FOREST OIL CORP - 10-Q Quarterly Report

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FOREST OIL CORPORATION INDEX TO FORM 10-Q June 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 June 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		25-0484900
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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

Title of Class of Common Stock		Number of Shares Outstanding July 31, 2003
Common Stock, Par Value $.10 Per Share		48,215,681

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

Part I—FINANCIAL INFORMATION			1
	Item 1—Financial Statements		1
		Condensed Consolidated Balance Sheets	1
		Condensed Consolidated Statements of Production and Operations	2
		Condensed Consolidated Statements of Cash Flows	3
		Notes to Condensed Consolidated Financial Statements	4
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations		21
	Item 3—Quantitative and Qualitative Disclosures about Market Risk		32
	Item 4—Controls and Procedures		37
Part II—OTHER INFORMATION			38
	Item 1—Legal Proceedings		38
	Item 4—Submission of Matters to a Vote of Security Holders		39
	Item 6—Exhibits and Reports on Form 8-K		40
Signatures			41

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

			June 30, 2003			December 31, 2002
			(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	10,221		13,166
	Accounts receivable			140,503		111,760
	Derivative instruments			2,524		3,241
	Current deferred tax asset			19,424		10,310
	Other current assets			21,873		21,994

		Total current assets		194,545		160,471
Net property and equipment				1,963,529		1,687,885
Deferred income taxes				1,303		41,022
Goodwill and other intangible assets, net				13,870		12,525
Other assets				20,673		22,778

			$	2,193,920		1,924,681

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	150,273		153,413
	Accrued interest			3,657		6,857
	Derivative instruments			41,124		29,120
	Asset retirement obligation			14,357		—
	Other current liabilities			3,464		2,285

		Total current liabilities		212,875		191,675
Long-term debt				745,563		767,219
Asset retirement obligation				145,962		—
Other liabilities				25,489		28,199
Deferred income taxes				25,271		16,377
Shareholders' equity:
	Common stock			5,029		4,913
	Capital surplus			1,183,657		1,159,269
	Accumulated deficit			(82,563	)	(144,548	)
	Accumulated other comprehensive loss			(11,493	)	(41,887	)
	Treasury stock, at cost			(55,870	)	(56,536	)

		Total shareholders' equity		1,038,760		921,211

			$	2,193,920		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 June 30,				Six Months Ended June 30,
			2003		2002		2003		2002
			(In Thousands Except Sales Volumes and Per Share Amounts)
SALES VOLUMES
Natural gas (MMCF)				22,769	23,535		45,839		45,742

Oil, condensate and natural gas liquids (thousands of barrels)				2,260	2,408		4,335		4,346

STATEMENTS OF CONSOLIDATED OPERATIONS
Revenue:
Oil and gas sales:
	Natural gas		$	99,870	73,797		213,828		133,229
	Oil, condensate and natural gas liquids			53,705	51,849		107,947		88,213

		Total oil and gas sales		153,575	125,646		321,775		221,442
	Marketing and processing, net			1,275	1,241		1,818		1,878

		Total revenue		154,850	126,887		323,593		223,320
Operating expenses:
	Oil and gas production			35,512	40,375		70,712		77,586
	General and administrative			10,173	10,062		19,065		18,219
	Depreciation and depletion			51,576	47,588		100,206		87,774
	Accretion of asset retirement obligation			3,147	—		6,267		—
	Impairment of oil and gas properties			135	—		135		—

		Total operating expenses		100,543	98,025		196,385		183,579

Earnings from operations				54,307	28,862		127,208		39,741
Other income and expense:
	Other expense, net			2,649	1,743		6,570		2,717
	Interest expense			12,491	12,568		25,451		24,713
	Translation gain on subordinated debt			—	(2,970	)	—		(2,821	)
	Realized loss (gain) on derivative instruments, net			5	(162	)	(38	)	(246	)
	Unrealized loss on derivative instruments, net			122	416		127		616

		Total other income and expense		15,267	11,595		32,110		24,979

Earnings before income taxes and cumulative effect of change in accounting principle				39,040	17,267		95,098		14,762
Income tax expense:
	Current			369	143		426		254
	Deferred			15,259	6,166		38,243		5,334

				15,628	6,309		38,669		5,588

Earnings before cumulative effect of change in accounting principle				23,412	10,958		56,429		9,174
Cumulative effect of change in accounting principle for recording asset retirement obligation, net of taxes				—	—		5,854		—

Net earnings			$	23,412	10,958		62,283		9,174

Weighted average number of common shares outstanding:
	Basic			48,188	46,925		48,024		46,880

	Diluted			49,068	48,485		48,901		48,293

Basic earnings per common share:
	Earnings before cumulative effect of change in accounting principle		$	0.49	.23		1.18		.20
	Cumulative effect of change in accounting principle			—	—		0.12		—

	Basic earnings per common share		$	0.49	.23		1.30		20

Diluted earnings per common share:
	Earnings before cumulative effect of change in accounting principle		$	0.48	.23		1.15		.19
	Cumulative effect of change in accounting principle			—	—		0.12		—

	Diluted earnings per common share		$	0.48	.23		1.27		.19

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Six Months Ended June 30,
				2003			2002
				(In Thousands)
Cash flows from operating activities:
	Net earnings before cumulative effect of change in accounting principle			$	56,429		9,174
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			100,206		87,774
		Accretion of asset retirement obligation			6,267		—
		Impairment of oil and gas properties			135		—
		Amortization of deferred hedge gain			(2,202	)	—
		Amortization of deferred debt costs			1,121		1,041
		Translation gain on subordinated debt			—		(2,821	)
		Unrealized loss on derivative instruments, net			127		616
		Deferred income tax expense			38,243		5,334
		Loss on extinguishment of debt			3,975		1,998
		Loss in equity method investee			1,580		—
		Other, net			(174	)	(1,772	)
		(Increase) decrease in accounts receivable			(22,720	)	28,956
		Decrease in other current assets			624		9,013
		Decrease in accounts payable			(9,867	)	(47,674	)
		Decrease in accrued interest and other liabilities			(10,897	)	(1,478	)

