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

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

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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 September 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)

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

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

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

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

        As of October 31, 2004 there were 59,295,659 shares of common stock, par value $.10 per share, outstanding.

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

Part I—FINANCIAL INFORMATION
	Item 1—Financial Statements
		Condensed Consolidated Balance Sheets
		Condensed Consolidated Statements of 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 6—Exhibits
Signatures

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

				September 30, 2004			December 31, 2003
				(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents			$	25,573		11,509
	Accounts receivable				153,568		158,954
	Derivative instruments				2,371		4,130
	Current deferred tax asset				55,398		23,302
	Other current assets				24,944		17,465
		Total current assets			261,854		215,360
Net property and equipment					2,760,284		2,433,966
Assets held for sale related to discontinued operations					—		8,589
Goodwill					63,978		—
Other assets					34,226		25,633
				$	3,120,342		2,683,548
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable			$	143,713		192,001
	Accrued interest				17,838		3,869
	Derivative instruments				127,706		49,838
	Asset retirement obligation				20,911		23,243
	Other current liabilities				6,863		4,158
		Total current liabilities			317,031		273,109
Long-term debt					1,009,353		929,971
Asset retirement obligation					212,368		188,189
Derivative instruments					42,141		9,696
Other liabilities					30,425		24,062
Deferred income taxes					162,012		72,723
Shareholders' equity:
	Common stock				6,123		5,563
	Capital surplus				1,431,143		1,302,340
	Accumulated earnings (deficit)				22,439		(56,495	)
	Accumulated other comprehensive loss				(57,346	)	(9,740	)
	Treasury stock, at cost				(55,347	)	(55,870	)
		Total shareholders' equity			1,347,012		1,185,798
				$	3,120,342		2,683,548

See accompanying notes to condensed consolidated financial statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

					Three Months Ended September 30,					Nine Months Ended September 30,
					2004			2003		2004			2003
					(In Thousands Except Per Share Amounts)
Revenue:
	Oil and gas sales:
		Natural gas			$	157,424		108,220		$	412,639		322,048
		Oil, condensate and natural gas liquids				87,569		52,719			234,079		160,666
			Total oil and gas sales			244,993		160,939			646,718		482,714
	Processing income, net					400		390			1,406		932
			Total revenue			245,393		161,329			648,124		483,646
Operating expenses:
	Oil and gas production					65,043		40,180			179,063		110,892
	General and administrative					7,975		11,118			22,504		29,425
	Depreciation and depletion					94,583		53,303			257,685		152,805
	Accretion of asset retirement obligation					4,472		3,456			12,900		9,723
	Impairment of oil and gas properties					—		—			1,690		135
			Total operating expenses			172,073		108,057			473,842		302,980
Earnings from operations						73,320		53,272			174,282		180,666
Other income and expense:
	Other (income) expense, net					990		(170	)		(350	)	6,367
	Unrealized loss (gain) on derivative instruments					3,584		(33	)		3,367		94
	Interest expense					16,604		11,529			42,635		36,979
			Total other income and expense			21,178		11,326			45,652		43,440
Earnings before income taxes, discontinued operations and cumulative effect of change in accounting principle						52,142		41,946			128,630		137,226
Income tax expense (benefit):
	Current					461		(144	)		1,329		270
	Deferred					19,906		15,770			47,759		52,843
						20,367		15,626			49,088		53,113
Earnings from continuing operations						31,775		26,320			79,542		84,113
Gain (loss) from discontinued operations (net of tax)						—		20			(575	)	(1,344	)
Cumulative effect of change in accounting principle for recording asset retirement obligation (net of tax)						—		—			—		5,854
Net earnings					$	31,775		26,340			78,967		88,623
Weighted average number of common shares outstanding:
	Basic					59,019		48,244			56,058		48,098
	Diluted					60,157		49,071			57,126		48,958
Basic earnings per common share:
	Earnings from continuing operations				$	0.54		0.55			1.42		1.75
	Loss from discontinued operations (net of tax)					—		—			(.01	)	(.03	)
	Cumulative effect of change in accounting principle (net of tax)					—		—			—		0.12
	Net earnings per common share				$	0.54		0.55			1.41		1.84
Diluted earnings per common share:
	Earnings from continuing operations				$	0.53		0.54			1.39		1.72
	Loss from discontinued operations (net of tax)					—		—			(.01	)	(.03	)
	Cumulative effect of change in accounting principle (net of tax)					—		—			—		0.12
	Net earnings per common share				$	0.53		0.54			1.38		1.81

See accompanying notes to condensed consolidated financial statements.

