FOREST OIL CORP - 10-Q Quarterly Report

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FOREST OIL CORPORATION INDEX TO FORM 10-Q September 30, 2003

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
Or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from N/A to N/A

Commission File Number 1-13515

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

New York (State or other jurisdiction of incorporation or organization)		25-0484900 (I.R.S. Employer Identification No.)
1600 Broadway Suite 2200 Denver, Colorado 80202 (Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (303) 812-1400

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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

		Number of Shares Outstanding
Title of Class of Common Stock Common Stock, Par Value $.10 Per Share		October 31, 2003 53,388,553

FOREST OIL CORPORATION
INDEX TO FORM 10-Q
September 30, 2003

Part I—FINANCIAL INFORMATION
	Item 1—Financial Statements
		Condensed Consolidated Balance Sheets
		Condensed Consolidated Statements of Production and Operations
		Condensed Consolidated Statements of Cash Flows
		Notes to Condensed Consolidated Financial Statements
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 3—Quantitative and Qualitative Disclosures about Market Risk
	Item 4—Controls and Procedures
Part II—OTHER INFORMATION
	Item 6—Exhibits and Reports on Form 8-K
Signatures

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

			September 30, 2003			December 31, 2002
			(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	5,388		13,166
	Accounts receivable			144,072		111,760
	Derivative instruments			14,355		3,241
	Current deferred tax asset			11,662		10,310
	Other current assets			34,052		21,994

		Total current assets		209,529		160,471
Net property and equipment				2,018,863		1,687,885
Deferred income taxes				—		41,022
Goodwill and other intangible assets, net				13,440		12,525
Other assets				20,409		22,778

			$	2,262,241		1,924,681

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	159,405		153,413
	Accrued interest			14,119		6,857
	Derivative instruments			22,575		29,120
	Asset retirement obligation			15,264		—
	Other current liabilities			4,834		2,285

		Total current liabilities		216,197		191,675
Long-term debt				754,797		767,219
Asset retirement obligation				142,682		—
Other liabilities				25,268		28,199
Deferred income taxes				41,454		16,377
Shareholders' equity:
	Common stock			5,034		4,913
	Capital surplus			1,185,711		1,159,269
	Accumulated deficit			(56,223	)	(144,548	)
	Accumulated other comprehensive income (loss)			3,191		(41,887	)
	Treasury stock, at cost			(55,870	)	(56,536	)

		Total shareholders' equity		1,081,843		921,211

			$	2,262,241		1,924,681

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF PRODUCTION AND OPERATIONS

(Unaudited)

			Three Months Ended September 30,				Nine Months Ended September 30,
			2003			2002	2003	2002
			(In Thousands Except Sales Volumes and Per Share Amounts)
SALES VOLUMES
Natural gas (MMCF)				24,059		23,613	69,898	69,355

Oil, condensate and natural gas liquids (thousands of barrels)				2,129		2,242	6,464	6,588

STATEMENTS OF CONSOLIDATED OPERATIONS
Revenue:
Oil and gas sales:
	Natural gas		$	108,220		73,990	322,048	207,219
	Oil, condensate and natural gas liquids			52,719		49,744	160,666	137,957

		Total oil and gas sales		160,939		123,734	482,714	345,176
	Marketing and processing, net			1,010		1,047	2,828	2,925

		Total revenue		161,949		124,781	485,542	348,101
Operating expenses:
	Oil and gas production			40,180		42,307	110,892	119,893
	General and administrative			11,967		9,637	31,032	27,856
	Depreciation and depletion			53,668		48,442	153,874	136,216
	Accretion of asset retirement obligation			3,456		—	9,723	—
	Impairment of oil and gas properties			—		—	135	—

		Total operating expenses		109,271		100,386	305,656	283,965

Earnings from operations				52,678		24,395	179,886	64,136
Other income and expense:
	Other expense (income), net			(822	)	5,149	5,837	8,236
	Interest expense			11,588		13,084	37,039	37,797
	Translation loss (gain) on subordinated debt			—		2,489	—	(332	)

		Total other income and expense		10,766		20,722	42,876	45,701

Earnings before income taxes and cumulative effect of change in accounting principle				41,912		3,673	137,010	18,435
Income tax expense (benefit):
	Current			(189	)	61	237	315
	Deferred			15,761		703	54,004	6,037

				15,572		764	54,241	6,352

Earnings before cumulative effect of change in accounting principle				26,340		2,909	82,769	12,083
Cumulative effect of change in accounting principle for recording asset retirement obligation, net of taxes				—		—	5,854	—

Net earnings			$	26,340		2,909	88,623	12,083

Weighted average number of common shares outstanding:
	Basic			48,244		46,974	48,098	46,912

	Diluted			49,071		48,062	48,958	48,210

Basic earnings per common share:
	Earnings before cumulative effect of change in accounting principle		$	.55		.06	1.72	.26
	Cumulative effect of change in accounting principle			—		—	.12	—

	Basic earnings per common share		$	.55		.06	1.84	.26

Diluted earnings per common share:
	Earnings before cumulative effect of change in accounting principle		$	.54		.06	1.69	.25
	Cumulative effect of change in accounting principle			—		—	.12	—

	Diluted earnings per common share		$	.54		.06	1.81	.25

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Nine Months Ended September 30,
				2003			2002
				(In Thousands)
Cash flows from operating activities:
Net earnings before cumulative effect of change in accounting principle				$	82,769		12,083
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			153,874		136,216
		Accretion of asset retirement obligation			9,723		—
		Impairment of oil and gas properties			135		—
		Amortization of deferred hedge gain			(3,321	)	—
		Amortization of deferred debt costs			1,691		1,644
		Translation gain on subordinated debt			—		(332	)
		Unrealized loss on derivative instruments, net			94		1,075
		Deferred income tax expense			54,004		6,037
		Loss on extinguishment of debt			3,975		5,089
		(Earnings) loss in equity method investee			1,775		(120	)
		Other, net			986		(1,771	)
		(Increase) decrease in accounts receivable			(26,292	)	35,878
		(Increase) decrease in other current assets			(11,851	)	5,719
		Decrease in accounts payable			(1,625	)	(73,832	)
		Increase (decrease) in accrued interest and other liabilities			(1,913	)	3,650

			Net cash provided by operating activities		264,024		131,336
Cash flows from investing activities:
	Capital expenditures for property and equipment:
		Acquisition of properties			(58,392	)	(2,801	)
		Exploration and development costs			(228,614	)	(251,764	)
		Other fixed assets			(1,589	)	(3,277	)
	Proceeds from sales of assets				12,059		3,744
	Increase in other assets, net				(901	)	(1,871	)

			Net cash used by investing activities		(277,437	)	(255,969	)
Cash flows from financing activities:
	Proceeds from bank borrowings				470,000		346,760
	Repayments of bank borrowings				(420,000	)	(283,878	)
	Issuance of 7³/4% senior notes, net of issuance costs				—		146,846
	Repurchase of 8³/4% senior subordinated notes				—		(66,248	)
	Repurchases of 10¹/2% senior subordinated notes				(69,441	)	(21,283	)
	Proceeds of common stock offering, net of offering costs				20,968		—
	Proceeds from the exercise of options and warrants				6,211		3,709
	Purchase of treasury stock				—		(560	)
	Decrease in other liabilities, net				(1,705	)	(728	)

			Net cash provided by financing activities		6,033		124,618
Effect of exchange rate changes on cash					(398	)	(591	)

Net decrease in cash and cash equivalents					(7,778	)	(606	)
Cash and cash equivalents at beginning of period					13,166		8,387

Cash and cash equivalents at end of period				$	5,388		7,781

Cash paid during the period for:
	Interest			$	31,588		31,215
	Income taxes			$	1,660		1,363

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002

(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, 2003 and the results of operations for the three and nine months ended September 30, 2003 and 2002. 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, depreciation and amortization, the amount of future net revenues used in computing the ceiling test limitations and the amount of future capital obligations used in such calculations, and the estimated amounts of future asset retirement obligations. Assumptions, judgments and estimates are also required in determining impairments of undeveloped properties and the valuation of deferred tax assets and the estimation of fair values of derivative instruments.

Certain amounts in the prior year financial statements have been reclassified to conform to the 2003 financial statement presentation. Losses related to the extinguishment of debt in 2002 were reclassified to other expense and the extraordinary item caption was deleted as a result of the Company's adoption of Statement of Financial Accounting Standards No. 145 on January 1, 2003.

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, 2002, previously filed with the Securities and Exchange Commission.

Impact of Recently Issued Accounting Pronouncements.