			Net cash provided by operating activities		162,847		90,161
Cash flows from investing activities:
	Capital expenditures for property and equipment:
		Exploration, development and acquisition costs			(166,102	)	(179,194	)
		Other fixed assets			(1,202	)	(2,114	)
	Proceeds from sales of assets				65		1,632
	Increase in other assets, net				(1,112	)	(2,296	)

			Net cash used by investing activities		(168,351	)	(181,972	)
Cash flows from financing activities:
	Proceeds from bank borrowings				321,000		177,889
	Repayments of bank borrowings				(275,000	)	(196,878	)
	Issuance of 7³/4% senior notes, net of issuance costs				—		146,846
	Repurchases of 8³/4% senior subordinated notes				—		(5,435	)
	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				4,152		3,573
	Purchase of treasury stock				—		(560	)
	Increase (decrease) in other liabilities, net				126		(497	)

			Net cash provided by financing activities		1,805		103,655
Effect of exchange rate changes on cash					754		(4	)

Net (decrease) increase in cash and cash equivalents					(2,945	)	11,840
Cash and cash equivalents at beginning of period					13,166		8,387

Cash and cash equivalents at end of period				$	10,221		20,227

Cash paid during the period for:
	Interest			$	29,877		24,002
	Income taxes			$	1,562		1,362

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND SIX MONTHS ENDED JUNE 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 June 30, 2003 and the results of operations for the three and six months ended June 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. In addition, marketing and processing revenue and related expenses have been netted in the accompanying condensed financial statements to reflect the change made in the third quarter of 2002 in response to EITF Issue No. 02-03.

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.

The Financial Accounting Standards Board (FASB) and representatives of the accounting staff of the Securities and Exchange Commission (SEC) are currently engaged in discussions regarding the application of certain provisions of 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) to companies in the extractive industries, including oil and gas companies. The FASB and the SEC staff are considering whether the provisions of SFAS No. 141 and SFAS No. 142 require registrants to classify costs associated with mineral rights, including both proved

and unproved lease acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures.

Historically, Forest has included oil and gas lease acquisition costs as a component of oil and gas properties. In the event the FASB and SEC staff determine that costs associated with mineral rights are required to be classified as intangible assets, a portion of our oil and gas property acquisition costs since the June 30, 2001 effective date of SFAS Nos. 141 and 142 would be separately classified on our balance sheets as intangible assets. Forest's results of operations would not be affected, however, since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. We do not believe the classification of oil and gas lease acquisition costs 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. Management believes the adoption of SFAS No. 149 will 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 June 30,			Six Months Ended June 30,
		2003(1)		2002(2)	2003(3)	2002(4)
		(In Thousands Except Per Share Amounts)
Earnings before cumulative effect of change in accounting principle		$	23,412	10,958	56,429	9,174
Cumulative effect of change in accounting principle			—	—	5,854	—

Net earnings		$	23,412	10,958	62,283	9,174

Weighted average common shares outstanding during the period			48,188	46,925	48,024	46,880
	Add dilutive effects of stock options		208	657	210	568
	Add dilutive effects of warrants		672	903	667	845

Weighted average common shares outstanding including the effects of dilutive securities			49,068	48,485	48,901	48,293

Basic earnings per share before cumulative effect of change in accounting principle		$	.49	.23	1.18	.20

Basic earnings per share		$	.49	.23	1.30	.20

Diluted earnings per share before cumulative effect of change in accounting principle		$	.48	.23	1.15	.19

Diluted earnings per share		$	.48	.23	1.27	.19

(1): For the three months ended June 30, 2003, options to purchase 2,428,075 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2013.
(2): For the three months ended June 30, 2002, options to purchase 426,250 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 2011.
(3): For the six months ended June 30, 2003, options to purchase 2,949,275 shares of common stock were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2013.
(4): For the six months ended June 30, 2002, options to purchase 1,630,800 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 through 2011.

Comprehensive Earnings (Loss):

Comprehensive earnings (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains and losses that under generally accepted accounting principles are reported as separate components of shareholders' equity instead of net earnings (loss). Items included in the Company's other comprehensive income (loss) for the three and six months ended June 30, 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 June 30,					Six Months Ended June 30,
		2003			2002		2003		2002
		(In Thousands)
Net earnings		$	23,412		10,958		62,283		9,174
Loss on sale of treasury stock			(298	)	—		(298	)	—
Other comprehensive income (loss):
	Foreign currency translation gains		21,507		9,402		37,932		9,091
	Unrealized gain (loss) on derivative instruments, net		(1,492	)	31		(8,319	)	(26,208	)
	Unrealized gain (loss) on securities available for sale and other		346		(42	)	781		(27	)

Total comprehensive earnings (loss)		$	43,475		20,349		92,379		(7,970	)

(3) STOCK-BASED COMPENSATION

The Company applies APB Opinion 25 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 June 30,			Six Months Ended June 30,
		2003		2002	2003	2002
		(In Thousands Except Per Share Amounts)
Net earnings:
	As reported	$	23,412	10,958	62,283	9,174

	Pro forma	$	19,643	7,035	55,506	2,385

Basic earnings per share:
	As reported	$	0.49	0.23	1.30	0.20

	Pro forma	$	0.41	0.15	1.16	0.05

Diluted earnings per share:
	As reported	$	0.48	0.23	1.27	0.19

	Pro forma	$	0.40	0.15	1.14	0.05

(4) NET PROPERTY AND EQUIPMENT

Components of net property and equipment are as follows:

	June 30, 2003			December 31, 2002
	(In Thousands)
Oil and gas properties	$	4,119,568		3,763,080
Buildings, transportation and other equipment		28,992		27,230