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FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

					Nine Months Ended September 30,
					2004			2003
					(In Thousands)
Cash flows from operating activities:
Net earnings before cumulative effect of change in accounting principle					$	78,967		$	82,769
	Adjustments to reconcile net earnings before cumulative effect of change in accounting principle to net cash provided by operating activities:
		Depreciation and depletion				257,685			153,874
		Accretion of asset retirement obligation				12,900			9,723
		Impairment of oil and gas properties				1,690			135
		Amortization of deferred hedge gain				(3,692	)		(3,321	)
		Amortization of deferred debt costs				1,838			1,691
		Unrealized loss on derivative instruments, net				3,367			94
		Deferred income tax expense				48,481			54,004
		Loss on extinguishment of debt				—			3,975
		Loss (earnings) in equity method investee				(1,386	)		1,775
		Other, net				(2	)		986
		Decrease (increase) in accounts receivable				29,629			(26,292	)
		Increase in other current assets				(4,676	)		(11,851	)
		Decrease in accounts payable				(82,210	)		(1,625	)
		Increase (decrease) in accrued interest and other current liabilities				21,030			(1,913	)
			Net cash provided by operating activities			363,621			264,024
Cash flows from investing activities:
	Acquisition of subsidiary					(169,821	)		—
	Capital expenditures for property and equipment:
		Exploration, development and other acquisition costs				(235,259	)		(287,006	)
		Other fixed assets				(1,938	)		(1,589	)
	Proceeds from sales of assets					17,676			12,059
	Proceeds from sale of goodwill and contract value					8,493			—
	Increase in other assets, net					(5,693	)		(901	)
			Net cash used by investing activities			(386,542	)		(277,437	)
Cash flows from financing activities:
	Proceeds from bank borrowings					1,321,074			470,000
	Repayments of bank borrowings					(1,409,000	)		(420,000	)
	Issuance of 8% senior notes, net of issuance costs					133,313			—
	Redemption of 91/2% senior notes					(126,971	)		—
	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					11,666			6,211
	Deferred compensation					98			—
	Purchase of treasury stock					(15	)		—
	Settlements of acquired derivative instruments					(5,582	)		—
	Decrease in other liabilities, net					(3,307	)		(1,705	)
			Net cash provided by financing activities			38,419			6,033
Effect of exchange rate changes on cash						(1,434	)		(398	)
Net increase (decrease) in cash and cash equivalents						14,064			(7,778	)
Cash and cash equivalents at beginning of period						11,509			13,166
Cash and cash equivalents at end of period					$	25,573			5,388
Cash paid during the period for:
	Interest				$	34,792			31,588
	Income taxes				$	3,067			1,660

See accompanying notes to condensed consolidated financial statements.

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FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 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 September 30, 2004 and the results of operations for the three and nine months ended September 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 used in such calculations. Assumptions, judgments and estimates are also required in determining future abandonment obligations, 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

        In June 2004, Forest completed its acquisition of the common stock of The Wiser Oil Company (Wiser) with oil and gas assets located in the Company's Canadian, Western U.S. 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 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. As of September 30, 2004, the cash consideration paid for Wiser was allocated as follows:

        Goodwill of $63,978,000 ($63,243,000 before effects of foreign currency exchange) 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:

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addition of significant estimated proved reserves, producing assets and undeveloped acreage in Forest's core areas; and

•

opportunities for cost savings through administrative and operational synergies.

        The following unaudited pro forma consolidated statements of operations information assumes that the Wiser Acquisition occurred as of January 1 of each year. These pro forma results of operations are not necessarily indicative of the results of operations that would have actually been attained if the transaction had occurred as of these dates.

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(3) GOODWILL

        The change in the carrying amount of goodwill for the three months ended September 30, 2004 is as follows:

(4) EARNINGS PER SHARE AND COMPREHENSIVE EARNINGS

Earnings per Share:

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

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

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

		Three Months Ended September 30,					Nine Months Ended September 30,
		2004(1)			2003(2)		2004(3)		2003(4)
		(In Thousands Except Per Share Amounts)
Earnings from continuing operations		$	31,775		26,320		79,542		84,113
Weighted average common shares outstanding during the period			59,019		48,244		56,058		48,098
Add dilutive effects of stock options			370		178		324		199
Add dilutive effects of warrants			768		649		744		661
Weighted average common shares outstanding including the effects of dilutive securities			60,157		49,071		57,126		48,958
Basic earnings per share from continuing operations		$	0.54		0.55		1.42		1.75
Diluted earnings per share from continuing operations		$	0.53		0.54		1.39		1.72

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(1)

For the three months ended September 30, 2004, options to purchase 1,228,400 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.