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141, Business Combinations, (SFAS No. 141) and Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, (SFAS No. 142). SFAS No. 141 addresses accounting and reporting for business combinations and is effective for all business combinations initiated after June 30, 2001. SFAS No. 142 addresses the accounting and reporting for acquired goodwill and other intangible assets. The new standard eliminates the requirement to amortize acquired goodwill; instead, such goodwill is required to be reviewed at least annually for impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and SFAS No. 142 had no impact on the carrying value of our goodwill or intangible assets.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and SFAS No. 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $20,000,000 to $25,000,000 at September 30, 2003 and approximately $15,000,000 to $20,000,000 at December 31, 2002, out of oil and gas properties and into a separate intangible assets line item. Our total balance sheet, cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (SFAS No. 149) was issued in April 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. The adoption of SFAS No. 149 did not have a significant effect on the Company's financial condition or results of operations.

Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150) was issued May 2003. SFAS No. 150 establishes standards for how an issuer classifies and measures three classes of freestanding financial instruments (mandatorily redeemable instruments, instruments with repurchase obligations, and instruments with obligations to issue a variable number of shares) with characteristics of both liabilities and equity. Instruments within the scope of the statement must be classified as liabilities on the balance sheet. SFAS No. 150 is effective for all freestanding financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company has not entered into any financial instruments within the scope of SFAS No. 150 since May 31, 2003, nor does it currently hold any significant financial instruments within the scope of SFAS No. 150.

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

Earnings (Loss) per Share:

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

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

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

		Three Months Ended September 30,			Nine Months Ended September 30,
		2003(1)		2002(2)	2003(3)	2002(4)
		(In Thousands Except Per Share Amounts)
Earnings before cumulative effect of change in accounting principle		$	26,340	2,909	82,769	12,083
Cumulative effect of change in accounting principle			—	—	5,854	—

Net earnings		$	26,340	2,909	88,623	12,083

Weighted average common shares outstanding during the period			48,244	46,974	48,098	46,912
	Add dilutive effects of stock options		178	363	199	494
	Add dilutive effects of warrants		649	725	661	804

Weighted average common shares outstanding including the effects of dilutive securities			49,071	48,062	48,958	48,210

Basic earnings per share before cumulative effect of change in accounting principle		$	.55	.06	1.72	.26

Basic earnings per share		$	.55	.06	1.84	.26

Diluted earnings per share before cumulative effect of change in accounting principle		$	.54	.06	1.69	.25

Diluted earnings per share		$	.54	.06	1.81	.25

(1): 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.
(2): For the three months ended September 30, 2002, options to purchase 2,610,250 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 2012.
(3): 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.
(4): For the nine months ended September 30, 2002, options to purchase 2,020,200 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 2012.

Comprehensive Earnings (Loss):

Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in the Company's other comprehensive income (loss) for the three and nine months ended September 30, 2003 and 2002 are foreign currency gains (losses) related to the translation of the assets and liabilities of the Company's Canadian operations; unrealized gains (losses) related to the change in fair value of derivative instruments designated as cash flow hedges; and unrealized gains (losses) related to the change in fair value of securities available for sale.

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

		Three Months Ended September 30,					Nine Months Ended September 30,
		2003			2002		2003		2002
		(In Thousands)
Net earnings		$	26,340		2,909		88,623		12,083
Loss on sale of treasury stock			—		—		(298	)	—
Other comprehensive income (loss):
	Foreign currency translation (losses) gains		(2,388	)	(7,662	)	35,544		1,429
	Unrealized gain (loss) on derivative instruments, net		16,373		(6,261	)	8,054		(32,469	)
	Unrealized gain on securities available for sale and other		699		36		1,480		9

Total comprehensive earnings (loss)		$	41,024		(10,978	)	133,403		(18,948	)

(3) STOCK-BASED COMPENSATION

The Company applies APB Opinion 25, Accounting for Stock Issued to Employees, and related Interpretations to account for its stock-based compensation plans. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common 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 noncompensatory plan. Had compensation cost for the Company's stock-based compensation plans been determined using the fair value of the options at the grant date as prescribed by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the Company's pro forma net earnings and earnings per common share would be as follows:

		Three Months Ended September 30,			Nine Months Ended September 30,
		2003		2002	2003	2002
		(In Thousands Except Per Share Amounts)
Net earnings:
	As reported	$	26,340	2,909	88,623	12,083

	Pro forma	$	21,039	144	76,545	2,529

Basic earnings per share:
	As reported	$	.55	.06	1.84	.26

	Pro forma	$	.44	—	1.59	.05

Diluted earnings per share:
	As reported	$	.54	.06	1.81	.25

	Pro forma	$	.43	—	1.56	.05

(4) NET PROPERTY AND EQUIPMENT

Components of net property and equipment are as follows:

	September 30, 2003			December 31, 2002
	(In Thousands)
Oil and gas properties	$	4,226,680		3,763,080
Buildings, transportation and other equipment		29,363		27,230

		4,256,043		3,790,310
Less accumulated depreciation, depletion and valuation allowance		(2,237,180	)	(2,102,425	)

	$	2,018,863		1,687,885

(5) ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003 the Company adopted 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. The Company previously recorded estimated costs of future abandonment liabilities, net of estimated salvage values, as part of its provision for depreciation and depletion for oil and gas properties without recording a separate liability for such amounts. The Company's asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

Upon adoption of SFAS No. 143, in the first quarter of 2003, the Company recorded an increase to net property and equipment of $165,370,000 ($102,321,000 net of tax), an asset retirement obligation liability of $155,972,000 ($96,467,000 net of tax) and an after tax credit of $5,854,000 for the cumulative effect of the change in accounting principle related to the depreciation and accretion amounts that would have been reported had the asset retirement obligations been recorded when incurred. Subsequent to initial measurement, the asset retirement liability is required to be accreted each period to present value. Capitalized costs are depleted as a component of the full cost pool using the units of production method.

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

	Nine Months Ended September 30, 2003
	(In Thousands)
Asset retirement obligation at beginning of period	$	—
Liability recognized in transition		155,972
Accretion expense		9,723
Liabilities incurred		3,571
Liabilities settled		(12,267	)
Impact of foreign currency exchange		947

Asset retirement obligation at end of period		157,946
Less: current asset retirement obligation		(15,264	)

Long-term asset retirement obligation	$	142,682

The following sets forth the pro forma effect on net earnings and earnings per share for the three and nine months ended September 30, 2002 as if SFAS No. 143 had been adopted on January 1, 2002:

		Three Months Ended September 30, 2002		Nine Months Ended September 30, 2002
		(In Thousands)
Net earnings:
	As reported	$	2,909	12,083

	Pro forma	$	2,597	11,013

Basic earnings per share:
	As reported	$	.06	.26

	Pro forma	$	.06	.23

Diluted earnings per share:
	As reported	$	.06	.25

	Pro forma	$	.05	.23

If SFAS No. 143 had been adopted as of January 1, 2002, the pro forma asset retirement obligation at that date would have been $141,864,000.

(6) GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill and other intangible assets recorded in the acquisition of Producers Marketing Ltd. (ProMark), the Company's Canadian gas marketing subsidiary, consist of the following:

	September 30, 2003			December 31, 2002
	(In Thousands)
Goodwill(1)	$	16,955		14,589
Long-term gas marketing contracts(1)		14,793		12,728

		31,748		27,317
Less accumulated amortization		(18,308	)	(14,792	)

	$	13,440		12,525

(1): The reported amounts for goodwill and long-term gas marketing contracts are converted to U.S. dollars at the end of each period. The increase in these reported amounts at September 30, 2003 is due to the increase in the value of the Canadian dollar relative to the U.S. dollar during the nine months ended September 30, 2003, offset by monthly amortizations to expense of the long-term gas marketing contracts. The value of the Canadian dollar was $.6364 per $1.00 U.S. at December 31, 2002 compared to $.7397 at September 30, 2003.

Goodwill is tested annually for impairment. Long-term gas marketing contracts are amortized based on estimated revenues over the life of the contracts.

(7) LONG-TERM DEBT

Components of long-term debt are as follows:

	September 30, 2003							December 31, 2002
	Principal		Unamortized Discount		Other		Total	Principal	Unamortized Discount		Other		Total
	(In Thousands)
U.S. Credit Facility	$	145,000	—		—		145,000	95,000	—		—		95,000
8% Senior Notes Due 2008		265,000	(463	)	10,838	(1)	275,375	265,000	(536	)	12,558	(1)	277,022
8% Senior Notes Due 2011		160,000	—		6,883	(1)	166,883	160,000	—		7,509	(1)	167,509
7³/4% Senior Notes Due 2014		150,000	(2,527	)	20,066	(2)	167,539	150,000	(2,706	)	14,772	(1)	162,066
10¹/2% Senior Subordinated Notes Due 2006		—	—		—		—	65,970	(348	)	—		65,622

	$	720,000	(2,990	)	37,787		754,797	735,970	(3,590	)	34,839		767,219

(1): Represents the unamortized portion of gains realized upon termination of three interest rate swaps that were accounted for as fair value hedges. The gains will be amortized as a reduction of interest expense over the terms of the note issues.
(2): Represents the unamortized portion of gains realized on termination of prior interest rate swaps accounted for as fair value hedges and the fair value of interest rate swaps accounted for as fair value hedges entered into on August 4, 2003. These current interest rate swaps were cancelled as of October 1, 2003 for a gain of $5,057,000. Both of these gains will be amortized as a reduction of interest expense over the term of the note issue.