		4,148,560		3,790,310
Less accumulated depreciation, depletion and valuation allowance		(2,185,031	)	(2,102,425	)

	$	1,963,529		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 properties 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 six months ended June 30, 2003:

	Six Months Ended June 30, 2003
	(In Thousands)
Asset retirement obligation at beginning of period	$	—
Liability recognized in transition		155,972
Accretion expense		6,267
Liabilities incurred		2,893
Liabilities settled		(5,798	)
Impact of foreign currency exchange		985

Asset retirement obligation at end of period		160,319
Less: current asset retirement obligation		14,357

Long-term asset retirement obligation	$	145,962

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

		Three Months Ended June 30, 2002		Six Months Ended June 30, 2002
		(In Thousands)
Net earnings:
	As reported	$	10,958	9,174

	Pro forma	$	10,688	8,416

Basic earnings per share:
	As reported	$	.23	.20

	Pro forma	$	.23	.18

Diluted earnings per share:
	As reported	$	.23	.19

	Pro forma	$	.22	.17

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:

	June 30, 2003			December 31, 2002
	(In Thousands)
Goodwill(1)	$	17,029		14,589
Long-term gas marketing contracts(1)		14,857		12,728

		31,886		27,317
Less accumulated amortization		(18,016	)	(14,792	)

	$	13,870		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 June 30, 2003 is due to the increase in the value of the Canadian dollar relative to the U.S. dollar during the six months ended June 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 $.7428 at June 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:

	June 30, 2003							December 31, 2002
	Principal		Unamortized Discount		Other		Total	Principal	Unamortized Discount		Other		Total
	(In Thousands)
U.S. Credit Facility	$	141,000	—		—		141,000	95,000	—		—		95,000
8% Senior Notes Due 2008		265,000	(488	)	11,418	(1)	275,930	265,000	(536	)	12,558	(1)	277,022
8% Senior Notes Due 2011		160,000	—		7,093	(1)	167,093	160,000	—		7,509	(1)	167,509
7³/4% Senior Notes Due 2014		150,000	(2,586	)	14,126	(1)	161,540	150,000	(2,706	)	14,772	(1)	162,066
10¹/2% Senior Subordinated Notes Due 2006		—	—		—		—	65,970	(348	)	—		65,622

	$	716,000	(3,074	)	32,637		745,563	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 gain will be amortized as a reduction of interest expense over the terms of the note issues.

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 quarter 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 non-operating 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% Notes due 2011 and the 8% Notes due 2008 for a variable rate based on 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% 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.

During the second quarters of 2003 and 2002, the Company recognized reductions of interest expense of $1,107,000 and $2,703,000, respectively, under the terminated interest rate swaps.

During the first six months of 2003 and 2002, the Company recognized reductions of interest expense of $2,202,000 and $4,260,000, respectively, under the terminated interest rate swaps.

In August, 2003, in connection with $150,000,000 principal amount of 7³/4% Senior Notes due 2014, the Company entered into an interest rate swap under which it will pay a variable rate based on the six month London Interbank Offered Rate (LIBOR) plus 248 basis points in exchange for a fixed rate of 7³/4% over the term of the note issue. The interest rate swap is a fair value hedge and, accordingly, unrecognized gains (losses) related to this instrument will be 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 swap will be recorded as a derivative asset (liability) and the corresponding fair value of the related debt instrument will be recorded as an increase (decrease) in the related debt balance.

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 June 30, 2003 have been designated as cash flow hedges. At June 30, 2003, the Company had a derivative asset of $3,037,000 (of which $2,524,000 was classified as current), a derivative liability of $44,989,000 (of which $41,124,000 was classified as current), a deferred tax asset of $15,942,000 (of which $14,668,000 was classified as current) and accumulated other comprehensive loss of approximately $25,676,000.

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

		Three Months Ended June 30,					Six Months Ended June 30,
		2003			2002		2003		2002
					(In Thousands)
Derivatives designated as cash flow hedges		$	(18,089	)	(3,802	)	(53,446	)	8,610
Derivatives not designated as cash flow hedges			(127	)	(254	)	(89	)	(370	)

	Total gain (loss)	$	(18,216	)	(4,056	)	(53,535	)	8,240

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 June 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
Third Quarter 2003	100.0	$	4.47	7,500	$	23.40
Fourth Quarter 2003	60.2	$	4.52	7,000	$	23.16
First Quarter 2004	—	$	—	6,000	$	23.23
Second Quarter 2004	20.0	$	3.90	8,000	$	24.31
Third Quarter 2004	20.0	$	3.90	7,000	$	24.34
Fourth Quarter 2004	6.7	$	3.90	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 June 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
Third Quarter 2003	20.0	$	3.25	$	4.08
Fourth Quarter 2003	33.3	$	3.49	$	4.93
First Quarter 2004	40.0	$	3.55	$	5.15

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

As of June 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	5.0	$	3.50	$	4.75	$	7.00
Third Quarter 2004	5.0	$	3.50	$	4.75	$	7.00
Fourth Quarter 2004	5.0	$	3.50	$	4.75	$	7.00

The Company also uses basis swaps in connection with natural gas swaps, in order to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. At June 30, 2003 there were basis swaps designated as cash flow hedges in place with weighted average volumes of 80.0 BBTUs per day for the remainder of 2003 and weighted average volumes of 5.8 BBTUs per day for 2004. At June 30, 2003 there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 16.7 BBTUs per day for the remainder of 2003 and weighted average volumes of 13.8 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 in the United States and Canada.

