FOREST OIL CORP - 10-Q Quarterly Report

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FOREST OIL CORPORATION INDEX TO FORM 10-Q SEPTEMBER 30, 2002

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

FORM 10-Q

(Mark One)
ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from N/A to N/A

Commission File Number 1-13515

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

New York
(State or other jurisdiction of
incorporation or organization)

25-0484900
(I.R.S. Employer
Identification No.)

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

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

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

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

Title of Class of Common Stock		Number of Shares Outstanding October 31, 2002
Common Stock, Par Value $.10 Per Share		46,979,465

FOREST OIL CORPORATION
INDEX TO FORM 10-Q
SEPTEMBER 30, 2002

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		17
	Item 3—Quantitative and Qualitative Disclosures about Market Risk		27
	Item 4—Controls and Procedures		31
Part II—OTHER INFORMATION			32
	Item 5—Other Information		32
	Item 6—Exhibits and Reports on Form 8-K		32
Signatures			33
CEO Certification			34
CFO Certification			35

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

			September 30, 2002			December 31, 2001
			(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	7,781		8,387
	Accounts receivable			119,840		134,090
	Derivative instruments			10,372		31,632
	Current deferred tax asset			8,163		—
	Other current assets			22,129		27,856

		Total current assets		168,285		201,965
Net property and equipment, at cost				1,637,740		1,516,900
Deferred income taxes				39,317		43,930
Goodwill and other intangible assets, net				12,785		13,263
Other assets				32,237		20,311

			$	1,890,364		1,796,369

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	138,283		209,163
	Accrued interest			13,899		7,364
	Derivative instruments			23,723		1,548
	Current portion of deferred income tax liability			—		11,154
	Other current liabilities			5,035		11,069

		Total current liabilities		180,940		240,298
Bank credit facilities				81,872		19,000
Other long-term debt				677,826		575,178
Other liabilities				24,408		21,524
Deferred income taxes				17,218		16,426
Shareholders' equity:
	Common stock			4,908		4,883
	Capital surplus			1,148,647		1,145,282
	Accumulated deficit			(153,739	)	(165,824	)
	Accumulated other comprehensive loss			(35,180	)	(4,147	)
	Treasury stock, at cost			(56,536	)	(56,251	)

		Total shareholders' equity		908,100		923,943

			$	1,890,364		1,796,369

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF PRODUCTION AND OPERATIONS

(Unaudited)

						Three Months Ended					Nine Months Ended
						September 30, 2002			September 30, 2001		September 30, 2002		September 30, 2001
						(In Thousands Except Production and Per Share Amounts)
PRODUCTION
	Natural gas (MMCF)						23,613		26,811		69,355		83,311

	Oil, condensate and natural gas liquids (thousands of barrels)						2,242		2,724		6,588		7,785

STATEMENTS OF CONSOLIDATED OPERATIONS
	Revenue:
		Oil and gas sales:
			Gas			$	73,990		82,167		207,219		397,775
			Oil, condensate and natural gas liquids				49,744		63,575		137,957		192,944

				Total oil and gas sales			123,734		145,742		345,176		590,719
		Marketing and processing, net					1,047		877		2,925		2,500

					Total revenue		124,781		146,619		348,101		593,219
	Operating expenses:
		Oil and gas production					42,307		52,434		119,893		136,605
		General and administrative					9,637		7,750		27,856		21,032
		Merger and seismic licensing expense					—		3,763		—		8,261
		Depreciation and depletion					48,442		60,381		136,216		174,321

					Total operating expenses		100,386		124,328		283,965		340,219

Earnings from operations							24,395		22,291		64,136		253,000
Other income and expense:
	Other expense, net						163		685		882		1,868
	Interest expense						13,084		12,270		37,797		37,763
	Translation loss (gain) on subordinated debt						2,489		5,465		(332	)	7,766
	Realized loss (gain) on derivative instruments, net						1,436		(11,826	)	1,190		(11,826	)
	Unrealized loss (gain) on derivative instruments, net						459		8,881		1,075		(4,705	)

					Total other income and expense		17,631		15,475		40,612		30,866

Earnings before income taxes and extraordinary item							6,764		6,816		23,524		222,134
Income tax expense:
	Current						61		485		315		2,721
	Deferred						2,020		3,964		8,023		83,582

							2,081		4,449		8,338		86,303

Net earnings before extraordinary item							4,683		2,367		15,186		135,831
Extraordinary loss on extinguishment of debt							(1,774	)	(827	)	(3,103	)	(2,417	)

Net earnings						$	2,909		1,540		12,083		133,414

Weighted average number of common shares outstanding:
	Basic						46,974		47,182		46,912		47,989

	Diluted						48,062		48,476		48,210		49,722

Basic earnings per common share:
	Earnings attributable to common stock before extraordinary item					$	0.10		.05		0.32		2.83
	Extraordinary loss on extinguishment of debt						(0.04	)	(.02	)	(0.06	)	(.05	)

	Earnings attributable to common stock					$	0.06		.03		0.26		2.78

Diluted earnings per common share:
	Earnings attributable to common stock before extraordinary item					$	0.10		.05		0.31		2.73
	Extraordinary loss on extinguishment of debt						(0.04	)	(.02	)	(0.06	)	(.05	)

	Earnings attributable to common stock					$	0.06		.03		0.25		2.68

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Nine Months Ended September 30,
				2002			2001
				(In Thousands)
Cash flows from operating activities:
	Net earnings before extraordinary item			$	15,186		135,831
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			136,216		174,321
		Amortization of deferred debt costs			1,644		1,309
		Translation (gain) loss on subordinated debt			(332	)	7,766
		Unrealized loss (gain) on derivative instruments, net			1,075		(4,705	)
		Deferred income tax expense			8,023		83,582
		Other, net			(1,771	)	(54	)
		Decrease in accounts receivable			35,878		31,876
		Decrease (increase) in other current assets			5,719		(11,102	)
		(Decrease) increase in accounts payable			(73,832	)	46,080
		Increase (decrease) in accrued interest and other current liabilities			2,923		(55,617	)

			Net cash provided by operating activities		130,729		409,287
Cash flows from investing activities:
	Capital expenditures for property and equipment:
		Exploration, development and acquisition costs			(254,565	)	(428,334	)
		Other fixed assets			(3,277	)	(3,058	)
	Proceeds from sales of assets				3,744		31,846
	Increase in other assets, net				(1,991	)	(2,497	)

			Net cash used by investing activities		(256,089	)	(402,043	)
Cash flows from financing activities:
	Proceeds from bank borrowings				346,760		687,986
	Repayments of bank borrowings				(283,878	)	(788,238	)
	Issuance of 7³/4% senior notes, net of issuance costs				146,846		—
	Issuance of 8% senior notes, net of issuance costs				—		199,500
	Repurchases of 10¹/2% senior subordinated notes				(21,283	)	—
	Repurchases of 8³/4% senior subordinated notes				(66,248	)	(67,003	)
	Proceeds from exercise of options and warrants				3,709		8,261
	Purchase of treasury stock				(560	)	(55,720	)
	Decrease in other liabilities, net				(1	)	(1,202	)

			Net cash provided (used) by financing activities		125,345		(16,416	)
Effect of exchange rate changes on cash					(591	)	(331	)

Net decrease in cash and cash equivalents					(606	)	(9,503	)
Cash and cash equivalents at beginning of period					8,387		14,003

Cash and cash equivalents at end of period				$	7,781		4,500

Cash paid during the period for:
	Interest			$	31,215		35,398
	Income taxes			$	1,363		4,512

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001

(Unaudited)

(1) BASIS OF PRESENTATION

The condensed consolidated financial statements included herein are unaudited. The consolidated financial statements include the accounts of Forest Oil Corporation and its consolidated subsidiaries (collectively, Forest or the Company). In the opinion of management, all adjustments, consisting of normal recurring accruals, have been made which are necessary for a fair presentation of the financial position of Forest at September 30, 2002 and the results of operations for the three and nine months ended September 30, 2002 and 2001. 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. Assumptions, judgments and estimates are also required in determining impairments of undeveloped properties and the valuation of deferred tax assets.