In the first quarter of 2003, the Company redeemed the remaining $65,970,000 outstanding principal amount of its 10¹/2% Senior Subordinated Notes at 105.25% of par value, resulting in a loss of $3,975,000. No such redemptions were made in the second or third quarters of 2003.

(8) 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 2002 and 2001 the Company entered into interest rate swaps intended to exchange the fixed interest rate on a specified principal amount of the 8% Senior Notes due 2011 and the 8% Senior Notes due 2008 for a variable rate based on the London Interbank Offered Rate (LIBOR) plus specified basis points over the term of the notes. The interest rate swaps were treated as fair value hedges for accounting purposes. In August 2002, the Company sold a call option on these two interest rate swaps. The call option was not designated as a hedge. On September 30, 2002 the Company

terminated the two interest rate swaps and settled the call option. The Company received approximately $20,858,000 (net of accrued settlements of approximately $1,779,000) in connection with termination of the interest rate swaps. Those aggregate gains were deferred and added to the carrying value of the related debt, and will be amortized as reductions of interest expense over the remaining terms of the note issues. The Company recorded approximately $1,823,000 as a realized loss on derivative instruments as a result of settlement of the call option.

In 2002, the Company entered into an interest rate swap intended to exchange the fixed interest rate on a specified principal amount of the 7³/4% Senior Notes for a variable rate based on LIBOR plus specified basis points over the term of the notes. On December 27, 2002 the Company terminated this interest rate swap. The Company received approximately $14,772,000 (net of accrued settlements of approximately $1,128,000) in connection with termination of the interest rate swap. The gain was deferred and added to the carrying value of the related debt, and will be amortized as reductions of interest expense over the remaining term of the note issue.

In August 2003, the Company entered into two interest rate swaps as fair value hedges of $150,000,000 principal amount of 7³/4% Senior Notes due 2014. Under these swaps, the Company would pay a variable rate based on the six-month LIBOR plus specified basis points in exchange for a fixed rate of 7³/4% over the term of the note issue. As these interest rate swaps were fair value hedges, unrecognized gains (losses) related to these instruments were offset against unrecognized gains (losses) in the fair value of the related debt instrument in the statement of operations. The fair value of the interest rate swaps was recorded as a derivative asset (liability) with a corresponding increase (decrease) in the related debt balance. On October 1, 2003 the Company terminated these interest rate swaps.

During the third quarters of 2003 and 2002, the Company recognized reductions of interest expense of $1,119,000 and $1,492,000, respectively, under the terminated interest rate swaps, and reductions of interest expense of $938,000 due to accrued settlements of outstanding interest rate swaps.

During the first nine months of 2003 and 2002, the Company recognized reductions of interest expense of $3,321,000 and $4,590,000, respectively, under the terminated interest rate swaps, and reductions of interest expense of $938,000 due to accrued settlements of outstanding interest rate swaps.

At September 30, 2003, with respect to the two outstanding interest rate swaps, the Company had a current derivative asset of $6,269,000 with a corresponding increase in the fair value of the 7³/4% Senior Notes due 2014. Upon termination of these interest rate swaps, the Company received approximately $5,057,000 (net of accrued settlements of approximately $938,000) in connection with the termination of the interest rate swaps. The aggregate gain was deferred and added to the carrying value of the related debt, and will be amortized as a reduction of interest expense over the remaining term of the note issue.

Commodity Swaps, Collars and Basis Swaps:

Forest periodically hedges a portion of its oil and gas production through 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.

All of the Company's commodity swaps and collar agreements and a portion of its basis swaps in place at September 30, 2003 have been designated as cash flow hedges. At September 30, 2003, the Company had a derivative asset of $8,933,000 (of which $8,086,000 was classified as current), a derivative liability of $24,444,000 (of which $22,575,000 was classified as current), a deferred tax asset of $5,894,000 (of which $5,506,000 was classified as current) and accumulated other comprehensive loss of approximately $9,303,000.

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,
		2003			2002		2003		2002
		(In Thousands)
Derivatives designated as cash flow hedges		$	(12,268	)	(2,876	)	(65,713	)	5,734
Derivatives not designated as cash flow hedges			44		(72	)	(45	)	(442	)

	Total gain (loss)	$	(12,224	)	(2,948	)	(65,758	)	5,292

In a typical swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon, published third-party index when the index price is lower. When 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, 2003, 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 Barrel
Fourth Quarter 2003	60.2	$	4.52	7,000	$	23.16
First Quarter 2004	—	$	—	7,000	$	23.95
Second Quarter 2004	30.0	$	4.27	9,000	$	24.75
Third Quarter 2004	30.0	$	4.27	7,000	$	24.34
Fourth Quarter 2004	10.1	$	4.27	3,000	$	23.33

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

only when the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only when the index price is above the ceiling price. In addition, Forest has entered into three-way collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any additional amounts. If the index price is above the ceiling, the Company pays the excess over 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 production. As of September 30, 2003, the Company had entered into the following gas and oil collars accounted for as cash flow hedges:

	Natural Gas
	BBTUs Per Day	Average Floor Price Per MMBTU		Average Ceiling Price Per MMBTU
Fourth Quarter 2003	39.9	$	3.74	$	5.28
First Quarter 2004	60.0	$	4.04	$	5.79

	Oil (NYMEX WTI)
	Barrels Per Day	Average Floor Price Per BBL		Average Ceiling Price Per BBL
Fourth Quarter 2003	3,000	$	22.00	$	25.42
First Quarter 2004	2,000	$	22.00	$	24.08

As of September 30, 2003, Forest had entered into the following 3-way 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
First Quarter 2004	30.0	$	3.50	$	5.27	$	8.75
Second Quarter 2004	25.0	$	3.50	$	4.75	$	5.80
Third Quarter 2004	25.0	$	3.50	$	4.75	$	5.80
Fourth Quarter 2004	11.7	$	3.50	$	4.75	$	6.14

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, 2003 there were basis swaps designated as cash flow hedges in place with weighted

average volumes of 60.2 BBTUs per day for the remainder of 2003 and weighted average volumes of 11.7 BBTUs per day for 2004. At September 30, 2003 there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 39.9 BBTUs per day for the remainder of 2003 and weighted average volumes of 43.8 BBTUs per day for 2004.

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.

(9) LEGAL PROCEEDINGS

Forest, in the ordinary course of business, is a party to various legal actions. While we believe that the amount of any potential loss would not be material to our consolidated financial position, the ultimate outcome of these proceedings is inherently difficult to predict with any certainty. In the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow in the reporting periods in which any such actions are resolved.

On May 1, 2002, the State of Alaska approved the development and production phase of our Redoubt Shoal Project (the Production Project). On May 30, 2002, Cook Inlet Keeper, a non-governmental third party, filed a challenge to the regulatory review and approval process for the Production Project. In July 2002, Forest was granted leave to intervene to defend the State of Alaska's approval of the Production Project. In August 2002, the Superior Court in Anchorage, Alaska (the trial court), entered a briefing schedule. That briefing has been completed, and oral argument before the trial court occurred on April 17, 2003. The trial court has taken the matter under advisement and has not indicated how quickly it might rule.

Separately, Cook Inlet Keeper filed a motion in September 2002 asking the trial court to stay Forest's development and production phase operations during the pendency of the briefing process and through the trial court's final determination regarding the challenge. Forest filed an opposition, and the trial court denied Cook Inlet Keeper's motion on December 4, 2002. Cook Inlet Keeper appealed that denial to the Alaska Supreme Court. Forest subsequently filed an opposition. On March 14, 2003, the Alaska Supreme Court remanded the matter to the trial court for clarification of the court's ruling, and postponed ruling on the petition for review until receipt of that clarification. The trial court provided that clarification on April 23, 2003, and on June 9, 2003, the Alaska Supreme Court denied Cook Inlet Keeper's petition. Further, in June 2003, certain legislation was signed into law by the Governor of Alaska that may impact Cook Inlet Keeper's challenge. Forest has advised the trial court of the legislation's existence and has submitted a brief on the potential impact on the litigation. While we intend to continue our vigorous opposition to Cook Inlet Keeper's challenge, the outcome of the litigation is inherently difficult to predict with any certainty. We can give no assurances as to the effect of any delays in the Production Project on Forest's financial condition and results of operations.

(10) MARKETING AND PROCESSING OPERATIONS

The Company's gas marketing subsidiary, ProMark, operates the ProMark Netback Pool. The ProMark Netback Pool matches major end users with providers of gas supply through arranged transportation channels, and uses a netback pricing mechanism to establish the wellhead price paid to all producers within the pool. Under this netback arrangement, producers receive the blended price less related transportation and other direct costs. ProMark charges a marketing fee to the pool participant producers for marketing and administering the gas supply pool.