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

	Three Months Ended June 30,			Six Months Ended June 30,
	2003		2002	2003	2002
	(In Thousands)
Marketing and processing revenue	$	90,212	71,962	190,514	125,349
Marketing and processing expense		88,937	70,721	188,696	123,471

Marketing and processing, net	$	1,275	1,241	1,818	1,878

(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 June 30, 2003

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International		Total Company
						(In Thousands)
Revenue		$	94,877	22,936	21,488	139,301	14,274	153,575	1,275	—		154,850
Expenses:
	Oil and gas production		17,178	5,559	9,680	32,417	3,095	35,512	—	—		35,512
	General and administrative		6,447	733	1,251	8,431	1,351	9,782	391	—		10,173
	Depletion and amortization		31,778	4,092	7,594	43,464	6,546	50,010	366	—		50,376
	Accretion		2,250	220	536	3,006	141	3,147	—	—		3,147
	Impairment		—	—	—	—	—	—	—	135		135

Earnings from operations		$	37,224	12,332	2,427	51,983	3,141	55,124	518	(135	)	55,507

Capital expenditures		$	56,466	11,459	12,198	80,123	11,490	91,613	—	1,738		93,351

Property and equipment, net		$	926,619	258,255	418,998	1,603,872	281,383	1,885,255	—	69,741		1,954,996

Information for reportable segments relates to the Company's June 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	$	55,507
Administrative asset depreciation		(1,200	)
Other expense, net		(2,649	)
Interest expense		(12,491	)
Realized loss on derivative instruments, net		(5	)
Unrealized loss on derivative instruments, net		(122	)

Earnings before income taxes and cumulative effect of accounting change	$	39,040

Six Months Ended June 30, 2003

		Oil and Gas Operations
		Gulf		Western	Alaska		Total United States	Canada	Total	Marketing and Processing	International		Total Company
		(In Thousands)
Revenue		$	202,072	51,163	36,437		289,672	32,103	321,775	1,818	—		323,593
Expenses:
	Oil and gas production		32,241	11,621	20,655		64,517	6,195	70,712	—	—		70,712
	General and administrative		11,508	1,446	2,710		15,664	2,644	18,308	757	—		19,065
	Depletion and amortization		62,898	8,423	13,569		84,890	12,301	97,191	704	—		97,895
	Accretion		4,499	440	1,072		6,011	256	6,267	—	—		6,267
	Impairment		—	—	—		—	—	—	—	135		135

Earnings from operations		$	90,926	29,233	(1,569	)	118,590	10,707	129,297	357	(135	)	129,519

Capital expenditures		$	85,666	18,368	40,499		144,533	19,433	163,966	—	2,136		166,102

Property and equipment, net		$	926,619	258,255	418,998		1,603,872	281,383	1,885,255	—	69,741		1,954,996

Information for reportable segments relates to the Company's June 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	$	129,519
Administrative asset depreciation		(2,311	)
Other expense, net		(6,570	)
Interest expense		(25,451	)
Realized gain on derivative instruments, net		38
Unrealized loss on derivative instruments, net		(127	)

Loss before income taxes and cumulative effect of change in accounting principle	$	95,098

Three Months Ended June 30, 2002

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International	Total Company
		(In Thousands)
Revenue		$	73,903	17,089	21,556	112,548	13,098	125,646	1,241	—	126,887
Expenses:
	Oil and gas production		21,151	5,010	10,306	36,467	3,908	40,375	—	—	40,375
	General and administrative		4,808	1,559	2,086	8,453	1,229	9,682	380	—	10,062
	Depletion		31,525	4,572	5,649	41,746	4,781	46,527	145	—	46,672

Earnings from operations		$	16,419	5,948	3,515	25,882	3,180	29,062	716	—	29,778

Capital expenditures		$	33,053	12,418	45,072	90,543	4,155	94,698	—	4,662	99,360

Property and equipment, net		$	792,396	227,423	284,148	1,303,967	245,044	1,549,011	—	65,214	1,614,225

Information for reportable segments relates to the Company's June 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	$	29,778
Administrative asset depreciation		(916	)
Other expense, net		(1,743	)
Interest expense		(12,568	)
Translation gain on subordinated debt		2,970
Realized gain on derivative instruments, net		162
Unrealized loss on derivative instruments, net		(416	)

Earnings before income taxes and cumulative effect of accounting change	$	17,267

Six Months Ended June 30, 2002

		Oil and Gas Operations
		Gulf		Western	Alaska	Total United States	Canada	Total	Marketing and Processing	International	Total Company
		(In Thousands)
Revenue		$	133,873	28,024	34,651	196,548	24,894	221,442	1,878	—	223,320
Expenses:
	Oil and gas production		41,698	9,949	19,171	70,818	6,768	77,586	—	—	77,586
	General and administrative		8,798	2,970	3,397	15,165	2,321	17,486	733	—	18,219
	Depletion		59,091	8,158	8,578	75,827	9,930	85,757	288	—	86,045

Earnings from operations		$	24,286	6,947	3,505	34,738	5,875	40,613	857	—	41,470

Capital expenditures		$	59,849	23,711	69,399	152,959	13,156	166,115	—	13,079	179,194

Property and equipment, net		$	792,396	227,423	284,148	1,303,967	245,044	1,549,011	—	65,214	1,614,225

Information for reportable segments relates to the Company's June 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	$	41,470
Administrative asset depreciation		(1,729	)
Other expense, net		(2,717	)
Interest expense		(24,713	)
Translation gain on subordinated debt		2,821
Realized gain on derivative instruments, net		246
Unrealized loss on derivative instruments, net		(616	)

Loss before income taxes and cumulative effect of change in accounting principle	$	14,762

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 Second Quarter of 2003

Net earnings for the second quarter of 2003 were $23,412,000 compared to $10,958,000 in the corresponding period of 2002. Higher earnings for the quarter ended June 30, 2003 compared to the corresponding period of 2002 were 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 in the United

States. Marketing and processing, net remained relatively flat at $1,275,000 in the second quarter of 2003 compared to $1,241,000 in the second quarter of 2002.

Oil and gas sales revenue increased by 22% to $153,575,000 in the second quarter of 2003 from $125,646,000 in the second quarter of 2002 as a result of higher product prices. The average gas sales price increased 40% for the second quarter of 2003 compared to the same period of 2002. The average liquids sales price increased 10% compared to the average price in the 2002 period.