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, 2001, previously filed with the Securities and Exchange Commission.

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

Earnings per Share:

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

Diluted earnings per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options and warrants. The effect of potentially dilutive securities is based on earnings before extraordinary items.

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

		Three Months Ended September 30,			Nine Months Ended September 30,
		2002(1)		2001(2)	2002(3)	2001(4)
		(In Thousands Except Per Share Amounts)
Net earnings before extraordinary item		$	4,683	2,367	15,186	135,831

Weighted average common shares outstanding during the period			46,974	47,182	46,912	47,989
	Add dilutive effects of employee stock options		363	513	494	803
	Add dilutive effects of warrants		725	781	804	930

Weighted average common shares outstanding including the effects of dilutive securities			48,062	48,476	48,210	49,722

Basic earnings per share before extraordinary item		$	.10	.05	.32	2.83

Diluted earnings per share before extraordinary item		$	.10	.05	.31	2.73

(1): At September 30, 2002, options to purchase 2,610,250 shares of common stock at prices ranging from $24.88 to $50.00 per share were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2012.
(2): At September 30, 2001, options to purchase 2,009,820 shares of common stock at prices ranging from $27.02 to $50.00 per share 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 2002 through 2011.
(3): At September 30, 2002, options to purchase 2,020,200 shares of common stock at prices ranging from $27.02 to $50.00 were outstanding, but were not included in the computation of diluted earnings per share because the exercise prices of these options were greater than the average market price of the common stock during the period. These options expire at various dates from 2003 to 2012.
(4): At September 30, 2001, options to purchase 345,250 shares of common stock at prices ranging from $30.75 to $50.00 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.

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 income. Items included in the Company's other comprehensive income (loss) for the three and nine months ended September 30, 2002 and 2001 are foreign currency gains (losses) related to the translation of the assets and liabilities of the Company's Canadian operations; unrealized gains (losses) related to the change in fair value of derivative instruments designated as cash flow hedges; and unrealized gains (losses) related to the change in fair value of securities available for sale.

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

		Three Months Ended September 30,					Nine Months Ended September 30,
		2002			2001		2002		2001
		(In Thousands)
Net earnings		$	2,909		1,540		12,083		133,414
Other comprehensive income (loss):
	Foreign currency translation gains (losses)		(7,662	)	(3,111	)	1,429		(2,796	)
	Unrealized gain (loss) on derivative instruments, net		(6,261	)	17,982		(32,469	)	19,120
	Unrealized (loss) gain on securities available for sale		36		(477	)	9		(368	)

Total comprehensive earnings (loss)		$	(10,978	)	15,934		(18,948	)	149,370

(3) NET PROPERTY AND EQUIPMENT

Components of net property and equipment are as follows:

	September 30, 2002			December 31, 2001
	(In Thousands)
Oil and gas properties	$	3,662,951		3,408,317
Buildings, transportation and other equipment		26,345		23,137

		3,689,296		3,431,454
Less accumulated depreciation, depletion and valuation allowance		(2,051,556	)	(1,914,554	)

	$	1,637,740		1,516,900

(4) GOODWILL AND OTHER INTANGIBLE ASSETS

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

	September 30, 2002			December 31, 2001
	(In Thousands)
Goodwill	$	14,520		14,394
Long-term gas marketing contracts		12,668		12,558

		27,188		26,952
Less accumulated amortization		(14,403	)	(13,689	)

	$	12,785		13,263

Effective January 1, 2002, pursuant to SFAS No. 142, goodwill is no longer being amortized but will be tested annually for impairment. Prior thereto, goodwill was amortized on a straight-line basis over 20 years. Long-term gas marketing contracts are amortized based on estimated revenues over the life of the contracts.

Had SFAS No. 142 been applied as of January 1, 2001, net earnings and earnings per common share for the three and nine months ended September 30, 2001 would have been as follows::

		Three Months Ended September 30, 2001		Nine Months Ended September 30, 2001
		(In Thousands, Except Per Share Amounts)
Net earnings		$	1,540	133,414
Add back: Goodwill amortization, net of tax			95	365

Adjusted net earnings		$	1,635	133,779

Basic earnings per common share:
	Earnings	$	.03	2.78
	Add back: Goodwill amortization, net of tax		—	.01

	Adjusted earnings	$	.03	2.79

Diluted earnings per common share:
	Earnings	$	.03	2.68
	Add back: Goodwill amortization, net of tax		—	.01

	Adjusted earnings	$	.03	2.69

(5) LONG-TERM DEBT

Components of long-term debt are as follows:

	September 30, 2002
	Principal		Unamortized Discount		Other		Total	December 31, 2001
	(In Thousands)
U.S. Credit Facility	$	35,000	—		—		35,000	19,000
Canadian Credit Facility		46,872	—		—		46,872	—
8% Senior Notes Due 2008		265,000	(561	)	13,138	(1)	277,577	264,366
8% Senior Notes Due 2011		160,000	—		7,720	(1)	167,720	160,000
7³/4% Senior Notes Due 2014		150,000	(2,766	)	17,211	(2)	164,445	—
10¹/2% Senior Subordinated Notes Due 2006		68,470	(386	)	—		68,084	87,569
8³/4% Senior Subordinated Notes Due 2007		—	—		—		—	63,243

	$	725,342	(3,713	)	38,069		759,698	594,178

(1): Represents the unamortized portion of a gain recognized upon termination of two 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.
(2): Represents unrealized gain relating to an interest rate swap accounted for as a fair value hedge.

In the second quarter of 2002, the Company issued $150,000,000 principal amount of 7³/4% Senior Notes due 2014 at 98.09% of par for proceeds of $146,846,000 (net of related issuance costs).

In the third quarter of 2002, the Company redeemed $57,948,000 of outstanding principal amount of 8³/4% Senior Subordinated Notes (the 8³/4% Notes) at 104.375% of par value. As a result, an extraordinary loss on extinguishment of debt of $1,774,000 (net of tax) was recorded. The 8³/4% Notes were issued by Forest's wholly owned subsidiary, Canadian Forest Oil Ltd. (Canadian Forest), and were guaranteed on a senior subordinated basis by Forest. Forest was required to recognize foreign currency translation gains or losses 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. As a result of the change in the value of the Canadian dollar relative to the U.S. dollar during the third quarter and first nine months of 2002, Forest reported noncash translation (gains) losses related to the 8³/4% Notes of approximately $2,489,000 and $(332,000), respectively, compared to $5,465,000 and $7,766,000 in the third quarter and first nine months of 2001. Following the redemption of the 8³/4% Notes, Forest has no debt issued in a currency other than the functional currency of the issuer.

(6) FINANCIAL INSTRUMENTS

The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment of the changes in fair value is dependent upon whether or not a derivative instrument is a cash flow hedge or a fair value hedge. For cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as oil and gas revenue. 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:

At September 30, 2002, the Company had one interest rate swap in place. In connection with the issuance of $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 three month London Interbank Offered Rate (LIBOR) plus 153 basis points in exchange for a fixed rate of 7³/4% on $150,000,000 principal amount 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 are 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 is recorded as a derivative asset (liability) and the corresponding fair value of the related debt instrument is recorded as an increase (decrease) in the related debt balance. At September 30, 2002, with respect to the interest rate swap, the Company had a current derivative asset of $6,876,000, a long-term derivative asset of $10,335,000 and an increase in the carrying value of the related notes of $17,211,000. For the third quarter and nine months ended September 30, 2002, the Company recognized net gains of $1,598,000 and $2,760,000, respectively, under this interest rate swap, which were recorded as reductions of interest expense.