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(2)

For the three months ended September 30, 2003, options to purchase 2,822,300 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 nine months ended September 30, 2004, options to purchase 1,433,900 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 nine months ended September 30, 2003, options to purchase 2,822,300 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:

        Comprehensive earnings is a term used to refer to net earnings plus other comprehensive income. Other comprehensive income 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. Items included in the Company's other comprehensive income for the three and nine months ended September 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 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 earnings are as follows:

(5) 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

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

(6) NET PROPERTY AND EQUIPMENT

        Components of net property and equipment are as follows:

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(7) 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 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.

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

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

(8) 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.

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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.

        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:

        The components of gain (loss) from discontinued operations for the three months ended September 30, 2003 and the nine months ended September 30, 2004 and 2003 are as follows:

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(9) LONG-TERM DEBT

        Components of long-term debt are as follows:

		September 30, 2004									December 31, 2003
		Principal			Unamortized Premium (Discount)		Other		Total		Principal		Unamortized Discount		Other		Total
		(In Thousands)
U.S. Credit Facility(1)		$	271,000		—		—		271,000		291,000		—		—		291,000
Canadian Credit Facility(1)			—		—		—		—		1,542		—		—		1,542
Bank debt assumed in acquisition			—		—		—		—		30,000	(2)	—		—		30,000
8% Senior Notes Due 2008			265,000		(365	)	8,531	(4)	273,166		265,000		(439	)	10,258	(4)	274,819
8% Senior Notes Due 2011(3)			285,000		9,365		6,041	(4)	300,406		160,000		—		6,671	(4)	166,671
73/4% Senior Notes Due 2014			150,000		(2,288	)	17,069	(4)	164,781		150,000		(2,467	)	18,406	(4)	165,939
					—						—		—		—		—
		$	971,000		6,712		31,641		1,009,353		897,542		(2,906	)	35,335		929,971

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(1)

In September 2004, Forest entered into amended and restated credit facilities totaling $600,000,000, consisting of a $550,000,000 United States credit facility and a $50,000,000 Canadian credit facility. The credit facilities mature in September 2009. Subject to the agreement of Forest and the applicable lenders, the size of the credit facilities may be increased by $200,000,000 in the aggregate.

(2)

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

(3)

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.

(4)

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

(10) EMPLOYEE BENEFITS

      The following table sets forth the components of the net periodic cost of the Company's defined benefit pension plans and postretirement benefits in the United States for the three and nine months ended September 30, 2004 and 2003 (In Thousands):

							Postretirement Benefits
															Postretirement Benefits
		Pension Benefits									Pension Benefits
							Three Months Ended September 30,
		Three Months Ended September 30,									Nine Months Ended September 30,				Nine Months Ended September 30,
		2004			2003		2004		2003		2004		2003		2004		2003
Service cost		$	—		—		158		133		—		—		474		399
Interest cost			431		454		138		131		1,293		1,362		414		393
Expected return on plan assets			(381	)	(341	)	—		—		(1,143	)	(1,023	)	—		—
Recognized actuarial loss			173		182		12		—		519		546		36		—
Total net periodic cost		$	223		295		308		264		669		885		924		792

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(11) 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 September 30, 2004 and 2003, the Company recognized reductions of interest expense of $1,239,550 and $1,119,000, respectively, related to the terminated interest rate swaps. During the nine months ended September 30, 2004 and 2003, the reductions of interest expense were $3,692,530 and $3,321,000, 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.

        Substantially all of the Company's commodity swaps and collar agreements and a portion of its basis swaps in place at September 30, 2004 have been designated as cash flow hedges. In addition, the Company has basis swaps that are not designated as cash flow hedges and also had certain collar agreements that could not be designated as cash flow hedges under generally accepted accounting principles because these collars had unrealized losses at the date they were obtained by Forest in the Wiser Acquisition.

        At September 30, 2004, the Company had a derivative asset of $2,409,000 (of which $2,371,000 was classified as current), a derivative liability of $169,847,000 (of which $127,706,000 was classified as current), a deferred tax asset of $63,506,000 (of which $47,507,000 was classified as current) and accumulated other comprehensive loss of $155,926,000 ($96,674,000 net of tax).

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

				Three Months Ended September 30,					Nine Months Ended September 30,
				2004			2003		2004		2003
							(In Thousands)
Derivatives designated as cash flow hedges				$	(30,447	)	(12,268	)	(80,109	)	(65,713	)
Derivatives not designated as cash flow hedges:
	Realized gains (losses)				(675	)	11		310		49
	Unrealized gains (losses)				(3,584	)	33		(3,367	)	(94	)
		Total loss		$	(34,706	)	(12,224	)	(83,166	)	(65,758	)

        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 September 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
Fourth Quarter 2004		127.5		$	5.21		10,850		$	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
Second Quarter 2006		30.0		$	5.47		4,000		$	31.58
Third Quarter 2006		30.0		$	5.47		4,000		$	31.58
Fourth 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 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

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in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged production. As of September 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 Price per MMBTU			Average Ceiling Price per MMBTU
Fourth Quarter 2004		23.3		$	5.71		$	7.20
First Quarter 2005		30.0		$	5.75		$	7.36

        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 September 30, 2004, Forest had entered into the following three-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
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 September 30, 2004 there were basis swaps designated as cash flow hedges in place with weighted average volumes of 15.9 BBTUs per day for the remainder of 2004. At September 30, 2004 there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 89.3 BBTUs per day for the remainder of 2004 and weighted average volumes of 72.5 BBTUs per day for 2005.