For the second quarter of 2003, Forest reported sales volumes of 36,329 MMCFE, a 4% decrease compared to the reported sales volumes of 37,983 MMCFE for the same period of 2002. In the United States, Forest's oil and gas sales volumes decreased 6% and 1%, respectively, or a total decrease in equivalent gas production of approximately 3% in the second quarter of 2003 compared to the corresponding prior year period. The decrease was attributable primarily to production declines and downtime in the Western and Gulf Coast business units. In Canada, Forest's sales volumes decreased 12% due primarily to higher royalty volumes in the current higher price environment and to 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 second quarter of 2003 decreased 12% to $35,512,000 compared to $40,375,000 in the corresponding period in 2002. On a per-unit basis, production expense decreased 8% to $.98 per MCFE in the second quarter of 2003 compared to $1.06 per MCFE in the second quarter of 2002. The decrease was due primarily to lower lease operating and workover expense in the Gulf of Mexico and in Alaska, and lower transportation expense in all business units. The decrease was offset partially by higher production taxes in the Western business unit as a result of higher product prices and by additional lease operating costs in Alaska in conjunction with the new production at the Redoubt Shoal Field.

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

				Three Months Ended June 30,
				2003			2002
Natural Gas
	Sales volumes (MMCF):
		United States			19,821		20,067
		Canada			2,948		3,468

			Total		22,769		23,535
	Sales price received (per MCF)			$	4.96		3.15
	Effects of energy swaps and collars (per MCF)(1)				(0.57	)	(.01	)

	Average sales price (per MCF)			$	4.39		3.14
Liquids
Oil and condensate:
	Sales volumes (MBBLS)				2,034		2,152
	Sales price received (per BBL)			$	26.81		24.27
	Effects of energy swaps and collars (per BBL)(1)				(2.52	)	(1.64	)

	Average sales price (per BBL)			$	24.29		22.63
Natural gas liquids:
	Sales volumes (MBBLS)				226		256
	Average sales price (per BBL)			$	19.07		12.27
Total liquids sales volumes (MBBLS):
		United States			2,000		2,134
		Canada			260		274

			Total		2,260		2,408
	Average sales price (per BBL)			$	23.76		21.53
Total sales volumes
	Sales volumes (MMCFE):
		United States			31,821		32,871
		Canada			4,508		5,112

			Total		36,329		37,983
Average sales price (per MCFE)				$	4.23		3.31
Oil and gas production expense (per MCFE):				$	0.98		1.06

(1): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 12,740 MMCF and 9,710 MMCF in the second quarter of 2003 and 2002, respectively. Hedged oil and condensate volumes were 1,228,500 barrels and 1,047,000 barrels in the second 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 $(18,089,000) and $(3,802,000) for the three months ended June 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.

Total overhead costs (capitalized and expensed general and administrative costs) decreased 7% to $16,005,000 in the second quarter of 2003 compared to $17,190,000 in the second quarter of 2002. The decrease resulted primarily from cost reduction measures in the area of professional service costs and

from higher credits for exploration and development activities, offset partially by severance costs and costs incurred to terminate a Canadian defined benefit pension plan. The expensed portion of overhead costs increased to approximately 64% of total overhead in the second quarter of 2003 from approximately 58% in the second quarter of 2002, primarily as a function of the higher exploration and development credits in 2003. Accordingly, general and administrative expense increased to $10,173,000 in the second quarter of 2003 compared to $10,062,000 in the second quarter of 2002.

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

		Three Months Ended June 30,
		2003		2002
		(In Thousands)
Overhead costs capitalized		$	5,832	7,128
General and administrative costs expensed(1)			10,173	10,062

	Total overhead costs	$	16,005	17,190

(1): Includes $391,000 and $380,000 related to marketing operations for the three months ended June 30, 2003 and 2002, respectively.

Depreciation and depletion expense was $51,576,000 in the second quarter of 2003 compared to $47,588,000 in the second quarter of 2002. On a per-unit basis, the depletion rate was $1.39 per MCFE for the quarter ended June 30, 2003, compared to $1.23 per MCFE in the corresponding prior year period. The higher rate in the second quarter of 2003 was due primarily to higher finding costs in the last six months of 2002 and the first quarter of 2003.

Accretion expense of $3,147,000 in the second 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 properties 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 $2,649,000 in the second quarter of 2003 consisted primarily of Forest's share of the net loss recorded by the Cook Inlet Pipeline Company, an equity method investee in which Forest owns a 40% interest. Other expense of $1,743,000 in the second quarter of 2002 consisted primarily of losses on extinguishment of debt of approximately $1,767,000 related to Forest's repurchase of $19,710,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 108% of par value and the repurchase of $150,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value.

Interest expense in the second quarter of 2003 decreased to $12,491,000 compared to $12,568,000 in the second quarter of 2002 as a result of higher average debt balances which were more than offset by lower average interest rates on variable and fixed rate debt.

There was a foreign currency translation gain of $2,970,000 in the second quarter of 2002 which was the result of translation of the 8³/4% Notes issued by Canadian Forest Oil, Ltd., our Canadian subsidiary (Canadian Forest) and was attributable to a decrease in the value of the Canadian dollar relative to the U.S. dollar during the period. Forest was required to recognize the noncash foreign currency translation loss related to the 8³/4% Notes because the debt was denominated in U.S. dollars

and the functional currency of Canadian Forest is the Canadian dollar. All of the outstanding notes were redeemed on September 15, 2002.

There was a realized loss on derivative instruments of $5,000 in the second quarter of 2003 compared to a realized gain on derivative instruments of $162,000 in the second quarter of 2002. The realized losses were due primarily to settlement of basis differential swaps at prices that were, in the aggregate, higher than the pricing established in the related derivative contracts. There was a net unrealized loss on derivative instruments in the second quarter of 2003 of $122,000 compared to a net unrealized loss on derivative instruments of $416,000 in the corresponding period in 2002. The losses were attributable primarily to decreases in the estimated future value of existing commodity swaps as a result of increases in commodity futures prices. Realized and unrealized gains and losses on derivative instruments are recorded separately in non-operating income since the instruments do not qualify as hedges under the accounting rules governing hedging activities that were adopted in 2001.