In August 2002, the Company sold a call option on two of the Company's then existing interest rate swaps that were effective hedges of the fixed interest rates on the 8% Senior Notes due 2008 and 2011. 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. A receivable of approximately $22,637,000 (including accrued settlements of approximately $1,779,000) was recorded on termination of the interest rate swaps and the net realized gain of $20,858,000 was added to the carrying value of the related debt. The gain 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 the settlement.

For the third quarter and nine months ended September 30, 2002, the Company recognized net gains of $1,492,000 and $4,590,000, respectively, under the two terminated interest rate swaps, which were recorded as reductions of interest expense. From inception to September 30, 2002, the effective rates on Forest's 8% Senior Notes due 2008 and 2011 were reduced to 7.18% and 7.32%, respectively, as a result of the original swaps. From October 1, 2002, to maturity, the effective rates on the 8% Senior Notes due 2008 and 2011 will be reduced to 7.24% and 7.66%, respectively, as a result of liquidation of those swaps.

Commodity Swaps, Collars and Basis Swaps:

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

All of the Company's commodity swaps and collar agreements and a portion of its basis swaps in place at September 30, 2002 have been designated as cash flow hedges. At September 30, 2002 the Company had a derivative asset of $5,076,000 (of which $3,496,000 was classified as current), a derivative liability of $27,028,000 (of which $23,723,000 was classified as current), a deferred tax asset of $8,342,000 (of which $7,686,000 was classified as current) and accumulated other comprehensive loss of approximately $13,177,000.

The Company's (gains) losses under these agreements were:

		Three Months Ended September 30,				Nine Months Ended September 30,
		2002		2001		2002		2001
				(In Thousands)
Derivatives designated as cash flow hedges		$	2,876	(14,568	)	(5,734	)	(3,852	)
Derivatives not designated as cash flow hedges			72	(2,945	)	442		(16,531	)

	Total (gain) loss	$	2,948	(17,513	)	(5,292	)	(20,383	)

In a typical swap agreement, Forest receives the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index if the index price is lower. If the index price is higher, Forest pays the difference. By entering into swap agreements the Company effectively fixes the price that it will receive in the future for the hedged production. Forest's current swaps are settled in cash on a monthly basis. As of September 30, 2002, Forest had entered into the following swaps:

	Natural Gas			Oil (NYMEX WTI)
	BBTUs per Day	Average Hedged Price per MMBTU		Barrels per Day	Average Hedged Price per Barrel
Fourth Quarter 2002	81.6	$	3.547	10,000	$	22.223
First Quarter 2003	25.0	$	3.624	6,000	$	23.273
Second Quarter 2003	40.0	$	3.960	4,500	$	22.550
Third Quarter 2003	40.0	$	3.960	4,000	$	22.009
Fourth Quarter 2003	13.5	$	3.960	4,000	$	21.928
First Quarter 2004	—		—	3,000	$	23.125
Second Quarter 2004	—		—	1,000	$	23.325

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

only if the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only if the index price is above the ceiling price. Collars are also settled in cash, either on a monthly basis or at the end of their terms. By entering into collars, the Company effectively provides a floor for the price that it will receive for the hedged production; however, the collar also establishes a maximum price that the Company will receive for the hedged production if prices increase above the ceiling price. The Company enters into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged production. As of September 30, 2002, the Company had entered into the following gas and oil collars:

	Natural Gas
	BBTUs per Day	Average Floor Price per MMBTU		Average Ceiling Price per MMBTU
Fourth Quarter 2002	46.5	$	3.429	$	5.038
First Quarter 2003	80.0	$	3.438	$	5.103
Second Quarter 2003	20.0	$	3.250	$	4.075
Third Quarter 2003	20.0	$	3.250	$	4.075
Fourth Quarter 2003	20.0	$	3.250	$	4.887
First Quarter 2004	20.0	$	3.250	$	5.300

	Oil (NYMEX WTI)
	Barrels per Day	Average Floor Price per BBL		Average Ceiling Price per BBL
First Quarter 2003	3,000	$	22.00	$	25.417
Second Quarter 2003	3,000	$	22.00	$	25.417
Third Quarter 2003	3,000	$	22.00	$	25.417
Fourth Quarter 2003	3,000	$	22.00	$	25.417
First Quarter 2004	2,000	$	22.00	$	24.075

The Company also uses basis swaps from time to time in connection with natural gas swaps, in order to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. At September 30, 2002 there were basis swaps designated as cash flow hedges in place with weighted average volumes of 109.9 BBTUs per day for the remainder of 2002 and weighted average volumes of 38.5 BBTUs per day for 2003. At September 30, 2002 there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 5.1 BBTUs per day for the remainder of 2002.

(7) MARKETING AND PROCESSING OPERATIONS

Components of marketing and processing, net are as follows:

	Three Months Ended September 30,			Nine Months Ended September 30,
	2002		2001	2002	2001
			(In Thousands)
Marketing and processing revenue	$	50,655	55,371	176,004	253,941
Marketing and processing expense		49,608	54,494	173,079	251,441

Marketing and processing, net	$	1,047	877	2,925	2,500

(8) 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 (Statement No. 131). Forest has six reportable segments consisting of oil and gas operations in five business units (Gulf of Mexico Offshore Region, Gulf Coast Onshore Region, Western United States, Alaska and Canada), and marketing and processing operations conducted by ProMark in Canada. 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 Forest's consolidated financial statements.

Three Months Ended September 30, 2002

		Oil and Gas Operations
		Oil and Gas Operations									Marketing
		GOM Offshore		Gulf Coast Onshore				Total U.S.			Marketing	Total Company
		GOM Offshore		Gulf Coast Onshore	Western	Alaska		Total U.S.	Canada	Total	Canada	Total Company
		(In Thousands)
Revenue		$	67,121	11,758	16,108	16,416		111,403	12,669	124,072	709	124,781
Expenses:
	Oil and gas production		18,821	2,356	5,870	11,372		38,419	3,888	42,307	—	42,307
	General and administrative		4,069	915	1,354	1,772		8,110	1,177	9,287	350	9,637
	Depletion		29,106	2,866	4,641	4,755		41,368	5,602	46,970	323	47,293

Earnings from operations		$	15,125	5,621	4,243	(1,483	)	23,506	2,002	25,508	36	25,544

Capital expenditures		$	23,628	5,354	9,018	34,652		72,652	3,969	76,621	—	76,621

Property and equipment, net		$	485,774	293,957	229,283	313,735		1,322,749	230,455	1,553,204	—	1,553,204

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	25,544
Administrative asset depreciation		(1,149	)
Other expense, net		(163	)
Interest expense		(13,084	)
Translation loss on subordinated debt		(2,489	)
Realized loss on derivative instruments, net		(1,436	)
Unrealized loss on derivative instruments, net		(459	)

Earnings before income taxes and extraordinary item	$	6,764

CAPITAL EXPENDITURES:
Reportable segments	$	76,621
International interests		(1,250	)
Administrative assets and other		1,163

Total capital expenditures	$	76,534

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,553,204
International interests		77,685
Administrative assets, net and other		6,851

Total property and equipment, net	$	1,637,740

Nine Months Ended September 30, 2002

		Oil and Gas Operations
		Oil and Gas Operations								Marketing
		GOM Offshore		Gulf Coast Onshore			Total U.S.			Marketing	Total Company
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Canada	Total Company
		(In Thousands)
Revenue		$	176,554	36,078	44,619	51,067	308,318	37,563	345,881	2,220	348,101
Expenses:
	Oil and gas production		49,719	13,156	15,819	30,543	109,237	10,656	119,893	—	119,893
	General and administrative		10,668	3,114	4,324	5,169	23,275	3,498	26,773	1,083	27,856
	Depletion		80,291	10,772	12,799	13,333	117,195	15,532	132,727	611	133,338