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

		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
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 obtained call derivative instruments in 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 obtained the following oil calls in the Wiser Acquisition.

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

(12) 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 $117.1 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.

(13) 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 September 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 8. 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

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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.

Three Months Ended September 30, 2004

				Oil and Gas Operations
				Gulf Coast			Western		Alaska		Total U.S.		Canada		Int'l		Total Company
				(In Thousands)
Revenue				$	148,533		48,221		12,371		209,125		35,868		—		244,993
Expenses:
	Oil and gas production				32,379		14,115		10,687		57,181		7,862		—		65,043
	General and administrative				2,157		920		770		3,847		1,128		—		4,975
	Depletion				57,014		9,792		12,341		79,147		14,422		—		93,569
	Accretion of asset retirement obligation				3,534		303		373		4,210		262		—		4,472
	Impairment of oil and gas properties				—		—		—		—		—		—		—
Earnings (loss) from operations				$	53,449		23,091		(11,800	)	64,740		12,194		—		76,934
Capital expenditures:
	Acquisitions			$	19,193		(72	)	11		19,132		(579	)	—		18,553
	Exploration costs				8,923		983		605		10,511		6,027		1,375		17,913
	Development costs				11,632		14,383		3,547		29,562		5,630		—		35,192
		Total capital expenditures(1)		$	39,748		15,294		4,163		59,205		11,078		1,375		71,658
Property and equipment, net				$	1,296,060		584,907		385,509		2,266,476		428,071		57,589		2,752,136
Goodwill(2)				$	16,401		36,080		—		52,481		11,497		—		63,978

---

(1)

Does not include estimated discounted asset retirement obligations of $(8.4) million related to assets placed in service during the three months ended September 30, 2004.

(2)

Represents a preliminary allocation of goodwill to business units.

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

Nine Months Ended September 30, 2004

				Oil and Gas Operations
				Gulf Coast			Western		Alaska		Total U.S.		Canada		Int'l		Total Company
				(In Thousands)
Revenue				$	409,975		117,410		46,399		573,784		72,934		—		646,718
Expenses:
	Oil and gas production				95,425		32,677		36,329		164,431		14,632		—		179,063
	General and administrative				6,006		1,865		2,548		10,419		2,612		—		13,031
	Depletion				157,183		23,633		43,567		224,383		30,551		—		254,934
	Accretion of asset retirement obligation				10,400		893		1,098		12,391		509		—		12,900
	Impairment of oil and gas properties				—		—		—		—		—		1,690		1,690
Earnings (loss) from operations				$	140,961		58,342		(37,143	)	162,160		24,630		(1,690	)	185,100
Capital expenditures:
	Acquisitions			$	108,265		164,634		11		272,910		109,212		—		382,122
	Exploration costs				53,746		2,823		1,987		58,556		12,869		3,900		75,325
	Development costs				66,031		33,310		7,050		106,391		12,437		—		118,828
		Total capital expenditures(1)		$	228,042		200,767		9,048		437,857		134,518		3,900		576,275
Property and equipment, net				$	1,296,060		584,907		385,509		2,266,476		428,071		57,589		2,752,136
Goodwill(2)				$	16,401		36,080		—		52,481		11,497		—		63,978

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(1)

Does not include estimated discounted asset retirement obligations of $13.5 million related to assets placed in service during the nine months ended September 30, 2004.

(2)

Represents a preliminary allocation of goodwill to business units.

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

Three Months Ended September 30, 2003

				Oil and Gas Operations
				Gulf Coast			Western		Alaska		Total U.S.		Canada		Int'l		Total Company
				(In Thousands)
Revenue				$	96,509		25,275		22,216		144,000		16,939		—		160,939
Expenses:
	Oil and gas production				19,624		5,748		10,530		35,902		4,278		—		40,180
	General and administrative				3,040		859		1,090		4,989		838		—		5,827
	Depletion				33,720		4,274		6,683		44,677		7,467		—		52,144
	Accretion of asset retirement obligation				2,485		235		602		3,322		134		—		3,456
Impairment of oil and gas properties					—		—		—		—		—		—		—
Earnings from operations				$	37,640		14,159		3,311		55,110		4,222		—		59,332
Capital expenditures:
	Acquisitions			$	1,410		34,870		—		36,280		—		22		36,302
	Exploration costs				20,470		571		967		22,008		12,691		1,991		36,690
	Development costs				26,975		5,551		11,010		43,536		4,376		—		47,912
		Total capital expenditures(1)		$	48,855		40,992		11,977		101,824		17,067		2,013		120,904
Property and equipment, net				$	943,181		283,002		424,758		1,650,941		290,384		71,756		2,013,081

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(1)

Does not include estimated discounted asset retirement obligations of $0.7 million related to assets placed in service during the three months ended September 30, 2003.