Forest recorded current income tax expense of $369,000 in 2003 compared to $143,000 in 2002. The increase in 2003 resulted from increases in alternative minimum taxes.

Deferred income tax expense was $15,259,000 in the second quarter of 2003 compared to $6,166,000 in the second 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 Forest's net operating loss carryforward.

Results of Operations for the Six Months Ended June 30, 2003

Net earnings for the first six months of 2003 were $62,283,000 compared to $9,174,000 in the corresponding period of 2002. Higher earnings for the six months ended June 30, 2003 compared to the corresponding period of 2002 were 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 in the United States. Marketing and processing, net remained relatively flat at $1,818,000 in the first six months of 2003 compared to $1,878,000 in the first six months of 2002.

Oil and gas sales revenue increased by 45% to $321,775,000 in the first six months of 2003 from $221,442,000 in the first six months of 2002, as a result of higher product prices. The average gas sales price increased 60% for the first six months of 2003 compared to the same period of 2002. The average liquids sales price increased 23% compared to the average price in the 2002 period.

For the first six months of 2003, Forest reported sales volumes of 71,849 MMCFE, compared to reported sales volumes of 71,818 MMCFE for the same period of 2002. In the United States, Forest's oil and gas sales volumes increased 1% and 4%, respectively, or a total increase in equivalent gas production of approximately 3% in the first six months of 2003 compared to the corresponding prior year period. The increase was attributable primarily to new gas production in the Gulf of Mexico and new oil production in Alaska. In Canada, Forest's sales volumes decreased 18% in the first six months of 2003 due primarily to higher royalty volumes in the current higher price environment and to 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 first six months of 2003 decreased 9% to $70,712,000 compared to $77,586,000 in the corresponding period in 2002. On a per-unit basis, production expense decreased 9% to $.98 per MCFE in the first six months of 2003 compared to $1.08 per MCFE in the first six months of 2002. The decrease was due primarily to lower lease operating and workover expense in the Gulf of Mexico and Alaska and lower transportation expense in all business

units. The decrease was offset partially by higher production taxes in the Western business unit as a result of higher product prices and by additional lease operating costs in Alaska in conjunction with the new production at the Redoubt Shoal Field.

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

				Six Months Ended June 30,
				2003			2002
Natural Gas
	Sales volumes (MMCF):
		United States			39,986		38,400
		Canada			5,853		7,342

			Total		45,839		45,742
	Sales price received (per MCF)			$	5.48		2.68
	Effects of energy swaps and collars (per MCF)(1)				(0.82	)	.23

	Average sales price (per MCF)			$	4.66		2.91
Liquids
Oil and condensate:
	Sales volumes (MBBLS)				3,869		3,781
	Sales price received (per BBL)			$	29.50		22.28
	Effects of energy swaps and collars (per BBL)(1)				(4.08	)	(.56	)

	Average sales price (per BBL)			$	25.42		21.72
Natural gas liquids:
	Sales volumes (MBBLS)				466		565
	Average sales price (per BBL)			$	20.57		10.77
Total liquids sales volumes (MBBLS):
		United States			3,807		3,749
		Canada			528		597

			Total		4,335		4,346
	Average sales price (per BBL)			$	24.90		20.30
Total sales volumes
	Sales volumes (MMCFE):
		United States			62,828		60,894
		Canada			9,021		10,924

			Total		71,849		71,818
Average sales price (per MCFE)				$	4.48		3.08
Oil and gas production expense (per MCFE):				$	0.98		1.08

(1): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Hedged natural gas volumes were 24,860 MMCF and 17,360 MMCF in the first six months of 2003 and 2002, respectively. Hedged oil and condensate volumes were 2,443,500 barrels and 2,082,000 barrels in the first six months 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) gains related to our cash flow hedges were $(53,446,000) and $8,610,000 for the six months ended June 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.

Total overhead costs (capitalized and expensed general and administrative costs) decreased 5% to $29,994,000 in the first six months of 2003, compared to $31,632,000 in the first six months of 2002. The decrease resulted primarily from cost reduction measures in the area of professional service costs and from higher credits for exploration and development activities, offset partially by severance costs and costs incurred to terminate a Canadian defined benefit pension plan. The expensed portion of overhead costs increased to approximately 64% of total overhead in the first six months of 2003 from approximately 58% in the first six months of 2002, primarily as a function of the higher exploration and development credits in 2003. Accordingly, general and administrative expense increased to $19,065,000 for the six months ended June 30, 2003, compared to $18,219,000 for the same period in 2002.

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

		Six Months Ended June 30,
		2003		2002
		(In Thousands)
Overhead costs capitalized		$	10,929	13,413
General and administrative costs expensed(1)			19,065	18,219

	Total overhead costs	$	29,994	31,632

(1): Includes $757,000 and $733,000 related to marketing operations for the six months ended June 30, 2003 and 2002, respectively.

Depreciation and depletion expense was $100,206,000 in the first six months of 2003 compared to $87,774,000 in the first six months of 2002. On a per-unit basis, the depletion rate was $1.36 per MCFE for the first six months of June 30, 2003, compared to $1.20 per MCFE in the corresponding prior year period. The higher rate in the first six months of 2003 was due primarily to higher finding costs in the last six months of 2002 and first quarter of 2003.

Accretion expense of $6,267,000 in the first six months of 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 properties 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 $6,570,000 in the first six months of 2003 consisted primarily of 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, and Forest's share of the net loss recorded by the Cook Inlet Pipeline Company, an equity method investee in which Forest owns a 40% interest. Other expense of $2,717,000 in the first six months of 2002 was due primarily to franchise taxes and 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 and the repurchase of $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value.