Earnings from operations		$	35,876	9,036	11,677	2,022	58,611	7,877	66,488	526	67,014

Capital expenditures		$	69,176	19,655	32,729	104,051	225,611	17,125	242,736	—	242,736

Property and equipment, net		$	485,774	293,957	229,283	313,735	1,322,749	230,455	1,553,204	—	1,553,204

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	67,014
Administrative asset depreciation		(2,878	)
Other expense, net		(882	)
Interest expense		(37,797	)
Translation gain on subordinated debt		332
Realized loss on derivative instruments, net		(1,190	)
Unrealized loss on derivative instruments, net		(1,075	)

Earnings before income taxes and extraordinary item	$	23,524

CAPITAL EXPENDITURES:
Reportable segments	$	242,736
International interests		11,829
Administrative assets and other		3,277

Total capital expenditures	$	257,842

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,553,204
International interests		77,685
Administrative assets, net and other		6,851

Total property and equipment, net	$	1,637,740

Three Months Ended September 30, 2001

		Oil and Gas Operations
		Oil and Gas Operations								Marketing
		GOM Offshore		Gulf Coast Onshore			Total U.S.			Marketing	Total Company
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Canada	Total Company
		(In Thousands)
Revenue		$	83,782	12,436	15,178	23,098	134,494	11,304	145,798	821	146,619
Expenses:
	Oil and gas production		22,804	4,938	6,888	13,019	47,649	4,785	52,434	—	52,434
	General and administrative		3,570	744	948	1,281	6,543	892	7,435	315	7,750
	Depletion		42,081	3,530	3,345	5,580	54,536	4,036	58,572	463	59,035

Earnings from operations		$	15,327	3,224	3,997	3,218	25,766	1,591	27,357	43	27,400

Capital expenditures		$	102,157	15,603	19,193	21,824	158,777	15,246	174,023	—	174,023

Property and equipment, net		$	626,195	271,109	201,108	176,056	1,274,468	223,828	1,498,296	—	1,498,296

Information for reportable segments relates to the Company's September 30, 2001 consolidated totals as follows:

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	27,400
Administrative asset depreciation		(1,346	)
Other expense, net		(685	)
Merger and seismic licensing expense		(3,763	)
Interest expense		(12,270	)
Translation loss on subordinated debt		(5,465	)
Realized gain on derivative instruments, net		11,826
Unrealized loss on derivative instruments, net		(8,881	)

Earnings before income taxes and extraordinary item	$	6,816

CAPITAL EXPENDITURES:
Reportable segments	$	174,023
International interests		3,431
Administrative assets and other		623

Total capital expenditures	$	178,077

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,498,296
International interests		68,694
Administrative assets, net and other		5,259

Total property and equipment, net	$	1,572,249

Nine Months Ended September 30, 2001

		Oil and Gas Operations
		Oil and Gas Operations								Marketing
		GOM Offshore		Gulf Coast Onshore			Total U.S.			Marketing	Total Company
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Canada	Total Company
		(In Thousands)
Revenue		$	366,995	52,370	66,660	57,335	543,360	47,074	590,434	2,785	593,219
Expenses:
	Oil and gas production		64,580	13,949	18,553	26,937	124,019	12,586	136,605	—	136,605
	General and administrative		9,116	2,082	2,797	3,299	17,294	2,705	19,999	1,033	21,032
	Depletion		120,219	11,232	12,310	12,885	156,646	13,098	169,744	1,405	171,149

Earnings from operations		$	173,080	25,107	33,000	14,214	245,401	18,685	264,086	347	264,433

Capital expenditures		$	237,010	28,243	29,861	56,420	351,534	46,468	398,002	—	398,002

Property and equipment, net		$	626,195	271,109	201,108	176,056	1,274,468	223,828	1,498,296	—	1,498,296

Information for reportable segments relates to the Company's September 30, 2001 consolidated totals as follows:

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	264,433
Administrative asset depreciation		(3,172	)
Other expense, net		(1,868	)
Merger and seismic licensing expense		(8,261	)
Interest expense		(37,763	)
Translation loss on subordinated debt		(7,766	)
Realized gain on derivative instruments, net		11,826
Unrealized gain on derivative instruments, net		4,705

Earnings before income taxes and extraordinary item	$	222,134

CAPITAL EXPENDITURES:
Reportable segments	$	398,002
International interests		30,332
Administrative assets and other		3,058

Total capital expenditures	$	431,392

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,498,296
International interests		68,694
Administrative assets, net and other		5,259

Total property and equipment, net	$	1,572,249

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" included in Forest's 2001 Annual Report on Form 10-K.

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 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 our future natural gas and liquids production, outlook on oil and gas prices, estimates of our oil and gas reserves, estimates of operating costs, planned capital expenditures, availability of capital resources to fund capital expenditures and the impact of political and regulatory developments, 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 future oil and gas reserves and 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 2001 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 attributable to Forest are expressly qualified in their entirety by this cautionary statement. Forest disclaims any obligation to update forward-looking statements contained herein, except as may be otherwise required by law.

Results of Operations for the Third Quarter of 2002

Net earnings for the third quarter of 2002 were $2,909,000 compared to net earnings of $1,540,000 in the corresponding period of 2001. The increase in earnings in the third quarter of 2002 compared to the third quarter of 2001 is the result of decreases in oil and gas production expense, depletion expense and income tax expense offset partially by lower oil and gas sales revenue.

Marketing and processing revenue, net increased 19% to $1,047,000 in the third quarter of 2002 from $877,000 in the third quarter of 2001. The increase is due primarily to gas plant income in the United States.

Oil and gas sales revenue decreased by 15% to $123,734,000 in the third quarter of 2002 from $145,742,000 in the third quarter of 2001, primarily as a result of lower product prices and production volumes. The average gas sales price declined 4% for the third quarter of 2002 compared to the same period of 2001. The average liquids sales price declined 5% compared to the average price in the 2001 period. Volume decreases in the 2002 period were attributable primarily to the Gulf of Mexico Offshore Business Unit. The Gulf of Mexico offshore properties were impacted by the 2001 sale of 50% of Forest's interests in the South Marsh Island and Vermilion areas, have experienced hurricane

downtime in September 2002, and have also experienced normal production declines that were the result of reduced capital expenditures allocated to that region.

Oil and gas production expense for the third quarter of 2002 decreased 19% to $42,307,000 compared to $52,434,000 in the corresponding period in 2001. The decrease was due primarily to lower direct operating expense in the Gulf of Mexico Offshore Business Unit.