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

Nine Months Ended September 30, 2003

				Oil and Gas Operations
				Gulf Coast			Western		Alaska		Total U.S.		Canada		Int'l		Total Company
				(In Thousands)
Revenue				$	298,581		76,438		58,653		433,672		49,042		—		482,714
Expenses:
	Oil and gas production				51,865		17,369		31,185		100,419		10,473		—		110,892
	General and administrative				8,517		2,305		3,800		14,622		3,505		—		18,127
	Depletion				96,618		12,697		20,252		129,567		20,473		—		150,040
	Accretion of asset retirement obligation				6,984		675		1,674		9,333		390		—		9,723
Impairment of oil and gas properties					—		—		—		—		—		135		135
Earnings from operations				$	134,597		43,392		1,742		179,731		14,201		(135	)	193,797
Capital expenditures:
	Acquisitions				19,880		38,490		—		58,370		—		22		58,392
	Exploration costs				41,642		1,806		3,372		46,820		27,133		4,127		78,080
	Development costs				72,999		19,064		49,104		141,167		9,367		—		150,534
		Total capital expenditures(1)		$	134,521		59,360		52,476		246,357		36,500		4,149		287,006
Property and equipment, net				$	943,181		283,002		424,758		1,650,941		290,384		71,756		2,013,081

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(1)

Does not include estimated discounted asset retirement obligations of $3.6 million related to assets placed in service during the nine months ended September 30, 2003.

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

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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.

Third Quarter 2004 Overview

        Highlights of the third quarter of 2004 included better production performance of approximately 46.5 BCFE or 506 MMCFE, an increase of 26% compared to the third quarter of 2003 and 13% compared to the second quarter of 2004. This higher production level was achieved despite the impact of Hurricane Ivan, which decreased third quarter 2004 production 13 MMCFE/d.

        Net earnings for the third quarter of 2004 of $32 million increased 21% compared to $26 million in the third quarter of 2003 due to increased production, higher per-unit netbacks and reduced general and administrative expense, offset partially by higher depletion expense. Total netbacks (oil and gas sales revenue less production expense) of approximately $180 million ($3.87 per MCFE) for the third quarter of 2004 were approximately $59 million greater than those reported in the third quarter of 2003. General and administrative expense in the third quarter of 2004 was approximately $8 million, a 28% decrease compared to the third quarter of 2003.

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

Oil and Gas Sales

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

---

(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 19,987 MMCF and 11,040 MMCF in the third quarter of 2004 and 2003, respectively. Hedged oil volumes were 1,550,200 barrels and 966,000 barrels in the third 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 $30,447,000 and $12,268,000 in the third quarter of 2004 and 2003, respectively. Average sales prices have been adjusted to reflect effects of

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energy swaps and collars. Derivative instruments that are not designated as cash flow hedges for accounting purposes are recorded as other income or expense.

        The increase in oil and gas sales revenue in the third quarter of 2004 compared to the third quarter of 2003 was the result of improved 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 and second quarter of 2004.

Oil and Gas Production Expense

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

			Three Months Ended September 30,
			2004			Per MCFE		2003		Per MCFE		% Change in cost
			(In Thousands Except Per MCFE Amounts)
Direct operating expense			$	50,390		1.08		30,748		.83		64	%
Workovers				3,646		.08		2,128		.06		71	%
Product transportation				3,093		.07		2,389		.06		29	%
Production and ad valorem taxes				7,914		.17		4,915		.14		61	%
	Total oil and gas production expense		$	65,043		1.40		40,180		1.09		62	%

        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 September 30, 2004 than in the corresponding prior year period due to the acquisition of properties with higher lease operating expense than our base properties. Workover expense increased due to exploitation activity in the newly acquired fields.

General and Administrative Expense; Overhead

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

        The significant decrease in total overhead costs and general and administrative expense in the third quarter of 2004 resulted primarily from cost reduction measures in corporate areas. On a per-unit basis, general and administrative expense decreased by 43% to $.17 per MCFE compared to $.30 per MCFE in the corresponding period of 2003.

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Depreciation and Depletion

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

        The increases in depletion expense and in the per-unit depletion rate in the three months ended September 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 and increased production.