In addition to operating the ProMark Netback Pool, ProMark provides other marketing services for other producers and consumers of natural gas. ProMark manages long-term gas supply contracts for industrial customers and provides full-service purchasing, accounting and gas nomination services for both producers and customers on a fee-for-service basis.

Processing income consists of fees earned, net of expenses, attributable to volumes processed on behalf of third parties.

Components of marketing and processing, net consist primarily of ProMark activity and are as follows:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2003		2002	2003	2002
	(In Thousands)
Marketing and processing revenue	$	92,788	50,655	283,302	176,004
Marketing and processing expense		91,778	49,608	280,474	173,079

Marketing and processing, net	$	1,010	1,047	2,828	2,925

(11) 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. Forest has six reportable segments consisting of oil and gas operations in five business units (Gulf Region, Western United States, Alaska, Canada and International), and marketing and processing operations conducted primarily by ProMark in Canada. In the first quarter of 2003 the Company modified its business unit structure by combining the Gulf of Mexico Offshore Region and the Gulf Coast Onshore Region into the Gulf Region for increased efficiencies. Therefore, segment information for the 2002 periods has been restated to give effect to this combination. The segments were determined based upon the type of operations in each business unit and the geographical location of each. The segment data presented below was prepared on the same basis as the consolidated financial statements.

Three Months Ended September 30, 2003

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International	Total Company
		(In Thousands)
Revenue		$	96,509	25,275	22,216	144,000	16,939	160,939	1,010	—	161,949
Expenses:
	Oil and gas production		19,624	5,748	10,530	35,902	4,278	40,180	—	—	40,180
	General and administrative		3,040	859	1,090	4,989	459	5,448	408	—	5,856
	Depletion and amortization		33,720	4,274	6,683	44,677	7,101	51,778	365	—	52,143
	Accretion		2,485	235	602	3,322	134	3,456	—	—	3,456

Earnings from operations		$	37,640	14,159	3,311	55,110	4,967	60,077	237	—	60,314

Capital expenditures		$	48,855	40,992	11,977	101,824	17,067	118,891	—	2,013	120,904

Property and equipment, net		$	943,181	283,002	424,758	1,650,941	290,384	1,941,325	—	71,756	2,013,081

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

		(In Thousands)
Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Principle:
	Earnings from operations for reportable segments	$	60,314
	Corporate general and administrative expense		(6,111	)
	Administrative asset depreciation		(1,525	)
	Other income, net		822
	Interest expense		(11,588	)

	Earnings before income taxes and cumulative effect of accounting change	$	41,912

Nine Months Ended September 30, 2003

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International		Total Company
		(In Thousands)
Revenue		$	298,581	76,438	58,653	433,672	49,042	482,714	2,828	—		485,542
Expenses:
	Oil and gas production		51,865	17,369	31,185	100,419	10,473	110,892	—	—		110,892
	General and administrative		8,517	2,305	3,800	14,622	3,103	17,725	1,165	—		18,890
	Depletion and amortization		96,618	12,697	20,252	129,567	19,402	148,969	1,069	—		150,038
	Accretion		6,984	675	1,674	9,333	390	9,723	—	—		9,723
	Impairment		—	—	—	—	—	—	—	135		135

Earnings from operations		$	134,597	43,392	1,742	179,731	15,674	195,405	594	(135	)	195,864

Capital expenditures		$	134,521	59,360	52,476	246,357	36,500	282,857	—	4,149		287,006

Property and equipment, net		$	943,181	283,002	424,758	1,650,941	290,384	1,941,325	—	71,756		2,013,081

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

		(In Thousands)
Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Principle:
	Earnings from operations for reportable segments	$	195,864
	Corporate general and administrative expense		(12,142	)
	Administrative asset depreciation		(3,836	)
	Other expense, net		(5,837	)
	Interest expense		(37,039	)

	Earnings before income taxes and cumulative effect of change in accounting principle	$	137,010

Three Months Ended September 30, 2002

		Oil and Gas Operations
		Gulf		Western	Alaska		Total United States	Canada	Total	Marketing and Processing	International		Total Company
		(In Thousands)
Revenue		$	78,771	15,878	16,416		111,065	12,669	123,734	1,047	—		124,781
Expenses:
	Oil and gas production		21,177	5,870	11,372		38,419	3,888	42,307	—	—		42,307
	General and administrative		4,984	1,354	1,772		8,110	1,177	9,287	350	—		9,637
	Depletion		31,972	4,640	4,756		41,368	5,602	46,970	323	—		47,293

Earnings from operations		$	20,638	4,014	(1,484	)	23,168	2,002	25,170	374	—		25,544

Capital expenditures		$	28,982	9,018	34,652		72,652	3,969	76,621	—	(1,250	)	75,371

Property and equipment, net		$	790,617	231,675	314,120		1,336,412	230,455	1,566,867	—	63,984		1,630,851

Information for reportable segments relates to the Company's September 30, 2002 consolidated totals as follows:

		(In Thousands)
Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Principle:
	Earnings from operations for reportable segments	$	25,544
	Administrative asset depreciation		(1,149	)
	Other expense, net		(5,149	)
	Interest expense		(13,084	)
	Translation gain on subordinated debt		(2,489	)

	Earnings before income taxes and cumulative effect of accounting change	$	3,673

Nine Months Ended September 30, 2002

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International	Total Company
						(In Thousands)
Revenue		$	212,644	43,902	51,067	307,613	37,563	345,176	2,925	—	348,101
Expenses:
	Oil and gas production		62,875	15,819	30,543	109,237	10,656	119,893	—	—	119,893
	General and administrative		13,782	4,324	5,169	23,275	3,498	26,773	1,083	—	27,856
	Depletion		91,063	12,798	13,334	117,195	15,532	132,727	611	—	133,338

Earnings from operations		$	44,924	10,961	2,021	57,906	7,877	65,783	1,231	—	67,014

Capital expenditures		$	88,831	32,729	104,051	225,611	17,125	242,736	—	11,829	254,565

Property and equipment, net		$	790,617	231,675	314,120	1,336,412	230,455	1,566,867	—	63,984	1,630,851

Information for reportable segments relates to the Company's September 30, 2002 consolidated totals as follows:

		(In Thousands)
Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Principle:
	Earnings from operations for reportable segments	$	67,014
	Administrative asset depreciation		(2,878	)
	Other expense, net		(8,236	)
	Interest expense		(37,797	)
	Translation gain on subordinated debt		332

	Loss before income taxes and cumulative effect of change in accounting principle	$	18,435

(12) SUBSEQUENT EVENTS

In September 2003, the Company announced an agreement with Union Oil Company of California (Unocal) to purchase properties located in the Gulf of Mexico and onshore Gulf Coast. The transaction closed on October 31, 2003. The estimated proved reserves acquired at closing were approximately 138 BCFE and the purchase price at closing was approximately $211,000,000. The acquisition was funded in part by the proceeds from the common stock offering mentioned below and by borrowings under the Company's U.S. credit facility.

In October 2003 the Company issued 5,123,000 shares of common stock at a price of $23.10 per share. Net proceeds from this offering were approximately $112,600,000 after deducting underwriting discounts and commissions and estimated offering expenses. Forest used the net proceeds from the offering to fund a portion of the acquisition of properties from Unocal.

On November 10, 2003, the Company entered into an agreement to purchase 100% of the stock of a private company with oil and gas assets located primarily in the Permian Basin and in five fields in South Texas. Proved reserves to be acquired are estimated at 102 BCFE. The acquisition will include working capital, oil and gas assets and certain other financial assets and liabilities of the seller. The amount of consideration for the oil and gas assets, including all land, pipelines, facilities and offices, is estimated to be approximately $102,000,000 at closing. Forest intends to utilize its credit facility to fund the purchase price. The transaction is expected to close on December 31, 2003, subject to customary closing conditions.

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 2002 Annual Report on Form 10-K. Unless the context otherwise indicates, references in this quarterly report on Form 10-Q to "Forest," "Company," "we," "ours," "us" or like terms refer to Forest Oil Corporation and its subsidiaries.

Forward-Looking Statements

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or present facts, that address activities, events, outcomes and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Forest cautions that these forward-looking statements, including without limitation those relating to estimates of our future natural gas and liquids production, including estimates of any increases in oil and gas production, our outlook on oil and gas prices, estimates of our oil and gas reserves, estimates of asset retirement obligations, planned capital expenditures and availability of capital resources to fund capital expenditures, the impact of political and regulatory developments, our future financial condition or results of operations and our future revenues and expenses, and our business strategy and other plans and objections for future operations, are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil and gas, many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and the timing of development expenditures and other risks as described in Management's Discussion and Analysis of Financial Condition and Results of Operations in Forest's 2002 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. The financial results of our foreign operations are also subject to currency exchange rate risks. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Forest's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements express or implied attributable to Forest are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that Forest or persons acting on its behalf may issue. Forest does not undertake to update any forward-looking statements to reflect events or circumstances after the date of filing this Form 10-Q with the Securities and Exchange Commission, except as required by law.