Production volumes and weighted average sales prices for the three months ended September 30, 2002 and 2001 were as follows:

				Three Months Ended September 30,
				2002			2001
Natural Gas
	Production (MMCF):
		United States			20,285		24,334
		Canada			3,328		2,477

			Total		23,613		26,811

	Sales price received (per MCF)(1)			$	2.84		2.74
	Effects of energy swaps and collars (per MCF)(2)				.10		.32

	Average sales price (per MCF)(1)			$	2.94		3.06
Liquids
Oil and condensate:
	Production (MBBLS)				1,945		2,360
	Sales price received (per BBL)			$	26.44		24.61
	Effects of energy swaps and collars (per BBL) (2)				(2.75	)	.31

	Average sales price (per BBL)			$	23.69		24.92
Natural gas liquids:
	Production (MBBLS)				297		364
	Average sales price (per BBL)			$	12.35		13.10
Total Liquids Production (MBBLS):
		United States			1,942		2,386
		Canada			300		338

			Total		2,242		2,724

	Average sales price (per BBL)			$	22.19		23.34
Total Production
Production volumes (MMCFE)					37,065		43,155
Average sales price (per MCFE) (1)				$	3.22		3.38

(1): Prices shown for the third quarter of 2002 exclude the effects of $4,500,000 of proceeds from business interruption insurance for lost gas sales following a 2001 blowout in the Gulf of Mexico. Including the effects of these proceeds, the sales price received, average sales price per MCF, and average sales price per MCFE were $3.03, $3.13 and $3.34, respectively.
(2): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Certain of the arrangements have been designated as cash flow hedges. Hedged natural gas volumes were 6,900 MMCF and 14,261 MMCF in the third quarter of 2002 and 2001, respectively. Hedged oil and condensate volumes were 920 MBBLS and 1,150 MBBLS in the third quarter of 2002 and 2001, respectively. The aggregate net gains (losses) under energy swap agreements were $(2,876,000) and $9,186,000 for the three months ended September 30, 2002 and 2001, respectively, and were accounted for as increases (reductions), respectively, to oil and gas sales.

General and administrative expense was $9,637,000 in the third quarter of 2002 compared to $7,750,000 in the third quarter of 2001. Total overhead costs (capitalized and expensed general and administrative costs) were $15,372,000 in the third quarter of 2002 compared to $13,075,000 in the third quarter of 2001. The increases in the 2002 period were attributable, in approximately equal measure, to higher gross overhead costs and to lower fixed-rate overhead cost recoveries for production operations and exploration and development activities. Higher gross overhead costs are attributable primarily to increases in salaried headcount, legal expense and insurance expense. Lower fixed-rate overhead cost recoveries for production operations are primarily the result of the Gulf of Mexico property sale and the related change in operatorship of those properties. Lower fixed-rate overhead cost recoveries for exploration and development activities are the result of decreased capital spending in the 2002 period. The percentage of overhead capitalized remained relatively constant at approximately 40% during the 2002 and 2001 periods.

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

		Three Months Ended September 30,
		2002		2001
		(In Thousands)
Overhead costs capitalized		$	5,735	5,325
General and administrative costs expensed(1)			9,637	7,750

	Total overhead costs	$	15,372	13,075

(1): Includes $350,000 and $340,000 related to marketing operations for the three months ended September 30, 2002 and 2001, respectively.

Depreciation and depletion expense was $48,442,000 in the third quarter of 2002 compared to $60,381,000 in the third quarter of 2001. The decrease was attributable primarily to lower production volumes. On a per-unit basis, the depletion rate was $1.28 per MCFE in the third quarter of 2002 compared to $1.37 per MCFE in the corresponding prior year period. The decrease in the per-unit rate was due primarily to the addition of proved reserves over the past year at lower than historical finding costs.

Other expense was $163,000 in the third quarter of 2002, consisting primarily of franchise taxes. Other expense of $685,000 in the third quarter of 2001 was due primarily to writeoffs of items associated with the Company's merger with Forcenergy.

Interest expense in the third quarter of 2002 increased to $13,084,000 compared to $12,270,000 in the third quarter of 2001, due primarily to higher debt balances offset partially by lower interest rates on variable and fixed rate debt.

Foreign currency translation loss was $2,489,000 in the third quarter of 2002 and $5,465,000 in the third quarter of 2001. The foreign currency translation loss was the result of translation of the 8³/4% Notes issued by Canadian Forest, and was attributable to the 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 gains or losses 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 $1,436,000 in the third quarter of 2002 and a realized gain on derivative instruments of $11,826,000 in the third quarter of 2001. The realized loss in 2002 was due primarily to a $1,823,000 net settlement of a call option related to two terminated interest rate swaps associated with our 8% Senior Notes. The gain in 2001 was due primarily to realization of gains on oil and gas collars that were previously reflected in unrealized gains on

derivative instruments. There was a net unrealized loss on derivative instruments in the third quarter of 2002 of $459,000 compared to a net unrealized loss on derivative instruments of $8,881,000 in the corresponding period in 2001. The loss in 2002 was attributable primarily to decreases in the estimated future value of existing commodity swaps as a result of increases in commodity futures prices. The loss in the third quarter of 2001 was due to a decrease in unrealized gains related to oil and gas collars as a result of a significant portion of the previously unrecorded gain becoming realized during the quarter. 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.

Income tax expense of $2,081,000 was recognized in the third quarter of 2002 compared to income tax expense of $4,449,000 in the third quarter of 2001. The decrease is attributable primarily to lower oil and gas sales revenue.

The extraordinary loss on extinguishment of debt of $1,774,000 (net of tax) in the third quarter of 2002 resulted from the redemption of $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value. The extraordinary loss on extinguishment of debt of $827,000 (net of tax) in the third quarter of 2001 resulted from the repurchase of $26,640,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 102% of par value.

Results of Operations for the Nine Months Ended September 30, 2002

Net earnings for the nine months ended September 30, 2002 were $12,083,000 compared to $133,414,000 in the corresponding period of 2001. The decline in earnings is attributable primarily to a decrease in oil and gas revenue, offset partially by a decrease in costs.

Marketing and processing revenue, net increased 17% to $2,925,000 in the nine months ended September 30, 2002 from $2,500,000 in the same period in 2001. The increase is due primarily to gas plant income in the United States.

Oil and gas sales revenue decreased by 42% to $345,176,000 in the nine months ended September 30, 2002 from $590,719,000 in the same period in 2001, primarily as a result of lower product prices and production volumes. For the nine months ended September 30, 2002, the average gas sales price declined 39% and the average liquids sales price declined 15% compared to average prices in the corresponding 2001 period. Lower production volumes in the 2002 period were attributable primarily to the Gulf of Mexico Offshore Business Unit. The Gulf of Mexico offshore properties were impacted by the sale of 50% of Forest's interests in the South Marsh Island and Vermilion areas in the fourth quarter of 2001, and also experienced hurricane downtime and normal declines caused by reduced capital expenditures allocated to that region.

Oil and gas production expense for the nine months ended September 30, 2002 decreased 12% to $119,893,000 compared to $136,605,000 in the corresponding period of 2001. The decrease was due primarily to decreases in direct operating expense in the Gulf of Mexico Offshore Business Unit.

Production volumes and weighted average sales prices for the nine months ended September 30, 2002 and 2001 were as follows:

				Nine Months Ended September 30,
				2002			2001
Natural Gas
	Production (MMCF):
		United States			58,685		75,349
		Canada			10,670		7,962

			Total		69,355		83,311

	Sales price received (per MCF)(1)			$	2.73		4.72
	Effects of energy swaps and collars (per MCF)(2)				.19		.05

	Average sales price (per MCF)(1)			$	2.92		4.77
Liquids
Oil and condensate:
	Production (MBBLS)				5,726		6,794
	Sales price received (per BBL)			$	23.69		25.80
	Effects of energy swaps and collars (per BBL)(2)				(1.30	)	(.09	)

	Average sales price (per BBL)			$	22.39		25.71
Natural gas liquids:
	Production (MBBLS)				862		991
	Average sales price (per BBL)			$	11.31		18.41
Total Liquids Production (MBBLS):
	United States				5,691		6,761
	Canada				897		1,024

			Total		6,588		7,785

	Average sales price (per BBL)			$	20.94		24.78
Total Production
Production volumes (MMCFE)					108,883		130,021
Average sales price (per MCFE) (1)				$	3.13		4.54

(1): Prices shown for the nine months ended September 30, 2002 exclude the effects of $4,500,000 of proceeds from business interruption insurance for lost gas sales following a 2001 blowout in the Gulf of Mexico. Including the effects of these proceeds, the sales price received, average sales price per MCF and average sales price per MCFE were $2.80, $2.99 and $3.17, respectively.
(2): Commodity swaps and collars were transacted to hedge the price of spot market volumes against price fluctuations. Certain of the arrangements have been designated as cash flow hedges. Hedged natural gas volumes were 24,260 MMCF and 43,193 MMCF in the nine months ended September 30, 2002 and 2001, respectively. Hedged oil and condensate volumes were 3,002 MBBLS and 3,213 MBBLS for the nine months ended September 30, 2002 and 2001, respectively. The aggregate net gains under energy swap agreements were $5,734,000 and $3,852,000, respectively, for the nine months ended September 30, 2002 and 2001 and were accounted for as increases to oil and gas sales.