Accretion of Asset Retirement Obligation

        Accretion expense of approximately $4.5 million and $3.5 million in the third 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 expense was $990,000 in the third quarter of 2004 and consisted primarily of realized losses on derivative instruments. In the three months ended September 30, 2003 other income was $170,000 primarily consisting of collection of funds under a bankruptcy claim that was written off in a prior year.

Unrealized Loss (Gain) on Derivative Instruments

        Forest recorded a loss of $3.6 million in the third quarter of 2004 and a gain of $33,000 in the third quarter of 2003 related to the unrealized effects of ineffective basis swaps, collar agreements and call instruments. The more significant impacts in the 2004 period related primarily to the effect of certain collar agreements obtained by Forest in the Wiser Acquisition that could not be designated as cash flow hedges under generally accepted accounting principles because these collars had unrealized losses at the date of the acquisition.

Interest Expense

        Interest expense of $16.6 million in the three months ended September 30, 2004 increased compared to the same period of 2003 due to higher average debt balances.

Current and Deferred Income Tax Expense

        Forest recorded current income tax expense of $461,000 in the three months ended September 30, 2004 compared to a current income tax benefit of $144,000 in the comparable period of 2003. The benefit in 2003 resulted from a decrease in the accrued alternative minimum tax for the year.

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        Deferred income tax expense was $19.9 million in the three months ended September 30, 2004 compared to $15.8 million in the comparable period of 2003. The increase was primarily attributable to higher pre-tax profitability.

Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary, Producers Marketing Ltd. (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 September 30, 2003 are as follows:

Results of Operations for the Nine Months Ended September 30, 2004

        Net earnings for the first nine months of 2004 were approximately $79 million compared to net earnings of approximately $89 million in the first nine months of 2003. The decrease in earnings was due primarily to increases in depreciation and depletion expense caused by downward revisions in estimated proved reserves in the fourth quarter of 2003 and increased oil and gas production expense primarily attributable to the acquisition of Wiser, offset partially by increased production, higher per-unit netbacks and reduced general and administrative expense.

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Oil and Gas Sales

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

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(1)

Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 50,892 MMCF and 35,900 MMCF in the first nine months of 2004 and 2003, respectively. Hedged oil volumes were 3,979,900 barrels and 3,409,500 barrels in the first nine 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 $80,109,000 and $65,713,000 in the first nine 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.

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        The increase in oil and gas sales revenue in the first nine months of 2004 compared to the first nine 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 and in the second quarter of 2004.

Oil and Gas Production Expense

        Oil and gas production expense increased in the first nine months of September 30, 2004 compared to the corresponding 2003 period. The increase was attributable primarily to the acquisition of Wiser. The components of oil and gas production expense were as follows:

			Nine Months Ended September 30,
			2004			Per MCFE		2003		Per MCFE		% Change in cost
			(In Thousands Except Per MCFE Amounts)
Direct operating expense			$	132,549		1.05		85,662		.79		55	%
Workovers				14,753		.12		3,085		.03		378	%
Product transportation				10,196		.08		7,521		.07		36	%
Production and ad valorem taxes				21,565		.17		14,624		.13		47	%
	Total oil and gas production expense		$	179,063		1.42		110,892		1.02		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 nine months ended September 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 activity on newly-acquired fields as well as 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:

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

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Depreciation and Depletion

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

        The increases in depletion expense and in the per-unit depletion rate in the nine months ended September 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 and increased production.

Accretion of Asset Retirement Obligation

        Accretion expense of approximately $12.9 million and $9.7 million in the first nine 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 in the nine months ended September 30, 2004 was $350,000. In the nine months ended September 30, 2003, other expense of $6.4 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.

Unrealized Loss (Gain) on Derivative Instruments

        Forest recorded a loss of $3.4 million in the nine months ended September 30, 2004 and $94,000 in the nine months ended 2003 related to the unrealized gains and losses in connection with the ineffective portions of our basis swaps, collar agreements and call instruments.

Interest Expense

        Interest expense of $43 million in the nine months ended September 30, 2004 increased compared to the same period of 2003 due to higher average debt balances. 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 $1.3 million in the nine months ended September 30, 2004 compared to $270,000 in the comparable period of 2003.

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        Deferred income tax expense was $48 million in the nine months ended September 30, 2004 compared to $53 million in the comparable period of 2003. The decrease was attributable primarily to lower pre-tax profitability.

Results of Discontinued Operations

        On March 1, 2004, the assets and business operations of our Canadian marketing subsidiary, Producers Marketing Ltd. (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 nine months ended September 30, 2004 and 2003 are as follows:

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. Forest had a working capital surplus, exclusive of the after-tax effects of derivatives and abandonment liabilities, of approximately $43.6 million at September 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 and a decrease in accounts payable partially offset by a decrease in accounts receivable. The decrease in accounts payable was caused by reduced exploration and development costs.

