability to access cash. We have historically addressed our long-term liquidity requirements through the use of bank credit facilities and cash provided by operating activities as well as through the issuance of debt and equity securities, when market conditions permit. The prices we receive for future oil and natural gas production and the level of production have significant impacts on operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production.

        We continually examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, preferred stock or other equity securities, sales of non-strategic assets, prospects and technical information and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

        Working Capital.    Working capital is the amount by which current assets exceed current liabilities. It is not unusual for Forest to have deficits in working capital, exclusive of the effects of derivatives and abandonment liabilities, at the end of a period. Such working capital deficits are principally the result of accounts payable related to exploration and development costs. Settlement of these payables is funded by cash flow from operations or, if necessary, by drawdowns on bank credit facilities.

        Forest had a working capital surplus, exclusive of the after-tax effects of derivatives and abandonment liabilities, of approximately $28.5 million at June 30, 2004 compared to a deficit of approximately $11.8 million at December 31, 2003. The change was due primarily to an increase in cash on hand at the end of the quarter as a result of cash borrowed under our credit facility to be used to fund repayments of Wiser's bank debt.

        Cash Flow.    Historically, one of our primary sources of capital has been net cash provided by operating activities. Net cash provided by operating activities, net cash used by investing activities and

30



net cash provided by financing activities for the six months ended June 30, 2004 and 2003 were as follows:

 
  Six Months Ended June 30,
 
 
  2004
  2003
  % Change
 
 
  (In Thousands)

 
Net cash provided by operating activities   $ 243,195   162,847   49 %
Net cash used by investing activities   $ (314,629 ) (168,351 ) 87 %
Net cash provided by financing activities   $ 112,608   1,805   6,139 %

        The increase in net cash provided by operating activities in the six months ended June 30, 2004 compared to the comparable period of 2003 was due primarily to higher realized oil and gas prices as well as increased production. The increase in cash used by investing activities in the six months ended June 30, 2004 was due primarily to the Wiser Acquisition on June 25, 2004, partially offset by slightly lower capital spending and the sale of the gas marketing operations of ProMark and other assets. Net cash provided by financing activities in the six months ended June 30, 2004 included net proceeds from the issuance of common stock of $117.1 million and $4.5 million in proceeds from the exercise of options and warrants, partially offset by net bank repayments of $6.5 million. The 2003 period included cash used for the repurchases of the 101/2% Senior Subordinated Notes of $69.4 million offset by net bank debt borrowings of $46.0 million and net proceeds from the issuance of common stock and the exercise of options and warrants of approximately $25.1 million.

        At June 30, 2004, net debt (long-term debt minus cash) increased $112 million to $1.03 billion compared to $918 million at December 31, 2003. The increase was primarily due to cash paid and debt assumed in the acquisition of Wiser, offset partially by cash flow in excess of capital expenditures for the quarter and proceeds from an equity offering in June 2004.

31



        Capital Expenditures.    Expenditures for property acquisition, exploration and development were as follows:

 
  Six Months Ended June 30,
 
  2004
  2003
 
  (In Thousands)

Property acquisition costs:          
  Proved properties   $ 317,523   22,090
  Undeveloped properties     46,046  
   
 
      363,569   22,090
Exploration costs:          
  Direct costs     51,317   34,942
  Overhead capitalized     6,095   6,449
   
 
      57,412   41,391
Development costs:          
  Direct costs     77,900   98,141
  Overhead capitalized     5,736   4,480
   
 
      83,636   102,621
   
 
Total capital expenditures for property development, acquisition and exploration(1)   $ 504,617   166,102
   
 

(1)
Does not include estimated discounted asset retirement obligations of $21.9 million and $2.9 million related to assets placed in service during the six months ended June 30, 2004 and 2003, respectively.

        Forest's anticipated expenditures for exploration and development in 2004 are estimated to range from $310 million to $330 million. We intend to meet our 2004 capital expenditure financing requirements using cash flows generated by operations, sales of assets and, if necessary, borrowings under bank credit facilities. There can be no assurance, however, that we will have access to sufficient capital to meet these capital requirements. The planned levels of capital expenditures could be reduced if we experience lower than anticipated net cash provided by operations or develop other needs for liquidity, or could be increased if we have increased cash flow or experience exploration success.

        In addition, while we intend to continue a strategy of acquiring reserves that meet our investment criteria, no assurance can be given that we can locate or finance any property acquisitions.