General and administrative expense was $27,856,000 for the nine months ended September 30, 2002 compared to $21,032,000 in the same period in 2001. Total overhead costs (capitalized and expensed general and administrative costs) were $47,004,000 in the nine months ended September 30, 2002 compared to $35,874,000 in the same period in 2001. The increases in the 2002 period were attributable, in approximately equal measure, to higher gross overhead costs, and to lower fixed-rate overhead cost recoveries for production operations and exploration and development activities. Higher

gross overhead costs are attributable primarily to increases in salaried headcount, legal expense and insurance expense. Lower fixed-rate overhead cost recoveries for production operations are primarily the result of the Gulf of Mexico property sale and the related change in operatorship of those properties. Lower fixed-rate overhead cost recoveries for exploration and development activities are the result of decreased capital spending in the 2002 period. The percentage of overhead capitalized remained relatively constant at approximately 40% during the 2002 and 2001 periods.

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

	Nine Months Ended September 30,
	2002		2001
	(In Thousands)
Overhead costs capitalized	$	19,148	14,842
General and administrative costs expensed(1)		27,856	21,032

	$	47,004	35,874

(1): Includes $1,083,000 and $1,058,000 related to marketing and processing operations for the nine months ended September 30, 2002 and 2001, respectively.

Depreciation and depletion expense was $136,216,000 in the nine months ended September 30, 2002 compared to $174,321,000 in the same period in 2001. The decrease was attributable primarily to lower production volumes. On a per-unit basis, the depletion rate was $1.22 per MCFE in the nine months ended September 30, 2002 compared to $1.32 per MCFE in the same period in 2001. The decrease in the per-unit rate was due primarily to the addition of proved reserves over the past year at lower than historical finding costs.

Other expense of $882,000 in the nine months ended September 30, 2002 consisted primarily of franchise taxes. Other expense of $1,868,000 in the same period of 2001 was due primarily to writeoffs of items associated with the merger with Forcenergy and the impairment of an account receivable.

Interest expense was $37,797,000 for the nine months ended September 30, 2002 and was $37,763,000 for the same period in 2001. Lower interest rates on variable and fixed rate debt in the 2002 period were offset by higher debt balances.

There was a foreign currency translation gain of $332,000 in the nine months ended September 30, 2002 and a loss of $7,766,000 in the same period in 2001. The foreign currency translation gains and losses were the result of translation of the 8³/4% Notes issued by Canadian Forest, and were attributable to the increases and decreases in the value of the Canadian dollar relative to the U.S. dollar during the periods. Forest was required to recognize the noncash foreign currency translation gains or losses 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 $1,190,000 for the nine months ended September 30, 2002 and realized gains on derivative instruments of $11,826,000 for the nine months ended September 30, 2001. The loss in 2002 was due primarily to a $1,823,000 net settlement of a call option related to two terminated interest rate swaps associated with our 8% Senior Notes. The gain in 2001 was due primarily to realization of gains on oil and gas collars that were previously reflected in unrealized gains on derivative instruments. There was a net unrealized loss on derivative instruments in the nine months ended September 30, 2002 of $1,075,000 compared to a net unrealized gain on derivative instruments of $4,705,000 in the corresponding period in 2001. The loss in 2002 was attributable primarily to decreases in the estimated future value of existing commodity swaps and collars as a result of increases in commodity futures prices. The gain in 2001 was due primarily to

increases in the estimated future value of oil and gas collars that were in place at that time due to decreases in commodity futures prices. These 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.

Current income tax expense was $315,000 in the nine months ended September 30, 2002 compared to $2,721,000 in the corresponding period of 2001. The deferred income tax expense was $8,023,000 in the nine months ended September 30, 2002 compared to $83,582,000 in the corresponding period of 2001. The decreases were due primarily to lower pre-tax profitability as a result of lower oil and gas revenue.

The extraordinary loss on extinguishment of debt of $3,103,000 (net of tax) in the nine months ended September 30, 2002 resulted from the repurchase of $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value, the repurchase of $19,710,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 108% of par value and the redemption of $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value. The extraordinary loss on extinguishment of debt of $2,417,000 (net of tax) in the nine months ended September 30, 2001 resulted from the repurchase of $65,260,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103% of par value.

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 issuance of debt and equity securities, when market conditions permit, and through the use of bank credit facilities and cash provided by operating activities. 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 continue to 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.

Termination of Interest Rate Swaps. On September 30, 2002, Forest terminated two interest rate swaps related to the 8% Senior Notes due 2008 and 2011. In October 2002, we received net proceeds of approximately $20,858,000 related to this termination, which was used for general corporate purposes. From inception to September 30, 2002, the effective rates on Forest's 8% Senior Notes due 2008 and 2011 were reduced to 7.18% and 7.32%, respectively, as a result of the original swaps. From October 1, 2002, to maturity, the effective rates on the 8% Senior Notes due 2008 and 2011 will be reduced to 7.24% and 7.66%, respectively, as a result of liquidation of those swaps.

Securities Issued. In the second quarter of 2002, we issued $150,000,000 principal amount of 7³/4% Senior Notes due 2014 at 98.09% of par for proceeds of $146,846,000 (net of related issuance costs). A portion of the net proceeds was used to repay all outstanding indebtedness under our U.S. credit facility and to repurchase $15,110,000 principal amount of our 10¹/2% Senior Subordinated Notes. The remaining net proceeds were used for general corporate purposes.

Securities Redeemed and Repurchased. In the nine months ended September 30, 2002, we repurchased $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value; $19,710,000 principal amount of our 10¹/2% Senior Subordinated Notes at approximately 108.0% of par value; and redeemed $57,948,000 outstanding principal amount of 8³/4% Senior Subordinated Notes at 104.375% of par value. We also purchased 21,894 shares of our common stock at an average price of $24.68 per share pursuant to our odd-lot stock buyback program.

Bank Credit Facilities. We have credit facilities totalling $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. 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. As of September 30, 2002, under the most restrictive of these covenants and financial tests, our remaining, unused borrowing amount under the credit facilities was estimated to be approximately $120,000,000, in addition to amounts outstanding. If the rating on our bank credit facilities is downgraded, the available borrowing amount under the credit facilities would be determined by a borrowing base subject to semi-annual re-determination. If Forest were subject to the borrowing base provisions, the borrowing amount would be determined based upon the value of certain oil and gas properties. As a result, the available borrowing amount could be increased or be reduced under the borrowing base tests.

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.

At September 30, 2002 there were $35,000,000 of outstanding borrowings under the U.S. credit facility and $46,872,000 under the Canadian Forest credit facility. At November 1, 2002, the outstanding borrowings under the U.S. credit facility were $75,000,000 and there were no outstanding borrowings under the Canadian credit facility. At November 1, 2002, we had used the credit facilities for letters of credit in the amount of $4,538,000 U.S. and $1,386,000 CDN.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. It is normal for Forest to report working capital deficits at the end of a period. Such working capital deficits are principally the result of accounts payable for capitalized 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 a working capital deficit of approximately $12,655,000 at September 30, 2002 compared to a deficit of approximately $38,333,000 at December 31, 2001. The decrease in the deficit was due primarily to a decrease in accounts payable attributable to lower capital spending, offset partially by a decrease in the fair value of derivative instruments and a decrease in accounts receivable attributable to lower product prices.