Interest expense in the first six months of 2003 increased to $25,451,000 compared to $24,713,000 in the first six months of 2002, due to higher average debt balances which were partially offset by lower average interest rates.

There was a foreign currency translation gain of $2,821,000 in the first six months of 2002 which was the result of translation of the 8³/4% Notes issued by Canadian Forest and was attributable to a

decrease in the value of the Canadian dollar relative to the U.S. dollar during the period. Forest was required to recognize the noncash foreign currency translation loss related to the 8³/4% Notes because the debt was denominated in U.S. dollars and the functional currency of Canadian Forest is the Canadian dollar. All of the outstanding notes were redeemed on September 15, 2002.

There was a realized gain on derivative instruments of $38,000 in the first six months of 2003 compared to a realized gain on derivative instruments of $246,000 in the first six months of 2002. The realized gains were due primarily to settlement of basis differential swaps at prices that were, in the aggregate, lower than the pricing established in the related derivative contracts. There was a net unrealized loss on derivative instruments in the first six months of 2003 of $127,000 compared to a net unrealized loss on derivative instruments of $616,000 in the corresponding period in 2002. The losses were attributable primarily to decreases in the estimated future value of existing commodity swaps as a result of increases in commodity futures prices. Realized and unrealized gains and losses on derivative instruments are recorded separately in non-operating income since the instruments do not qualify as hedges under the accounting rules governing hedging activities that were adopted in 2001.

Forest recorded current income tax expense of $426,000 in 2003 compared to $254,000 in the corresponding period of 2002. The increase in 2003 resulted from increases in alternative minimum taxes.

Deferred income tax expense was $38,243,000 in the first six months of 2003 compared to $5,334,000 in the first six months 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 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 long-term bank credit facilities.

Forest had working capital, exclusive of the effects of derivatives, of approximately $8,787,000 at June 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, a decrease in accounts payable and accrued interest payable, offset by the addition of current asset retirement obligations in the first six months of 2003.

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 $162,847,000 in the first six months of 2003 compared to $90,161,000 in the same period in 2002. The increase was due primarily to higher

average oil and gas prices. Cash used for investing activities in the first six months of 2003 was $168,351,000 compared to $181,972,000 in the same period in 2002. The decrease was due primarily to decreased exploration and development activities. Net cash provided by financing activities in the first six months of 2003 was $1,805,000 compared to cash provided of $103,655,000 in the same period in 2002. The 2003 period included cash used for the repurchases of the 10¹/2% Senior Subordinated Notes of $69,441,000 offset by net bank debt borrowings of $46,000,000 and net proceeds from the issuance of common stock and the exercise of options and warrants of approximately $25,120,000. The 2002 period included net repayments of bank debt of $18,989,000 and cash used for the repurchase of the 10¹/2% Senior Subordinated Notes of $21,283,000, more than offset by net proceeds of $146,846,000 from the issuance of the 7³/4% Senior Notes.

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

		Six Months Ended June 30,
		2003		2002
		(In Thousands)
Property acquisition costs:
	Proved properties	$	22,090	2,799
	Undeveloped properties		—	—

			22,090	2,799
Exploration costs:
	Direct costs		34,942	53,280
	Overhead capitalized		6,449	6,490

			41,391	59,770
Development costs:
	Direct costs		98,141	109,702
	Overhead capitalized		4,480	6,923

			102,621	116,625

Total capital expenditures for property acquisition, exploration and development(1)		$	166,102	179,194

(1): Does not include estimated discounted future abandonment costs of $5,798,000 related to assets placed in service during the first six months of 2003.

Forest's anticipated expenditures for exploration and development in 2003 are estimated to range from $350,000,000 to $400,000,000. We intend to meet our 2003 capital expenditure financing requirements using cash flows generated by operations, sales of non-strategic assets and, if necessary, borrowings under existing lines of credit. 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.

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 of 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.

Under the most restrictive of the financial covenants contained in our credit facilities, the unused borrowing amount under the credit facilities at June 30, 2003 was approximately $142,000,000 in addition to amounts outstanding. At August 8, 2003, under the most restrictive of these financial covenants, our unused borrowing amount under the credit facilities was approximately $130,000,000 in addition to amounts outstanding.

At June 30, 2003, there were outstanding borrowings of $141,000,000 under the U.S. credit facility at a weighted average interest rate of 2.8% and there were no outstanding borrowings under the Canadian credit facility. At August 8, 2003, the outstanding borrowings under the U.S. credit facility were $182,000,000 at a weighted average interest rate of 3.0% and there were no outstanding borrowings under the Canadian credit facility. At August 8, 2003, we had used the credit facilities for letters of credit in the amount of $6,553,633 U.S. and $1,353,230 CDN.

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 assets 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. For example, if our credit rating is downgraded from its current level, the amount of credit that is available under the credit facilities will be determined by a borrowing base. The available borrowing amount could be increased or be reduced under the borrowing base tests. If as a result of a downgrade of our credit rating a borrowing base is established at a level below our then outstanding borrowings under the credit facilities, we would be required to repay the excess of outstanding borrowings over the newly established borrowing base. If we were unable to pay such excess, it would cause an event of default.

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.