        Bank Credit Facilities.    We have credit facilities totaling $600 million, consisting of a $500 million U.S. credit facility through a syndicate of banks led by JPMorgan Chase and a $100 million Canadian credit facility through a syndicate of banks led by JPMorgan Chase Bank, Toronto Branch. The credit facilities mature in October 2005.

        Currently, the amount available under the credit facilities is governed by a borrowing base (Global Borrowing Base). Effective July 30, 2004, the Global Borrowing Base was set at $500 million, with $480 million allocated to the U.S. credit facility and $20 million allocated to the Canadian credit facility. Under the terms of the credit facility, the Global Borrowing Base will next be redetermined in the fourth quarter of 2004 and the amount of available borrowing could be adjusted at that time.

        At June 30, 2004, the unused borrowing amount under the Global Borrowing Base was approximately $158 million in addition to amounts outstanding. On July 31, 2004, our unused borrowing amount was approximately $179 million in addition to amounts outstanding.

32



        At June 30, 2004, there were outstanding borrowings of $316 million under Forest's U.S. credit facility at a weighted average interest rate of 2.59% and there were no borrowings under our Canadian credit facility. In addition to outstanding borrowings under Forest's credit facilities, there were outstanding borrowings of Wiser in the amount of $19 million under a U.S. credit facility and $17.4 million under a Canadian credit facility. On July 6, 2004 Wiser's U.S. and Canadian facilities were repaid using additional borrowings under Forest's U.S. credit facility and cash on hand. The Wiser credit facilities were terminated July 30, 2004. At July 31, 2004, there were outstanding borrowings of $314 million under Forest's U.S. credit facility at a weighted average interest rate of 2.77%, and there were no borrowings under the Canadian credit facility. At June 30, 2004, Forest had used the credit facilities for letters of credit in the amount of $5.9 million. At July 31, 2004, we had used the credit facilities for letters of credit in the amount of $6.3 million.

        Credit Ratings.    Our bank credit facilities and 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. On May 28, 2004, S&P announced that it lowered the corporate and senior unsecured debt rating on Forest to BB- from BB. S&P also lowered its senior secured bank loan rating on our credit facility to BB from BB+. S&P's ratings outlook is stable. On June 2, 2004, Moody's announced that it lowered Forest's senior implied rating to Ba3 from Ba2, but confirmed our Ba3 senior unsecured note rating with a negative outlook. Moody's also lowered its rating on our credit facility from Ba1 to Ba2.

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

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

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

        Note Redemptions.    On July 30, 2004, we redeemed, at 101.583% of par value, $125 million principal amount of 91/2% Senior Subordinated Notes due 2007 that were issued by Wiser. The note redemption was funded using borrowings under our U.S. credit facility.

33


Item 3. 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. In order to reduce the impact of fluctuations in prices, we enter into long-term contracts for a portion of our production and use a hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars and other financial instruments. With the exception of certain derivative instruments acquired in the Wiser Acquisition, all of our commodity swaps and collar agreements and a portion of our basis swaps in place at June 30, 2004 have been designated as cash flow hedges. 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. We periodically assess the estimated portion of our anticipated production that is subject to hedging arrangements, and we adjust this percentage based on our assessment of market conditions and the availability of hedging arrangements that meet our criteria. Hedging arrangements covered 52% and 55% of our consolidated production, on an equivalent basis, during the six months ended June 30, 2004 and 2003, respectively.

        In a typical commodity swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index when the index price is lower. If the index price is higher, Forest pays the difference. By entering into swap agreements we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of June 30, 2004, Forest had entered into the following swaps accounted for as cash flow hedges:

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs Per Day
  Average Hedged
Price Per MMBTU

  Barrels Per Day
  Average Hedged
Price Per BBL

Third Quarter 2004   157.3   $ 5.19   13,850   $ 28.30
Fourth Quarter 2004   117.5   $ 5.24   9,850   $ 29.60
First Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Second Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Third Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
Fourth Quarter 2005   100.0   $ 5.04   6,500   $ 30.93
First Quarter 2006   30.0   $ 5.47   4,000   $ 31.58

        Between July 1, 2004 and August 5, 2004, we did not enter into any swaps accounted for as cash flow hedges.

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

        Collars are also settled in cash, either on a monthly basis or at the end of their terms. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production when prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged

34



production. As of June 30, 2004, the Company had entered into the following natural gas collars accounted for as cash flow hedges:

 
  Natural Gas
 
  BBTUs
per Day

  Average Floor
MMBTU Price per

  Average Ceiling
Price per MMBTU

Third Quarter 2004   10.0   $ 5.50   $ 6.25
Fourth Quarter 2004   16.6   $ 5.30   $ 6.76
First Quarter 2005   20.0   $ 5.25   $ 6.89

        Between July 1, 2004 and August 5, 2004, we did not enter into any collars accounted for as cash flow hedges.