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 $130,729,000 in the first nine months ended September 30, 2002 compared to $409,287,000 in the same period in 2001. The decrease was due primarily to lower oil and gas revenue as a result of lower product prices and decreased production. Cash used for investing activities in the first nine months ended September 30, 2002 was $256,089,000 compared to $402,043,000 in the same period in 2001. The decrease was due primarily to decreased exploration and development activities. Net cash provided by financing activities in the nine months ended September 30, 2002 was $125,345,000 compared to cash used of $16,416,000 in the same period in 2001. The 2002 period included net borrowings of bank debt of $62,882,000, and net proceeds of $146,846,000 from the issuance of the 7³/4% Notes, offset by repurchases of the 10¹/2% Notes of $21,283,000 and repurchases and redemptions of the 8³/4% Notes of $66,248,000. The 2001 period included net repayments of bank debt of $100,252,000, cash used for repurchases of the 8³/4% Notes of $67,003,000, cash used for the purchase of treasury stock of $55,720,000 and net cash inflows of $199,500,000 from the issuance of the 8% Notes.

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

		Nine Months Ended September 30,
		2002		2001
		(In Thousands)
Property acquisition costs:
	Proved properties	$	2,801	9
	Undeveloped properties		—	(273	)

			2,801	(264	)
Exploration costs:
	Direct costs		70,250	176,095
	Overhead capitalized		9,675	6,738

			79,925	182,833
Development costs:
	Direct costs		162,366	237,661
	Overhead capitalized		9,473	8,104

			171,839	245,765

Total capital expenditures		$	254,565	428,334

Forest's anticipated expenditures for exploration and development in the fourth quarter of 2002 are estimated to range from $85,000,000 to $95,000,000. We intend to meet our 2002 capital expenditure financing requirements using cash flows generated by operations, sales of non-strategic assets and 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.

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

Impact of Recently Issued Accounting Pronouncements.

Statement 142, Goodwill and Other Intangible Assets (SFAS No. 142), requires that goodwill no longer be amortized but tested for impairment at least annually. Other intangible assets are to be amortized over their useful lives and reviewed for impairment. An intangible asset with an indefinite useful life will not be amortized until its useful life becomes determinable. The effective date of this statement was January 1, 2002. Adoption of this statement had no impact on our historical financial statements.

Statement 143, Accounting for Asset Retirement Obligations (SFAS No. 143) requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. We will be required to adopt SFAS No. 143 effective January 1, 2003 using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. We currently record estimated costs of dismantlement, removal, site reclamation, and similar activities as part of our provision for depreciation and depletion for oil and gas properties without recording a separate liability for such amounts. We have not completed our assessment of the impact of SFAS No. 143 on our financial condition and results of operations.

Statement 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144) retains the fundamental provisions of SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of (SFAS No. 121) for recognizing and measuring impairment losses while resolving significant implementation issues associated with SFAS No. 121. SFAS No. 144 also expands the basic provisions of Accounting Principles Board (APB) Opinion No. 30 (APB 30), Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, regarding presentation of discontinued operations in the income statement. The scope for reporting a discontinued operation has been expanded to include a "component" of an entity. A component comprises operations and cash flows that can be clearly distinguished from the rest of the entity. A component could be a segment, a reporting unit, a consolidated subsidiary, or an asset group.

Forest adopted SFAS No. 144 as of January 1, 2002. Because we have elected the full-cost method of accounting for oil and gas exploration and development activities, the impairment provisions of SFAS No. 144 do not apply to our oil and gas assets, which are instead subject to ceiling limitations. For our non-oil and gas assets, the method of impairment assessment is largely unchanged from SFAS No. 121. The adoption of SFAS No. 144 had no impact on our financial statements.

Statement 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections(SFAS No. 145) was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in APB 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. We expect adoption of this statement to result in the reclassification of losses on extinguishment of debt for all periods from extraordinary to other income and expense.

Statement 146, Accounting for Exit or Disposal Activities (SFAS No. 146), was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS No. 146 will be effective for Forest in January 2003. We are evaluating the impact of SFAS No. 146.

EITF Issue No. 02-03, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, and No. 00-17, Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10, was issued in June 2002. EITF Issue No. 02-03 addresses certain issues related to energy trading activities, including (a) gross versus net presentation in the income statement, (b) whether the initial fair value of an energy trading contract can be other than the price at which it was exchanged, and (c) accounting for inventory utilized in energy trading activities. Certain provisions of EITF Issue No. 02-03 relating to gross versus net presentations were effective for Forest in the third quarter of 2002 and, accordingly, we have presented our revenue and expenses from marketing and processing activities as a net revenue line item in the accompanying statements of operations. The remaining provisions will be effective on January 1, 2003.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

We produce and sell natural gas, crude oil and natural gas liquids for our own account in the United States and Canada and, through ProMark, our marketing subsidiary, we market natural gas for third parties in Canada. As a result, our financial results are affected when prices for these commodities fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in prices, we enter into long-term contracts for a portion of our production and use a hedging strategy. Under our hedging strategy, Forest enters into commodity swaps, collars and other financial instruments. All of our commodity swaps and collar agreements and a portion of our basis swaps in place at September 30, 2002 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 34% and 49% of our consolidated production, on an equivalent basis, during the third quarter of 2002 and 2001, respectively.

Long-Term Sales Contracts. A significant portion of Canadian Forest's natural gas production is sold through the ProMark Netback Pool which is operated by ProMark on behalf of Canadian Forest. At September 30, 2002, 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	Sales Price per MCF
Remainder of 2002	1.4	$	2.78 CDN
2003	5.5	$	2.83 CDN
2004	5.5	$	2.94 CDN
2005	5.5	$	3.05 CDN
2006	5.5	$	3.17 CDN
2007	5.5	$	3.29 CDN
2008	5.5	$	3.42 CDN
2009	3.6	$	4.14 CDN
2010	1.7	$	6.40 CDN
2011	0.8	$	6.75 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 2001, Canadian Forest supplied 39% of the total netback pool sales quantity. In the 2002/2003 contract year, it is estimated that Canadian Forest will supply approximately 42% of the netback pool quantity. We currently expect that Canadian Forest's pro rata obligations as a gas producer will continue to change and may increase as production dedicated to the netback pool declines and producers' supply contracts expire and may decrease as gas sales contracts expire.

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 does not believe that such shortfalls will be significant.