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

        The increase in net cash provided by operating activities in the nine months ended September 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 nine months ended September 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 nine months ended September 30, 2004 included net proceeds from the issuance of our 8% senior notes of $133.3 million, net proceeds from the issuance of common stock of $117.1 million and proceeds of $11.7 million from the exercise of options and warrants, partially offset by $127.0 million for the redemption of the 9¹/2% senior notes and net bank repayments of $88 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 $50 million and net proceeds from the issuance of common stock and the exercise of options and warrants of approximately $27.2 million.

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Capital Expenditures

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

---

(1)

Does not include estimated discounted asset retirement obligations of $13.5 million and $3.6 million related to assets placed in service during the nine months ended September 30, 2004 and 2003, respectively.

        Forest's anticipated expenditures for exploration and development in 2004 are estimated to range from $260 million to $280 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

        On September 28, 2004, Forest entered into amended and restated credit facilities totaling $600,000,000, consisting of a $550,000,000 United States credit facility through a syndicate of banks led by JPMorgan Chase and a $50,000,000 Canadian credit facility through a syndicate of banks led by JPMorgan Chase Bank, Toronto Branch. The credit facilities mature in September 2009. Subject to the agreement of Forest and the applicable lenders, the size of the credit facilities may be increased by $200,000,000 in the aggregate.

        Availability under the credit facilities will be based either on certain financial covenants included in the credit facilities or the loan value assigned to Forest's oil and gas properties. If Forest's corporate credit rating by Moody's is "Ba1" or higher and "BB+" or higher by S&P, the credit facilities will be governed by certain financial covenants. Alternatively, if Forest's corporate credit rating is "Ba2" or lower by Moody's or "BB" or lower by S&P, availability under the credit facilities will be governed by a

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borrowing base (Global Borrowing Base). Currently, availability under the credit facilities is governed by the Global Borrowing Base, which currently is set at $500,000,000, with $480,000,000 allocated to the United States credit facility and $20,000,000 allocated to the Canadian credit facility.

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

        At September 30, 2004, the unused borrowing amount under the Global Borrowing Base was approximately $222 million in addition to amounts outstanding. On October 31, 2004, our unused borrowing amount was approximately $268 million in addition to amounts outstanding.

        At September 30, 2004, there were outstanding borrowings of $271 million under the United States credit facility at a weighted average interest rate of 3.09% and there were no borrowings under the Canadian credit facility. At October 31, 2004, there were outstanding borrowings of $225 million under the United States credit facility at a weighted average interest rate of 3.21% and there were no borrowings under the Canadian credit facility. At September 30, 2004 and October 31, 2004, we had used the credit facilities for letters of credit in the amount of $6.4 million and $6.5 million, respectively.

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

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

Credit Ratings

        Our senior notes are separately rated by two ratings agencies: Moody's and S&P. In addition, Moody's and S&P have assigned Forest a general corporate credit rating. On May 28, 2004, S&P announced that it lowered the corporate and senior unsecured debt rating on Forest to BB- from BB.

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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.

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

Common Stock 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

        In July 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.

Impact of Recently Issued Accounting Pronouncements

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

Forward-Looking Statements

        Certain information included in this quarterly report on Form 10-Q and other materials that we file with the Securities and Exchange Commission, as well as information included in oral statements or other written statements that we make include "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 relating to our operations, financial condition and the oil and gas industry. All statements, other than statements of historical facts or present facts, that address activities, events, outcomes and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events.

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        These forward-looking statements appear in a number of places and include statements with respect to, among other things, estimates of our oil and gas reserves; estimates of our future natural gas and liquids production, including estimates of any increases in oil and gas production; planned capital expenditures and availability of capital resources to fund capital expenditures; cash flow; our outlook on oil and gas prices; drilling activities and drilling locations; acquisition and development activities and the funding thereof; hedging activities and the results thereof; liquidity; operating costs; operating margins; political and regulatory developments; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations.

        We caution you that these forward-looking statements are not guarantees of future performance and are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and gas. In particular, the risk factors discussed below and in our Annual Report on Form 10-K could affect our actual results and cause our actual results to differ materially from expectations, estimates, plans, or assumptions expressed in, forecasted in, or implied in such forward-looking statement. Among the factors that could cause actual results to differ materially are:

•

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,

•

timing of development expenditures, and

•

interest rates.

        The financial results of our foreign operations are also subject to currency exchange rate risks.

        Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-Q occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

        All forward-looking statements, expressed or implied, included in this Form 10-Q and attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Forest or persons acting on its behalf may issue. Forest does not undertake to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-Q with the Securities and Exchange Commission, except as required by law.