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

        As of June 30, 2004, Forest had entered into the following 3-way natural gas collars accounted for as cash flow hedges:

 
  Natural Gas
 
  BBTUs Per Day
  Average Lower Floor Price Per MMBTU
  Average Upper Floor Price Per MMBTU
  Average Ceiling
Price Per MMBTU

Third Quarter 2004   25.0   $ 3.50   $ 4.75   $ 5.80
Fourth Quarter 2004   11.7   $ 3.50   $ 4.75   $ 6.14

 


 

Oil (NYMEX WTI)

 
  Barrels Per Day
  Average Lower Floor Price Per Barrel
  Average Upper Floor Price Per Barrel
  Average Ceiling
Price Per Barrel

First Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Second Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Third Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00
Fourth Quarter 2005   1,500   $ 24.00   $ 28.00   $ 32.00

        Between July 1, 2004 and August 5, 2004, we did not enter into any 3-way collars accounted for as cash flow hedges.

        We also use basis swaps in connection with natural gas swaps, in order to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. As of June 30, 2004, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 29.0 BBTUs per day for the remainder of 2004. Between July 1, 2004 and August 5, 2004, we did not enter into any basis swaps designated as cash flow hedges.

        The fair value of our cash flow hedges based on the futures prices quoted on June 30, 2004 was a loss of approximately $100,918,000 ($62,569,000 after tax) which was recorded as a component of other comprehensive income.

        As of June 30, 2004, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 91.7 BBTUs per day for the remainder of 2004 and weighted average volumes of 72.5 BBTUs per day for 2005. Between July 1, 2004 and August 5, 2004 we did not enter into any additional basis swaps not designated as cash flow hedges.

35


        Forest has the following swap agreements as a result of the Wiser Acquisition. These swap agreements were not designated as cash flow hedges by Wiser but were designated as cash flow hedges by Forest on July 15, 2004.

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs Per Day
  Average Hedged
Price Per MMBTU

  Barrels Per Day
  Average Hedged Price Per BBL
Third Quarter 2004   10.0   $ 4.85   2,000   $ 28.23
Fourth Quarter 2004   10.0   $ 4.85   1,000   $ 29.60

        Forest also has the following collar agreements as a result of the Wiser Acquisition. These collar agreements cannot be designated as cash flow hedges by Forest under generally accepted accounting principles because the collars had unrealized losses at the date of the Wiser Acquisition.

 
  Natural Gas
  Oil (NYMEX WTI)
 
  BBTUs
Per Day

  Average Floor
Price per MMBTU

  Average Ceiling
Price per MMBTU

  Barrels
Per Day

  Average Floor
Price per BBL

  Average Ceiling
Price per BBL

Third Quarter 2004   15.0   $ 4.35   $ 5.48          
Fourth Quarter 2004   5.0   $ 5.50   $ 7.40          
First Quarter 2005   5.0   $ 5.50   $ 8.00   1,000   $ 32.00   $ 35.30

        In addition, we have call derivative instruments as a result of the Wiser Acquisition. Call derivative instruments require Forest to pay the difference between the actual market price and the call price only if the actual market price is above the call price. If the actual market price is equal to or below the call price, we do not pay or receive any settlement amount. Calls are speculative arrangements and are not cash flow hedges under generally accepted accounting principles. We have the following oil calls as a result of the Wiser Acquisition.

 
  Oil (NYMEX WTI)
 
  Barrels Per Day
  Average Hedged
Price Per Barrel

Third Quarter 2004   1,000   $ 31.25
Fourth Quarter 2004   1,000   $ 33.00

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

        The fair value of our derivative instruments not designated as cash flow hedges based on the futures prices quoted on June 30, 2004 was a loss of approximately $7.5 million.

Foreign Currency Exchange Risk

        We conduct business in several foreign countries 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 U.S. dollar-denominated, as have cash proceeds related to property sales and farmout arrangements.