Results of Operations for the Third Quarter of 2003

Net earnings for the third quarter of 2003 were $26,340,000 compared to $2,909,000 in the corresponding period of 2002. Higher earnings for the quarter ended September 30, 2003 compared to the corresponding period of 2002 were primarily the result of increased operating margins from the combination of higher average oil and gas sales prices and lower oil and gas production expense.

Marketing and processing, net represents the net margin earned by Producers Marketing Ltd. (ProMark) our Canadian gas marketing subsidiary, as well as processing income earned, net of

expenses. Marketing and processing, net remained relatively flat at $1,010,000 in the third quarter of 2003 compared to $1,047,000 in the third quarter of 2002.

Oil and gas sales revenue increased by 30% to $160,939,000 in the third quarter of 2003 from $123,734,000 in the third quarter of 2002 as a result of higher product prices. The average gas sales price increased 53% for the third quarter of 2003 compared to the same period of 2002. The average liquids sales price increased 12% compared to the average price in the same period of 2002.

For the third quarter of 2003, Forest reported sales volumes that were approximately the same as those reported for the same period of 2002. In the United States, Forest's oil and gas sales volumes remained constant compared to the corresponding prior year period. In Canada, Forest's sales volumes decreased 6% due primarily to higher royalty volumes in the current higher price environment, plant maintenance and the effects of property divestitures made in 2002.

Oil and gas production expense includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of workovers that are expensed rather than capitalized because they do not extend the life of the property, product transportation costs, production taxes and ad valorem taxes. Oil and gas production expense for the third quarter of 2003 decreased 5% to $40,180,000 compared to $42,307,000 in the corresponding period in 2002. On a per-unit basis, production expense decreased 4% to $1.09 per MCFE in the third quarter of 2003 compared to $1.14 per MCFE in the third quarter of 2002. All business units contributed to the reduction in lease operating expense, which were achieved despite higher production and ad valorem taxes in all business units.

Sales volumes, weighted average sales prices and oil and gas production expense per MCFE for the three months ended September 30, 2003 and 2002 were as follows:

				Three Months Ended September 30,
				2003			2002
Natural Gas
	Sales volumes (MMCF):
		United States			20,677		20,285
		Canada			3,382		3,328

			Total		24,059		23,613
	Sales price received (per MCF)			$	4.76		2.84
	Effects of energy swaps and collars (per MCF)(1)				(.26	)	.10

	Average sales price (per MCF)(2)			$	4.50		2.94
Liquids
Oil and condensate:
	Sales volumes (MBBLS)				1,923		1,945
	Sales price received (per BBL)			$	28.58		26.44
	Effects of energy swaps and collars (per BBL)(1)				(3.14	)	(2.75	)

	Average sales price (per BBL)			$	25.44		23.69
Natural gas liquids:
	Sales volumes (MBBLS)				206		297
	Average sales price (per BBL)			$	18.47		12.35
Total liquids sales volumes (MBBLS):
	United States				1,887		1,942
	Canada				242		300

			Total		2,129		2,242
	Average sales price (per BBL)			$	24.76		22.19
Total sales volumes
	Sales volumes (MMCFE):
		United States			31,999		31,937
		Canada			4,834		5,128

			Total		36,833		37,065

Average sales price (per MCFE)				$	4.37		3.22
Oil and gas production expense (per MCFE)				$	1.09		1.14

(1): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 11,040 MMCF and 6,900 MMCF in the third quarter of 2003 and 2002, respectively. Hedged oil and condensate volumes were 966,000 barrels and 920,000 barrels in the third quarter of 2003 and 2002, respectively. Most of these arrangements have been designated as cash flow hedges for accounting purposes and, as a result, 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 $12,268,000 and $2,876,000 for the three months ended September 30, 2003 and 2002, respectively. Those arrangements that are not designated as cash flow hedges for accounting purposes are recorded as non-operating income or expense.
(2): Oil and gas sales revenue for the third quarter ended September 30, 2002 included $4,500,000 of proceeds from business interruption insurance. The average gas sales prices presented above for these periods exclude the effects of the insurance proceeds.

General and administrative expense increased to $11,967,000 for the quarter ended September 30, 2003 compared to $9,637,000 for the same period in 2002. The increase resulted primarily from severance costs of approximately $2,600,000 and increased insurance costs, offset partially by lower employee related costs and the positive effects of cost reduction measures in corporate areas.

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

		Three Months Ended September 30,
		2003		2002
		(In Thousands)
Overhead costs capitalized		$	7,135	5,735
General and administrative costs expensed(1)			11,967	9,637

	Total overhead costs	$	19,102	15,372

(1): Includes $408,000 and $350,000 related to marketing operations for the three months ended September 30, 2003 and 2002, respectively.

Depreciation and depletion expense was $53,668,000 in the third quarter of 2003 compared to $48,442,000 in the third quarter of 2002. On a per-unit basis, the depletion rate was $1.42 per MCFE for the quarter ended September 30, 2003, compared to $1.28 per MCFE in the corresponding prior year period. The higher rate in the third quarter of 2003 was due primarily to higher finding costs in the last quarter of 2002 and the first nine months of 2003.

Accretion expense of $3,456,000 in the third quarter of 2003 was related to the accretion of Forest's asset retirement obligation pursuant to Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (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 $102,321,000 (net of tax), an asset retirement obligation liability of $96,467,000 (net of tax) and an after tax credit of $5,854,000 for the cumulative effect of the change in accounting principle.

Other income of $822,000 in the third quarter of 2003 was attributable primarily to recovery of a bankruptcy claim that was written off in a prior year. Other expense of $5,149,000 in the third quarter of 2002 consisted primarily of a $3,091,000 loss on extinguishment of debt from the redemption of $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value and realized and unrealized losses on derivative instruments.

Interest expense was $11,588,000 in the third quarter of 2003 compared to $13,084,000 in the third quarter of 2002. The effects of higher average debt balances were more than offset by lower average interest rates on variable and fixed rate debt and by amortizations of gains recognized on termination of interest rate swaps.

There was a foreign currency translation loss of $2,489,000 in the third quarter of 2002 which was the result of translation of the 8³/4% Senior Subordinated Notes issued by Canadian Forest Oil, Ltd., our Canadian subsidiary (Canadian Forest). All of the outstanding notes were redeemed on September 15, 2002.

Forest recorded a current income tax benefit of $189,000 in the third quarter of 2003 compared to current income tax expense of $61,000 in the third quarter of 2002. The benefit in 2003 resulted from a decrease in the accrued alternative minimum tax for the year.

Deferred income tax expense was $15,761,000 in the third quarter of 2003 compared to $703,000 in the third quarter of 2002. The increase in deferred tax expense is attributable to increased pre-tax profitability which did not create a current tax liability due to timing differences and Forest's net operating loss carryforward.

Results of Operations for the Nine Months Ended September 30, 2003

Net earnings for the nine months ended September 30, 2003 were $88,623,000 compared to $12,083,000 in the corresponding period of 2002. Higher earnings for the 2003 period were primarily the result of increased operating margins from the combination of higher average oil and gas sales prices and lower oil and gas production expense.

Marketing and processing, net represents the net margin earned by ProMark as well as processing income earned, net of expenses. Marketing and processing, net remained relatively flat at $2,828,000 for the nine months ended September 30, 2003 compared to $2,925,000 in the same period of 2002.

Oil and gas sales revenue increased by 40% to $482,714,000 for the nine months ended September 30, 2003 compared to $345,176,000 in the same period of 2002, as a result of higher product prices. The average gas sales price increased 58% for the nine months ended September 30, 2003 compared to the same period of 2002. The average liquids sales price increased 19% compared to the average price in the same period in 2002.

For the nine months ended September 30, 2003, Forest reported sales volumes that were approximately the same as those reported for the same period of 2002. In the United States, Forest's liquids sales volumes remained constant while gas sales volumes increased 3% for a total increase in equivalent gas production of approximately 2% in the nine months ended September 30, 2003 compared to the corresponding prior year period. The increase was attributable primarily to new gas production in the Gulf Coast Business Unit. In Canada, Forest's sales volumes decreased 14% in the nine months ended September 30, 2003, due primarily to higher royalty volumes in the current higher price environment, plant maintenance and the effects of property divestitures made in 2002.

Oil and gas production expense includes direct costs incurred to operate and maintain wells and related equipment and facilities, costs of workovers that are expensed rather than capitalized because they do not extend the life of the property, product transportation costs, production taxes and ad valorem taxes. Oil and gas production expense for the nine months ended September 30, 2003 decreased 8% to $110,892,000 compared to $119,893,000 in the corresponding period in 2002. On a per-unit basis, production expense decreased 7% to $1.02 per MCFE for the nine months ended September 30, 2003 compared to $1.10 per MCFE for the nine months ended September 30, 2002. All business units contributed to the reduction in lease operating expense, which were achieved despite higher production and ad valorem taxes in all business units.