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 2002	.16	$	3.68 CDN
2003	.62	$	3.82 CDN
2004	.62	$	3.96 CDN
2005	.62	$	4.11 CDN
2006	.52	$	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 if the index price is lower. If the index price is higher, Forest pays the difference. By entering into swap agreements we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of September 30, 2002, Forest had entered into the following swaps:

	Natural Gas			Oil (NYMEX WTI)
	BBTUs per Day	Average Hedged Price per MMBTU		Barrels per Day	Average Hedged Price per BBL
Fourth Quarter 2002	81.6	$	3.547	10,000	$	22.223
First Quarter 2003	25.0	$	3.624	6,000	$	23.273
Second Quarter 2003	40.0	$	3.960	4,500	$	22.550
Third Quarter 2003	40.0	$	3.960	4,000	$	22.009
Fourth Quarter 2003	13.5	$	3.960	4,000	$	21.928
First Quarter 2004	—	$	—	3,000	$	23.125
Second Quarter 2004	—	$	—	1,000	$	23.325

Between October 1, 2002 and November 8, 2002, we entered into the following swaps:

	Natural Gas			Oil (NYMEX WTI)
	BBTUs per Day	Average Hedged Price per MMBTU		Barrels per Day	Average Hedged Price per BBL
First Quarter 2003	10.0	$	4.124	2,000	$	24.673
Second Quarter 2003	10.0	$	4.124	2,000	$	24.673
Third Quarter 2003	10.0	$	4.124	2,000	$	24.673
Fourth Quarter 2003	10.0	$	4.124	2,000	$	24.673
First Quarter 2004	—		—	2,000	$	22.980
Second Quarter 2004	10.0	$	3.800	2,000	$	22.980
Third Quarter 2004	10.0	$	3.800	2,000	$	22.980
Fourth Quarter 2004	3.4	$	3.800	2,000	$	22.980

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 if the index price is below the floor price, and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. 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 if prices increase above the ceiling price. We enter into collars during periods of volatile commodity prices in order to protect against a significant decline in prices in exchange for forgoing the benefit of price increases in excess of the ceiling price on the hedged production. As of September 30, 2002, Forest had entered into the following gas and oil collars:

	Natural Gas
	BBTUs Per Day	Average Floor Price per MMBTU		Average Ceiling Price per MMBTU
Fourth Quarter 2002	46.5	$	3.429	$	5.038
First Quarter 2003	80.0	$	3.438	$	5.103
Second Quarter 2003	20.0	$	3.250	$	4.075
Third Quarter 2003	20.0	$	3.250	$	4.075
Fourth Quarter 2003	20.0	$	3.250	$	4.887
First Quarter 2004	20.0	$	3.250	$	5.300

	Oil (NYMEX WTI)
	Barrels Per Day	Average Floor Price per BBL		Average Ceiling Price per BBL
First Quarter 2003	3,000	$	22.00	$	25.417
Second Quarter 2003	3,000	$	22.00	$	25.417
Third Quarter 2003	3,000	$	22.00	$	25.417
Fourth Quarter 2003	3,000	$	22.00	$	25.417
First Quarter 2004	2,000	$	22.00	$	24.075

Between October 1, 2002 and November 8, 2002, we entered into the following collars.

	Natural Gas
	BBTUs Per Day	Average Floor Price per MMBTU		Average Ceiling Price per MMBTU
Fourth Quarter 2003	6.6	$	3.710	$	5.000
First Quarter 2004	10.0	$	3.710	$	5.000

We also use basis swaps to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. As of September 30, 2002, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 109.9 BBTUs per day for the remainder of 2002 and weighted average volumes of 38.5 BBTUs per day for 2003. Between October 1, 2002 and November 8, 2002, we did not enter into any basis swaps designated as cash flow hedges.

The fair value of our cash flow hedges based on the futures prices quoted on September 30, 2002 was a loss of approximately $21,253,000.

Trading Activities. Profits or losses generated by the purchase and sale of third parties' gas are based on the spread between the prices of natural gas purchased and sold. ProMark does not trade natural gas to hold as a speculative or open position. All transactions represent physical volumes and are immediately offset, thereby fixing the margin and eliminating the market risk on the related agreements. At September 30, 2002, ProMark's trading operations had the following purchase and sales commitments in place for 2002 and 2003:

	Natural Gas
	BCF	Purchase Price per MCF		Sales Price per MCF
October-December, 2002	.573	$	4.90 CDN	$	4.93 CDN
2003	.886	$	4.96 CDN	$	4.99 CDN

As of September 30, 2002, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 5.1 BBTUs per day for the remainder of 2002. Between October 1, 2002 and November 8, 2002 we entered into additional basis swaps not designated as cash flow hedges covering weighted average volumes of 16.5 BBTUs per day for the remainder of 2002 and weighted average volumes of 20.0 BBTUs per day for the first quarter of 2003.

The fair value of our derivative instruments not designated as cash flow or fair value hedges based on the futures prices quoted on September 30, 2002 was a loss of approximately $699,000.

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.

Interest Rate Risk

The following table presents principal amounts and related average fixed interest rates by year of maturity for Forest's debt obligations at September 30, 2002:

		2002			2006		2008		2011		2014		Total		Fair Value
		(Dollar Amounts in Thousands)
Bank credit facilities:
	Variable rate	$	81,872		—		—		—		—		81,872		81,872
	Average interest rate		3.77	%	—		—		—		—		3.77	%
Long-term debt:
	Fixed rate	$	—		68,470		265,000		160,000		150,000		643,470		660,953
	Average interest rate		—		10.5	%	8.00	%	8.00	%	7.75	%	8.21	%

In connection with the issuance of $150,000,000 principal amount of 7³/4% Senior Notes due 2014, we entered into an interest rate swap under which we will pay a variable rate based on the three month London Interbank Offered Rate (LIBOR) plus 153 basis points in exchange for a fixed rate of 7³/4% on $150,000,000 principal amount over the term of the note issue. As of September 30, 2002 the fair value of this interest rate swap, which is accounted for as a fair value hedge, was a gain of approximately $17,211,000.

Item 4. CONTROLS AND PROCEDURES.

(a) Evaluation of disclosure controls and procedures. Within 90 days before the filing of this Report, Robert S. Boswell, our Chief Executive Officer, and David H. Keyte, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. 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.

(b) Changes in internal controls. There have been no significant changes in our internal controls or in other factors that could significantly affect our internal controls subsequent to their evaluation, nor have there been any corrective actions with regard to significant deficiencies or material weaknesses.

PART II. OTHER INFORMATION

Item 5. OTHER INFORMATION

From time to time Forest is subject to legal challenges in connection with governmental regulatory permits, consents and approvals necessary to conduct its normal exploration, development and production operations.

On May 1, 2002, the State of Alaska approved the development and production phase of the Company's Redoubt Shoal oil and gas project (the Production Project). On May 30, 2002, 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 court entered a briefing schedule, which Forest anticipates will extend into the first quarter of 2003. Separately, the non-governmental third party filed a motion in September 2002 asking the Court to stay Forest's development and production phase operations during the pendency of the briefing process and through the court's final determination regarding the challenge. Forest filed an opposition to this motion on September 30, 2002, and the court has not yet ruled on it. While Forest intends to vigorously contest the challenge to the Production Project, the outcome of the litigation is inherently difficult to predict with any certainty. At this time, however, Forest believes that any potential delays in the Production Project resulting from this challenge will not have a material adverse impact on Forest's financial condition and results of operations.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a): Exhibits.
10.1: Forest Oil Corporation Pension Trust Agreement dated as of January 1, 2002, by and between Forest Oil Corporation and the trustees named therein, or their successors.
10.2: First Amendment to Retirement Savings Plan of Forest Oil Corporation dated April 12, 2002.
(b): Reports on Form 8-K.

The Company filed the following current reports on Form 8-K during the third quarter ending September 30, 2002.

Date of Report		Item Reported		Financial Statements Filed
August 7, 2002		Item 9		None
August 14, 2002		Item 9		None

SIGNATURES

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

	Forest Oil Corporation (Registrant)
November 14, 2002	By:	/s/ DAVID H. KEYTE David H. Keyte Executive Vice President and Chief Financial Officer (Principal Financial Officer)
	By:	/s/ JOAN C. SONNEN Joan C. Sonnen Vice President—Controller and Chief Accounting Officer (Principal Accounting Officer)

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, Robert S. Boswell, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Forest Oil Corporation;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c): presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 14, 2002

/s/ ROBERT S. BOSWELL

Robert S. Boswell
Chairman and Chief Executive Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, David H. Keyte, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Forest Oil Corporation;

2.

3.

4.

a): designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b): evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c): presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

a): all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b): any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.: The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 14, 2002

/s/ DAVID H. KEYTE

David H. Keyte
Executive Vice President and
Chief Financial Officer