36



Interest Rate Risk

        The following table presents principal amounts and related weighted average fixed interest rates by year of maturity for Forest's debt obligations at June 30, 2004:

 
  2005
  2007
  2008
  2011
  2014
  Total
  Fair Value
 
  (Dollar Amounts in Thousands)

Bank credit facilities:                              
  Variable rate(1)   $ 352,354             352,354   352,354
  Average interest rate     2.80 %           2.80 %  
Long-term debt:                              
  Fixed rate(2)   $   125,000   265,000   160,000   150,000   700,000   731,825
  Coupon interest rate       9.50 % 8.00 % 8.00 % 7.75 % 7.93 %  
  Effective interest rate(3)       9.50 % 6.56 % 7.48 % 7.91 % 7.81 %  

(1)
Includes debt of $36 million assumed in the Wiser Acquisition with an average interest rate of 4.55% at June 30, 2004, which was repaid in July 2004 using funds from our U.S. credit facility. The average interest rate without this debt would have been 2.59%.

(2)
Includes $125 million principal amount of 91/2% Senior Subordinated Notes due 2007 issued by Wiser, which were redeemed in July 2004.

(3)
The effective interest rates on the 8% Senior Notes due 2008, the 8% Senior Notes due 2011 and the 73/4% Senior Notes due 2014 will be reduced from the coupon rate as a result of amortization of the gains related to termination of the related interest rate swaps.

Item 4. CONTROLS AND PROCEDURES

        H. Craig Clark, our Chief Executive Officer, and David H. Keyte, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the quarterly period ended June 30, 2004. Based on the evaluation, they believe that:

        There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

37



PART II—OTHER INFORMATION

Part II—Other Information

Item 1. Legal Proceedings.

        Environmental Matters.    In April 2004 the environmental proceeding commenced by the U.S. Coast Guard concerning the King Salmon platform in the Cook Inlet in Alaska, in which Forest owns a non-operating interest, was resolved. The operator of the platform entered into a consent order under which it agreed to pay a civil penalty of $137,500. As a joint working interest owner in the platform, Forest is responsible for 46.8 percent of the penalty. The parties have not resolved any separate action that the State of Alaska Department of Environmental Conservation might initiate.

Item 4. Submission Of Matters To A Vote Of Security Holders.

        On May 13, 2004, Forest held its Annual Meeting of Shareholders (Annual Meeting) in Denver, Colorado. A total of 50,371,025 shares of common stock were present at the Annual Meeting, either in person or by proxy, constituting a quorum. The matters voted upon at the Annual Meeting consisted of two proposals set forth in Forest's Proxy Statement dated April 12, 2004. The two proposals submitted to a vote of shareholders are set forth below. The proposals were each adopted by the shareholders by the indicated margins.

Proposal No. 1—Election of three (3) Class I directors.

 
  Shares Voted for
  Shares Withheld
Cortlandt S. Dietler   49,445,532   925,493
Dod A. Fraser   49,382,804   988,221
Patrick R. McDonald   49,387,225   983,800

        In addition to the three Class I directors noted above, the other directors of Forest whose terms did not expire at the 2004 Annual Meeting include: William L. Britton, H. Craig Clark, Forrest E. Hoglund and James H. Lee.

Proposal No. 2—Ratification of the appointment of KPMG as independent accountants.

Shares Voted for

  Shares Against
  Abstentions
50,102,812   212,959   55,254

        There were no broker non-votes.

Item 6. Exhibits And Reports On Form 8-K


*
Filed herewith.

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

38


        The Company filed the following current reports on Form 8-K during the second quarter ending June 30, 2004.

Date of Report

  Item Reported
  Financial Statements Filed
May 6, 2004   Items 7, 9 and 12*   None
May 24, 2004   Items 7 and 9*   None
May 24, 2004   Items 7 and 9*   None
May 24, 2004   Items 5 and 7*   None
May 27, 2004   Items 7 and 9*   None
May 27, 2004   Items 5 and 7   None
June 2, 2004   Item 5   None
June 2, 2004   Items 5 and 7   None
June 3, 2004   Item 5   None

*
The information in the Forms 8-K furnished pursuant to Items 9 and 12 is not considered to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section.

39



SIGNATURES

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


 

 

FOREST OIL CORPORATION
(Registrant)

August 9, 2004

 

By:

 

/s/  
DAVID H. KEYTE      
David H. Keyte
Executive Vice President and Chief Financial Officer (on behalf of the Registrant and as Principal Financial Officer)

 

 

By:

 

/s/  
JOAN C. SONNEN      
Joan C. Sonnen
Vice President—Controller and Chief Accounting Officer (Principal Accounting Officer)

40


Exhibit Index

Exhibit Number
  Description
4.1   Registration Rights Agreement dated July 14, 2004 among Forest Oil Corporation and the initial purchasers named therein

31.1

 

Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended

31.2

 

Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended

32.1

 

Certification of Chief Executive Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350

32.2

 

Certification of Chief Financial Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350