Sales volumes, weighted average sales prices and oil and gas production expense per MCFE for the nine months ended September 30, 2003 and 2002 were as follows:

				Nine Months Ended September 30,
				2003			2002
Natural Gas
	Sales volumes (MMCF):
		United States			60,663		58,685
		Canada			9,235		10,670

			Total		69,898		69,355
	Sales price received (per MCF)			$	5.24		2.73
	Effects of energy swaps and collars (per MCF)(1)				(.63	)	.19

	Average sales price (per MCF)(2)			$	4.61		2.92
Liquids
Oil and condensate:
	Sales volumes (MBBLS)				5,792		5,726
	Sales price received (per BBL)			$	29.20		23.69
	Effects of energy swaps and collars (per BBL)(1)				(3.77	)	(1.30	)

	Average sales price (per BBL)			$	25.43		22.39
Natural gas liquids:
	Sales volumes (MBBLS)				672		862
	Average sales price (per BBL)			$	19.92		11.31
Total liquids sales volumes (MBBLS):
	United States				5,694		5,691
	Canada				770		897

			Total		6,464		6,588
	Average sales price (per BBL)			$	24.86		20.94
Total sales volumes
	Sales volumes (MMCFE):
		United States			94,827		92,831
		Canada			13,855		16,052

			Total		108,682		108,883
Average sales price (per MCFE)				$	4.44		3.13
Oil and gas production expense (per MCFE)				$	1.02		1.10

(1): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 35,900 MMCF and 24,260 MMCF for the nine months ended September 30, 2003 and 2002, respectively. Hedged oil and condensate volumes were 3,409,500 barrels and 3,002,000 barrels for the nine months ended September 30, 2003 and 2002, respectively. Most of these arrangements have been designated as cash flow hedges for accounting purposes and, as a result, the net gains and losses were accounted for as increases and decreases of oil and gas sales. The aggregate net (losses) gains related to our cash flow hedges were $(65,713,000) and $5,734,000 for the nine months ended September 30, 2003 and 2002, respectively. Those arrangements that are not designated as cash flow hedges for accounting purposes are recorded as non-operating income or expense.
(2): Oil and gas sales revenue for the nine months ended September 30, 2002 included $4,500,000 of proceeds from business interruption insurance. The average gas sales prices presented above for these periods exclude the effects of the insurance proceeds.

General and administrative expense increased to $31,032,000 for the nine months ended September 30, 2003 compared to $27,856,000 for the same period in 2002. The increase resulted primarily from $3,600,000 attributable to severance costs and costs incurred to terminate a Canadian

defined benefit pension plan and increased insurance costs, offset partially by lower employee related costs and the positive effects of cost reduction measures in corporate areas.

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

		Nine Months Ended September 30,
		2003		2002
		(In Thousands)
Overhead costs capitalized		$	18,064	19,148
General and administrative costs expensed(1)			31,032	27,856

	Total overhead costs	$	49,096	47,004

(1): Includes $1,165,000 and $1,083,000 related to marketing operations for the nine months ended September 30, 2003 and 2002, respectively.

Depreciation and depletion expense was $153,874,000 for the nine months ended September 30, 2003 compared to $136,216,000 for the corresponding period of 2002. On a per-unit basis, the depletion rate was $1.38 per MCFE for the nine months ended September 30, 2003, compared to $1.22 per MCFE in the corresponding prior year period. The higher rate for the nine months ended September 30, 2003 was due primarily to higher finding costs in the last quarter of 2002 and first nine months of 2003.

Accretion expense of $9,723,000 for the nine months ended September 30, 2003 was related to the accretion of Forest's asset retirement obligation pursuant to SFAS No. 143, adopted January 1, 2003. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Using a cumulative effect approach, in the first quarter of 2003 Forest recorded an increase to net property and equipment of $102,321,000 (net of tax), an asset retirement obligation liability of $96,467,000 (net of tax) and an after tax credit of $5,854,000 for the cumulative effect of the change in accounting principle.

Other expense of $5,837,000 for the nine months ended September 30, 2003 included a loss on early extinguishment of debt of approximately $3,975,000 related to Forest's redemption in January 2003 of its remaining 10¹/2% Senior Subordinated Notes at 105.25% of par value as well as Forest's share of the net loss recorded by an equity method investee. Other expense of $8,236,000 for the same period of 2002 was due primarily to franchise taxes, losses on extinguishment of debt related to Forest's repurchase of $19,710,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 108% of par value, the repurchase of $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value, the redemption of $57,948,000 of 8³/4% Senior Subordinated Notes at 104.375% of par value, and realized and unrealized losses on derivative instruments.

Interest expense for the nine months ended September 30, 2003 was $37,039,000 compared to $37,797,000 for the corresponding period of 2002. The effects of higher average debt balances were more than offset by lower average interest rates on variable and fixed rate debt and by amortization of gains recognized on termination of interest rate swaps.

There was a foreign currency translation gain of $332,000 for the nine months ended September 30, 2002 which was the result of translation of the 8³/4% Senior Subordinated Notes issued by Canadian Forest. All of the outstanding notes were redeemed on September 15, 2002.

Forest recorded current income tax expense of $237,000 in the nine months ended September 30, 2003 compared to $315,000 in the corresponding period of 2002. The decrease in the 2003 period resulted from a decrease in estimated alternative minimum taxes.

Deferred income tax expense was $54,004,000 for the nine months ended September 30, 2003 compared to $6,037,000 for the same period of 2002. The increase in deferred tax expense is attributable primarily to increased pre-tax profitability, which did not create a current tax liability due to timing differences and Forest's net operating loss carryforward.

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 our 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, the issuance of net profits interests, sales of non-strategic assets, prospects and technical information, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

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

Forest had a working capital deficit, exclusive of the effects of derivatives, of approximately $3,954,000 at September 30, 2003 compared to a working capital deficit of approximately $15,159,000 at December 31, 2002. The increase in working capital was due primarily to an increase in accounts receivable attributable primarily to higher oil and gas prices and insurance claims for hurricane damage.

Cash Flow. Historically, one of our primary sources of capital has been net cash provided by operating activities. Net cash provided by operating activities was $264,024,000 for the nine months ended September 30, 2003 compared to $131,336,000 in the same period in 2002. The increase was due primarily to higher average oil and gas prices. Net cash used for investing activities was $277,437,000 for the nine months ended September 30, 2003 compared to $255,969,000 in the same period of 2002. The increase was due primarily to increased exploration and development activities, partially offset by higher proceeds from sales of assets. Net cash provided by financing activities was $6,033,000 for the nine months ended September 30, 2003 compared to $124,618,000 in the same period of 2002. The nine months ended September 30, 2003 included cash used for the repurchases of the 10¹/2% Senior Subordinated Notes of $69,441,000, which was more than offset by net bank borrowings of $50,000,000 and net proceeds from the issuance of common stock and the exercise of options and warrants of approximately $27,179,000. The corresponding period of 2002 included net borrowings of bank debt of $62,882,000 and net proceeds of $146,846,000 from the issuance of the 7³/4% Senior Notes, offset by

repurchases of the 10¹/2% Senior Subordinated Notes of $21,283,000 and repurchases and redemptions of the 8³/4% Senior Subordinated Notes of $66,248,000.

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

		Nine Months Ended September 30,
		2003		2002
		(In Thousands)
Property acquisition costs:
	Proved properties	$	56,692	2,801
	Undeveloped properties		1,700	—

			58,392	2,801
Exploration costs:
	Direct costs		67,823	70,250
	Overhead capitalized		10,257	9,675

			78,080	79,925
Development costs:
	Direct costs		142,727	162,366
	Overhead capitalized		7,807	9,473

			150,534	171,839

Total capital expenditures for property acquisition, exploration and development(1)		$	287,006	254,565

(1): Does not include estimated discounted future abandonment costs of $3,571,000 related to assets placed in service during the nine months ended September 30, 2003.

Forest's anticipated expenditures for exploration and development in 2003 are estimated to range from $575,000,000 to $600,000,000, including approximately $260,000,000 related to acquisitions. We intend to meet our 2003 capital expenditure financing requirements using cash flows generated by operations, sales of non-strategic assets, the proceeds from the common stock offering in October 2003 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 experience increased cash flow or access additional sources of capital.

In September 2003, Forest announced an agreement with Union Oil Company of California (Unocal) to purchase properties located in the Gulf of Mexico and onshore Gulf Coast. The transaction closed on October 31, 2003. The estimated proved reserves acquired at closing were approximately 138 BCFE and the purchase price at closing was approximately $211,000,000. The purchase price was originally estimated to be $260,000,000, but was reduced as a result of closing adjustments and the exercise of preferential purchase rights by third parties. Forest may purchase additional properties from Unocal pursuant to the purchase agreement; the purchase price for these additional properties is expected to fall within the range of $5,000,000 to $10,000,000. The Unocal acquisition was funded in part by proceeds from a common stock offering and by borrowings under Forest's U.S. credit facility.