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 June 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 55% and 42% of our consolidated production, on an equivalent basis, during the first six months of 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 June 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
Remainder of 2003	2.8	$	2.67 CDN
2004	5.5	$	2.75 CDN
2005	5.5	$	2.85 CDN
2006	5.5	$	2.96 CDN
2007	5.5	$	3.07 CDN
2008	5.5	$	3.19 CDN
2009	3.6	$	3.79 CDN
2010	1.7	$	5.64 CDN
2011	.8	$	5.95 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
Remainder of 2003	.3	$	3.82 CDN
2004	.6	$	3.96 CDN
2005	.6	$	4.11 CDN
2006	.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 June 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
Third Quarter 2003	100.0	$	4.47	7,500	$	23.40
Fourth Quarter 2003	60.2	$	4.52	7,000	$	23.16
First Quarter 2004	—	$	—	6,000	$	23.23
Second Quarter 2004	20.0	$	3.90	8,000	$	24.31
Third Quarter 2004	20.0	$	3.90	7,000	$	24.34
Fourth Quarter 2004	6.7	$	3.90	3,000	$	23.33

Between July 1, 2003 and August 8, 2003, we 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
First Quarter 2004	—	$	—	1,000	$	28.30
Second Quarter 2004	—	$	—	1,000	$	28.30

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 June 30, 2003, Forest had entered into the following gas collars accounted for as cash flow hedges:

	Natural Gas
	BBTUs Per Day	Average Floor Price Per MMBTU		Average Ceiling Price Per MMBTU
Third Quarter 2003	20.0	$	3.25	$	4.08
Fourth Quarter 2003	33.3	$	3.49	$	4.93
First Quarter 2004	40.0	$	3.55	$	5.15

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

Between July 1, 2003 and August 8, 2003, we did not enter into any collars accounted for as cash flow hedges.

As of June 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	5.0	$	3.50	$	4.75	$	7.00
Third Quarter 2004	5.0	$	3.50	$	4.75	$	7.00
Fourth Quarter 2004	5.0	$	3.50	$	4.75	$	7.00

Between July 1, 2003 and August 8, 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 June 30, 2003, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 80.0 BBTUs per day for the remainder of 2003 and weighted average volumes of 5.8 BBTUs per day for 2004. Between July 1, 2003 and August 8, 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 June 30, 2003 was a loss of approximately $41,413,000 ($25,676,000 after tax) which was recorded as a component of other comprehensive income.

At June 30, 2003, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 16.7 BBTUs per day for the remainder of 2003 and weighted average volumes of 13.8 BBTUs per day for 2004. Between July 1, 2003 and August 8, 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 June 30, 2003 was a loss of approximately $539,000.

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 June 30, 2003, ProMark's trading operations had the following purchase and sales commitments in place for 2003 and 2004:

	Natural Gas
	BCF	Purchase Price Per MCF		Sales Price Per MCF
July-December, 2003	.6	$	5.50 CDN	$	5.55 CDN
2004	.3	$	6.44 CDN	$	6.53 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 June 30, 2003:

		2005			2008		2011		2014		Total		Fair Value
		(Dollar Amounts in Thousands)
Bank credit facilities:
	Variable rate	$	141,000		—		—		—		141,000		141,000
	Average interest rate		2.80	%	—		—		—		2.80	%
Long-term debt:
	Fixed rate	$	—		265,000		160,000		150,000		575,000		610,450
	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 rate 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 gain 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 an interest rate swap under which it will pay a variable rate based on the six month London Interbank Offered Rate (LIBOR) plus 248 basis points in exchange for a fixed rate of 7³/4% over the term of the note issue. The interest rate swap is a fair value hedge and, accordingly, unrecognized gains (losses) related to this instrument will be 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 swap will be recorded as a derivative asset (liability) and the corresponding fair value of the related debt instrument will be recorded as an increase (decrease) in the related debt balance.

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 June 30, 2003. Based on the evaluation, they believe that:

•: our disclosure controls and procedures are designed 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 material information 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 June 30, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

On May 8, 2003, Forest held its Annual Meeting of Shareholders ("Annual Meeting") in Denver, Colorado. A total of 43,095,131 shares of common stock were present at the Annual Meeting, either in person or by proxy, constituting a quorum. The matters voted upon at the Annual Meeting consisted of three proposals set forth in Forest's Proxy Statement dated April 2, 2003. The three proposals submitted to a vote of shareholders are set forth below, and were each adopted by the indicated margins.

Proposal No. 1: Election of two (2) Class III directors.

		Shares Voted for		Shares Withheld
Robert S. Boswell		41,412,372		1,682,758
William L. Britton		32,553,377		10,541,753

Election of one (1) Class I director.

		Shares Voted for		Shares Withheld
Cortlandt S. Dietler		41,412,737		1,682,393

In addition to the two Class III directors and the one Class I director noted above, the other directors of Forest whose terms did not expire at the 2003 Annual Meeting include: Dod A. Fraser, Forrest E. Hoglund, James H. Lee and Craig D. Slater.

Proposal No. 2: Amend the Company's 2001 Stock Incentive Plan to increase the number of shares reserved for issuance and modify certain award limits.

Shares Voted for		Shares Against		Abstentions
35,925,115		7,284,616		253,769

Proposal No. 3: Ratify the appointment of the Company's independent auditors.

Shares Voted for		Shares Against		Abstentions
42,413,044		647,083		35,003

There were no broker non-votes.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a): Exhibits.

10.1		Amendment No. 1 to Forest Oil Corporation's 2001 Stock Incentive Plan.
10.2		Form of Amendment to Severance Agreement
31.1		Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended
31.2		Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended
32.1		Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350
32.2		Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350

(b): Reports on Form 8-K.

The Company filed the following current reports on Form 8-K during the second quarter ending June 30, 2003:

Date of Report		Item Reported		Financial Statements Filed
May 9, 2003		Item 7 & 9*		None
May 15, 2003		Item 9*		None

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

SIGNATURES

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

	FOREST OIL CORPORATION (Registrant)
August 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		Amendment No. 1 to Forest Oil Corporation's 2001 Stock Incentive Plan
10.2		Form of Amendment to Severance Agreement
31.1		Certification of Principal Executive Officer of Forest Oil Corporation, as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended
31.2		Certification of Principal Financial Officer of Forest Oil Corporation, as required by Rule 13a-14(a) of the Securities Exchange Act of 1934, as amended
32.1		Certification of Chief Executive Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350
32.2		Certification of Chief Financial Officer of Forest Oil Corporation, pursuant to 18 U.S.C. §1350