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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. All of our commodity swaps and collar agreements and a portion of its basis swaps in place at September 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 59% and 52% of our consolidated production, on an equivalent basis, during the nine months ended September 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 November 3, 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
Fourth Quarter 2004		127.5		$	5.21		10,850		$	29.60
First Quarter 2005		100.0		$	5.04		7,500		$	33.47
Second Quarter 2005		100.0		$	5.04		7,500		$	33.47
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
Second Quarter 2006		30.0		$	5.47		4,000		$	31.58
Third Quarter 2006		30.0		$	5.47		4,000		$	31.58
Fourth 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

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production. As of November 3, 2004, the Company had entered into the following natural gas 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 November 3, 2004, Forest had entered into the following three-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
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

        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 September 30, 2004, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 15.9 BBTUs per day for the remainder of 2004. Between October 1, 2004 and November 3, 2004, we did not enter into any basis swaps designated as cash flow hedges.

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        The fair value of our cash flow hedges based on the futures prices quoted on September 30, 2004 was a loss of approximately $163 million ($100.9 million after tax) which was recorded as a component of other comprehensive income.

        As of September 30, 2004, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 89.3 BBTUs per day for the remainder of 2004 and weighted average volumes of 72.5 BBTUs per day for 2005. Between October 1, 2004 and November 3, 2004, we did not enter into any additional basis swaps not designated as cash flow hedges.

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

		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
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 obtained call derivative instruments in 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 obtained the following oil calls in the Wiser Acquisition.

        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 September 30, 2004 was a loss of approximately $4.3 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.

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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 September 30, 2004:

			2008			2009		2011		2014		Total		Fair Value
			(Dollar Amounts in Thousands)
Bank credit facilities:
	Variable rate		$	—		271,000		—		—		271,000		271,000
	Average interest rate			—		3.09	%	—		—		3.09	%
Long-term debt:
	Fixed rate		$	265,000		—		285,000		150,000		700,000		775,863
	Coupon interest rate			8.00	%	—		8.00	%	7.75	%	7.95	%
	Effective interest rate(1)			7.13	%	—		7.71	%	6.56	%	7.24	%

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(1)

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

Disclosure 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 September 30, 2004. Based on the evaluation, they believe that:

•

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



•

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

Internal Control Over Financial Reporting

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

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PART II—OTHER INFORMATION

Item 6. Exhibits

3.1*

Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments Nos. 1, 2 and 3.



10.1*

Amended and Restated U.S. Credit Agreement dated as of September 28, 2004, by and between Forest Oil Corporation, each of the lenders that is a party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas and Harris Nesbitt Financing, Inc., as Co-U.S. Documentation Agents, and JPMorgan Chase Bank, as Global Administrative Agent.



10.2*

Amended and Restated Canadian Credit Agreement dated as of September 28, 2004, by and between Canadian Forest Oil, Ltd., and the subsidiary borrowers from time to time parties hereto, each of the lenders that is a party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, Bank of Montreal and The Toronto-Dominion Bank, as Co-Canadian Documentation Agents, JPMorgan Chase Bank, Toronto Branch, as Canadian Administrative Agent, and JPMorgan Chase Bank, as Global Administrative Agent.



10.3*

Form of Senior Vice President Severance Agreement.



10.4*

Form of Senior Vice President Severance Agreement.



10.5*

Form of Vice President Severance Agreement.



10.6*

Form of Restricted Stock Agreement.



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.



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.



32.1+

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



32.2+

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

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*

Filed herewith.

+

Not deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section and not deemed to be incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent registrant specifically incorporates it by reference.

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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)
November 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)

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Exhibit Index

Exhibit Number		Description
3.1		Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments Nos. 1, 2 and 3.
10.1		Amended and Restated U.S. Credit Agreement dated as of September 28, 2004, by and between Forest Oil Corporation, each of the lenders that is a party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas and Harris Nesbitt Financing, Inc., as Co-U.S. Documentation Agents, and JP Morgan.
10.2		Amended and Restated Canadian Credit Agreement dated as of September 28, 2004, by and between Canadian Forest Oil, Ltd., and the subsidiary borrowers from tim to time parties hereto, each of the lenders that is a party thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, Bank of Montreal and The Toronto-Dominion Bank, as Co-Canadian Documentation Agents, JP Morgan Chase Bank, Toronto Branch, as Canadian Administrative Agent, and JP Morgan Chase Bank, as Global Administrative Agent.
10.3		Form of Senior Vice President Severance Agreement.
10.4		Form of Senior Vice President Severance Agreement.
10.5		Form of Vice President Severance Agreement.
10.6		Form of Restricted Stock Agreement.
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.
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.
32.1		Certification of Chief Executive Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350.
32.2		Certification of Chief Financial Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350.

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