Bank Credit Facilities. We have credit facilities totaling $600,000,000, consisting of a $500,000,000 U.S. credit facility through a syndicate of banks led by JPMorgan Chase and a $100,000,000 Canadian credit facility through a syndicate of banks led by J.P. Morgan Bank Canada. The credit facilities mature in October 2005. Under the credit facilities, Forest, Canadian Forest and certain of their subsidiaries are subject to certain covenants and financial tests, including restrictions or requirements with respect to dividends, additional debt, liens, asset sales, investments, hedging activities, mergers and reporting responsibilities. These financial covenants will affect the amount available and our ability to borrow amounts under the credit facility. In addition, if the rating on our bank credit facilities is downgraded below BB+ by Standard & Poor's Rating Services (S&P) and Ba1 by Moody's Investors Services (Moody's), the available borrowing amount under the credit facilities would be determined by a formula based on the value of certain oil and gas properties (a borrowing base) subject to semi-annual re-determination. As a result, the available borrowing amount could be increased or reduced under the borrowing base tests.

We recently entered into an amendment to the credit facilities effective October 30, 2003. The amendment allows us the option of electing to have availability under the credit facilities governed by a borrowing base ("Global Borrowing Base"), rather than financial covenants. The determination of the Global Borrowing Base is made by the lenders taking into consideration the estimated value of the oil and gas properties in accordance with their customary practices for oil and gas loans. Forest can exercise the option one time per year and any such election will be irrevocable for a period of one year. In connection with the amendment, effective as of October 30, 2003, we elected to determine availability based on the Global Borrowing Base. Effective October 30, 2003, the Global Borrowing base was set at $525,000,000, with $475,000,000 allocated to the U.S. credit facility and with $50,000,000 allocated to the Canadian credit facility. Under the Global Borrowing Base, availability will be re-determined semi-annually.

At September 30, 2003, under the most restrictive of the financial covenants contained in our credit facilities, the unused borrowing amount under the credit facilities was approximately $163,000,000 in addition to amounts outstanding. At November 4, 2003, under the credit facility as amended, our unused borrowing amount was approximately $310,000,000 in addition to amounts outstanding.

At September 30, 2003, there were outstanding borrowings of $145,000,000 under the U.S. credit facility at a weighted average interest rate of 2.47%, and there were no outstanding borrowings under the Canadian credit facility. At November 4, 2003, there were outstanding borrowings of $205,000,000 under the U.S. credit facility and $1,515,000 under the Canadian credit facility, at a weighted average interest rate of 2.27%. At September 30, 2003, we had used the credit facilities for letters of credit in the amount of $7,555,000. At November 4, 2003, we had used the credit facilities for letters of credit in the amount of $5,703,000.

Under the Global Borrowing Base, the lenders will periodically re-determine Forest's availability based on their estimated valuation of our oil and gas properties. If a borrowing base re-determination is less than the outstanding borrowings under the credit facilities, we would be required to repay the

amount representing the excess of outstanding borrowings within a prescribed period. If we were unable to pay the excess amount, it would cause an event of default.

Our U.S. credit facility is secured by a lien on, and a security interest in, a portion of our proved oil and gas properties and related assets in the United States and Canada, a pledge of 65% of the capital stock of Canadian Forest and its parent, 3189503 Canada Ltd., and a pledge of 100% of the capital stock of Forest Pipeline Company. Under certain circumstances, we could be obligated to pledge additional objects as collateral.

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

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

Securities Issued. In January 2003, we issued 7,850,000 shares of common stock at a price of $24.50 per share. Net proceeds from this offering (before any exercise of the underwriters' over-allotment option), were approximately $184,400,000 after deducting underwriting discounts and commissions and the estimated expenses of the offering. Forest used the net proceeds from the offering to repurchase, immediately following the closing of the offering, 7,850,000 shares of common stock from The Anschutz Corporation and certain of its affiliates. The shares repurchased were cancelled immediately upon repurchase. In February 2003, an additional 900,000 shares of common stock were issued pursuant to exercise of the underwriters' over-allotment option. The net proceeds of $21,168,000 were used for general corporate purposes.

In October 2003, Forest issued 5,123,000 shares of common stock at a price of $23.10 per share. Net proceeds from this offering were approximately $112,600,000 after deducting underwriting discounts and commissions and estimated offering expenses. Forest used the net proceeds from the offering to fund a portion of the acquisition of properties from Unocal.

Securities Redeemed. In the first quarter of 2003 we redeemed the remaining $65,970,000 outstanding principal amount of our 10¹/2% Senior Subordinated Notes at 105.25% of par value.

Impact of Recently Issued Accounting Pronouncements.

Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150) was issued May 2003. SFAS No. 150 establishes standards for how an issuer classifies and measures three classes of freestanding financial instruments (mandatorily redeemable instruments, instruments with repurchase obligations, and instruments with obligations to issue a variable number of shares) with characteristics of both liabilities and equity. Instruments within the scope of the statement must be classified as liabilities on the balance sheet. SFAS No. 150 is effective for all freestanding financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. Forest has not entered into any financial instruments within the scope of SFAS No. 150 since May 31, 2003, nor does it currently hold any significant financial instruments within the scope of SFAS No. 150.

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 and, through ProMark, our marketing subsidiary, we market natural gas for third parties in 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, Forest enters into commodity swaps, collars and other financial instruments. All of our commodity swaps and collar agreements and a portion of our basis swaps in place at September 30, 2003 have been designated as cash flow hedges. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons. We periodically assess the estimated portion of our anticipated production that is subject to hedging arrangements, and we adjust this

percentage based on our assessment of market conditions and the availability of hedging arrangements that meet our criteria. Hedging arrangements covered 52% and 40% of our consolidated production, on an equivalent basis, during the nine months ended September 30, 2003 and 2002, respectively.

Long-Term Sales Contracts. A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool which is operated by ProMark on behalf of Canadian Forest. At September 30, 2003, the ProMark Netback Pool had entered into fixed price contracts to sell natural gas at the following quantities and weighted average prices:

	Natural Gas
	BCF	Weighted Average Sales Price Per MCF
Fourth Quarter of 2003	1.4	$	2.65 CDN
2004	5.5	$	2.70 CDN
2005	5.5	$	2.80 CDN
2006	5.5	$	2.91 CDN
2007	5.5	$	3.02 CDN
2008	5.5	$	3.13 CDN
2009	3.0	$	3.97 CDN
2010	1.7	$	5.42 CDN
2011	0.7	$	5.72 CDN

As operator of the netback pool, ProMark aggregates gas from producers for sale to markets across North America. Currently, over 30 producers have contracted with the netback pool including Canadian Forest. The producers are paid a netback price which reflects all of the revenue from approved customers less the costs of delivery (including transportation, audit and shortfall makeup costs) and a ProMark marketing fee.

Canadian Forest, as one of the producers in the netback pool, is obligated to supply its contract quantity. In 2002, Canadian Forest supplied 42% of the total netback pool sales quantity. For 2003 it is estimated that Canadian Forest will supply approximately 44% of the netback pool quantity. We expect that Canadian Forest's pro rata obligations as a gas producer will increase in 2005 and future years. In order to satisfy their supply obligations, the ProMark Netback Pool and Canadian Forest may be required to cover their obligations in the market.

As the operator of the netback pool, ProMark is required to acquire gas in the event of a shortfall between the gas supply and market obligations. A shortfall could occur if a gas producer fails to deliver its contractual share of the supply obligations of the netback pool. The cost of purchasing gas to cover any shortfall is a cost of the netback pool. The prices paid for shortfall gas would typically be spot market prices and may differ from the market prices received from netback pool customers. Higher spot prices would reduce the average netback pool price paid to the gas producers, including Canadian Forest. Shortfalls in gas produced may occur in the future. The Company cannot predict with any certainty the amount of any such shortfalls.

In addition to its commitments to the ProMark Netback Pool, Canadian Forest is committed to sell natural gas at the following quantities and weighted average prices:

	Natural Gas
	BCF	Sales Price Per MCF
Fourth Quarter of 2003	0.16	$	3.82 CDN
2004	0.6	$	3.96 CDN
2005	0.6	$	4.11 CDN
2006	0.5	$	4.27 CDN

Hedging Program. 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. When 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 September 30, 2003, 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 2003	60.2	$	4.52	7,000	$	23.16
First Quarter 2004	—	$	—	7,000	$	23.95
Second Quarter 2004	30.0	$	4.27	9,000	$	24.75
Third Quarter 2004	30.0	$	4.27	7,000	$	24.34
Fourth Quarter 2004	10.1	$	4.27	3,000	$	23.33

Between October 1, 2003 and November 4, 2003, we entered into the following swaps accounted for as cash flow hedges, including hedges associated with the Unocal properties:

	Natural Gas			Oil (NYMEX WTI)
	BBTUs Per Day	Average Hedged Price Per MMBTU		Barrels Per Day	Average Hedged Price Per BBL
Fourth Quarter 2003	49.7	$	4.92	2239	$	29.08
First Quarter 2004	70.00	$	4.82	3500	$	27.79
Second Quarter 2004	70.00	$	4.82	2500	$	26.71
Third Quarter 2004	70.00	$	4.82	2500	$	26.71
Fourth Quarter 2004	70.00	$	4.82	2500	$	26.71
First Quarter 2005	70.00	$	4.63	2500	$	25.45
Second Quarter 2005	70.00	$	4.63	2500	$	25.45
Third Quarter 2005	70.00	$	4.63	2500	$	25.45
Fourth Quarter 2005	70.00	$	4.63	2500	$	25.45

We also enter into collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only when the index price is below the floor price, and we pay the difference between the ceiling price and the index price only when the index price is above the ceiling price. In addition, Forest has entered into three-way collars with third parties. These instruments establish two floors and one ceiling. Upon settlement, if the index price is below the lowest floor, the Company receives the difference between the two floors. If the index price is between the two floors, the Company receives the difference between the higher of the two floors and the index price. If the index price is between the higher floor and the ceiling, the Company does not receive or pay any additional amounts. If the index price is above the ceiling, the Company pays the excess over the ceiling price.

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

price increases in excess of the ceiling price on the hedged production. As of September 30, 2003, Forest had entered into the following natural gas and oil collars accounted for as cash flow hedges:

	Natural Gas
	BBTUs Per Day	Average Floor Price Per MMBTU		Average Ceiling Price Per MMBTU
Fourth Quarter 2003	39.9	$	3.74	$	5.28
First Quarter 2004	60.0	$	4.04	$	5.79

	Oil (NYMEX WTI)
	Barrels Per Day	Average Floor Price Per BBL		Average Ceiling Price Per BBL
Fourth Quarter 2003	3,000	$	22.00	$	25.42
First Quarter 2004	2,000	$	22.00	$	24.08

Between October 1, 2003 and November 4, 2003, we did not enter into any collars accounted for as cash flow hedges.

As of September 30, 2003, Forest had entered into the following 3-way natural gas collars accounted for as cash flow hedges:

	Natural Gas
	BBTUs Per Day	Average Lower Floor Price Per MMBTU		Average Upper Floor Price Per MMBTU		Average Ceiling Price Per MMBTU
First Quarter 2004	30.0	$	3.50	$	5.27	$	8.75
Second Quarter 2004	25.0	$	3.50	$	4.75	$	5.80
Third Quarter 2004	25.0	$	3.50	$	4.75	$	5.80
Fourth Quarter 2004	11.7	$	3.50	$	4.75	$	6.14

Between October 1, 2003 and November 4, 2003, we did not enter into any 3-way collars accounted for as cash flow hedges.

We also use basis swaps in connection with natural gas swaps, in order to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. At September 30, 2003, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 60.2 BBTUs per day for the remainder of 2003 and weighted average volumes of 11.7 BBTUs per day for 2004. Between October 1, 2003 and November 4, 2003, we did not enter into any basis swaps designated as cash flow hedges.

The fair value of our cash flow hedges based on the futures prices quoted on September 30, 2003 was a loss of approximately $15,005,000 ($9,303,000 after tax) which was recorded as a component of other comprehensive income.

At September 30, 2003, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 39.9 BBTUs per day for the remainder of 2003 and weighted average volumes of 43.8 BBTUs per day for 2004. Between October 1, 2003 and November 4, 2003 we did not enter into any additional basis swaps not designated as cash flow hedges.

The fair value of our derivative instruments not designated as cash flow hedges based on the futures prices quoted on September 30, 2003 was a loss of approximately $506,000.

Trading Activities. Profits or losses generated by the purchase and sale of third parties' gas are based on the spread between the prices of natural gas purchased and sold. ProMark does not trade natural gas to hold as a speculative or open position. All transactions represent physical volumes and are immediately offset, thereby fixing the margin and eliminating the market risk on the related agreements. At September 30, 2003, ProMark's trading operations had the following purchase and sales commitments in place for 2003 through 2005:

	Natural Gas
	BCF	Purchase Price Per MCF		Sales Price Per MCF
Fourth Quarter of 2003	0.4	$	5.97 CDN	$	6.04 CDN
2004	1.3	$	6.15 CDN	$	6.25 CDN
2005	0.2	$	5.56 CDN	$	5.76 CDN

Foreign Currency Exchange Risk

We conduct business in several foreign currencies and thus are subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. In the past, we have not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk. Expenditures incurred relative to the foreign concessions held by Forest outside of North America have been primarily U.S. dollar-denominated, as have cash proceeds related to property sales and farmout arrangements.

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, 2003:

		2005			2008		2011		2014		Total		Fair Value
		(Dollar Amounts in Thousands)
Bank credit facilities:
	Variable rate	$	145,000		—		—		—		145,000		145,000
	Average interest rate		2.47	%	—		—		—		2.47	%
Long-term debt:
	Fixed rate	$	—		265,000		160,000		150,000		575,000		602,213
	Coupon interest rate		—		8.00	%	8.00	%	7.75	%	7.93	%
	Effective interest rate(1)		—		7.13	%	7.48	%	6.88	%	7.16	%

(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.

In August 2003, in connection with $150,000,000 principal amount of 7³/4% Senior Notes due 2014, Forest entered into two interest rate swaps under which it would pay a variable rate based on the six month London Interbank Offered Rate (LIBOR) plus specified basis points in exchange for a fixed rate of 7³/4% over the term of the note issue. As of September 30, 2003, the fair value of these interest rate swaps, which are accounted for as fair value hedges, was a gain of approximately $6,269,000.

On October 1, 2003, Forest terminated the two interest rate swaps. We received approximately $5,057,000 (net of accrued settlements of approximately $938,000) in connection with the termination of the interest rate swaps. The aggregate gain was deferred and added to the carrying value of the related debt, and will be amortized as a reduction of interest expense over the remaining term of the note issue.

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, 2003. 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, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

10.1	*	Purchase and Sale Agreement by and between Forest Oil Corporation, Union Oil Company of California, Pure Resources, L.P., Pure Partners, L.P., and PRS Offshore L.P., dated September 20, 2003
10.2	*	Form of Executive Severance Agreement
10.3	*	Forest Oil Corporation Amended and Restated Salary Deferral Compensation Plan
10.4	*	Seventh Amendment to Combined Credit Agreements, dated as of October 15, 2003, among Forest Oil Corporation, Canadian Forest Oil Ltd., and the subsidiary borrowers from time to time parties thereto, each of the lenders that is a party thereto, Bank of America, N.A., as U.S. Syndication Agent, Citibank, N.A., as U.S. Documentation Agent, J.P. Morgan Bank Canada, successor to the Chase Manhattan Bank of Canada, as Canadian Administrative Agent, Bank of Montreal, as Canadian Syndication Agent, The Toronto-Dominion Bank, as Canadian Documentation Agent, and JPMorgan Chase Bank, successor to The Chase Manhattan Bank, as Global Administrative Agent
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

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

(b) Reports on Form 8-K.

The Company filed the following current reports on Form 8-K during the third quarter ending September 30, 2003.

Date of Report	Item Reported	Financial Statements Filed
August 1, 2003	Item 5	None
August 8, 2003	Items 7, 9 & 12*	None
September 23, 2003	Items 7 & 9*	None
September 29, 2003	Items 5 & 7	None

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

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 12, 2003	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)

Exhibit Index

Exhibit Number		Description
10.1		Purchase and Sale Agreement by and between Forest Oil Corporation, Union Oil Company of California, Pure Resources, L.P., Pure Partners, L.P., and PRS Offshore L.P., dated September 20, 2003
10.2		Form of Executive Severance Agreement
10.3		Forest Oil Corporation Amended and Restated Salary Deferral Compensation Plan
10.4		Seventh Amendment to Combined Credit Agreements, dated as of October 15, 2003, among Forest Oil Corporation, Canadian Forest Oil Ltd., and the subsidiary borrowers from time to time parties thereto, each of the lenders that is a party thereto, Bank of America, N.A., as U.S. Syndication Agent, Citibank, N.A., as U.S. Documentation Agent, J.P. Morgan Bank Canada, successor to the Chase Manhattan Bank of Canada, as Canadian Administrative Agent, Bank of Montreal, as Canadian Syndication Agent, The Toronto-Dominion Bank, as Canadian Documentation Agent, and JPMorgan Chase Bank, successor to The Chase Manhattan Bank, as Global Administrative Agent
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