FOREST OIL CORP - 10-Q Quarterly Report

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

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

Title of Class of Common Stock		Number of Shares Outstanding July 31, 2002
Common Stock, Par Value $.10 Per Share		46,971,869

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

Part I—FINANCIAL INFORMATION
	Item 1—Financial Statements
	Condensed Consolidated Balance Sheets
	Condensed Consolidated Statements of Production and Operations
	Condensed Consolidated Statements of Cash Flows
	Notes to Condensed Consolidated Financial Statements
	Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations
	Item 3—Quantitative and Qualitative Disclosures about Market Risk
Part II—OTHER INFORMATION
	Item 4—Submission of Matters to a Vote of Security Holders
	Item 5—Other Information
	Item 6—Exhibits and Reports on Form 8-K
Signatures

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

			June 30, 2002			December 31, 2001
			(In Thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	20,227		8,387
	Accounts receivable			107,011		134,090
	Derivative instruments			11,469		31,632
	Current deferred tax asset			4,257		—
	Other current assets			18,863		27,856

		Total current assets		161,827		201,965
Net property and equipment, at cost				1,620,903		1,516,900
Deferred income taxes				41,087		43,930
Goodwill and other intangible assets, net				13,622		13,263
Other assets				25,979		20,311

			$	1,863,418		1,796,369

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	165,422		209,163
	Accrued interest			7,025		7,364
	Derivative instruments			10,362		1,548
	Current portion of deferred income tax liability			—		11,154
	Other current liabilities			7,742		11,069

		Total current liabilities		190,551		240,298
Bank credit facilities				—		19,000
Other long-term debt				712,170		575,178
Other liabilities				22,817		21,524
Deferred income taxes				18,938		16,426
Shareholders' equity:
	Common stock			4,907		4,883
	Capital surplus			1,148,512		1,145,282
	Accumulated deficit			(156,650	)	(165,824	)
	Accumulated other comprehensive loss			(21,291	)	(4,147	)
	Treasury stock, at cost			(56,536	)	(56,251	)

		Total shareholders' equity		918,942		923,943

			$	1,863,418		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					Six Months Ended
						June 30, 2002			June 30, 2001		June 30, 2002		June 30, 2001
						(In Thousands Except Production and Per Share Amounts)
PRODUCTION
	Natural gas (MMCF)						23,535		28,739		45,742		56,500

	Oil, condensate and natural gas liquids (thousands of barrels)						2,408		2,410		4,346		5,061

STATEMENTS OF CONSOLIDATED OPERATIONS
	Revenue:
		Marketing and processing				$	71,962		88,373		125,349		198,570
		Oil and gas sales:
			Gas				73,797		128,953		133,229		315,608
			Oil, condensate and natural gas liquids				51,849		58,273		88,213		129,369

				Total oil and gas sales			125,646		187,226		221,442		444,977

					Total revenue		197,608		275,599		346,791		643,547
	Operating expenses:
		Marketing and processing					70,721		87,670		123,471		196,947
		Oil and gas production					40,375		44,204		77,586		84,171
		General and administrative					10,062		7,076		18,219		13,282
		Merger and seismic licensing expense					—		3,998		—		4,498
		Depreciation and depletion					47,588		57,315		87,774		113,940

					Total operating expenses		168,746		200,263		307,050		412,838

Earnings from operations							28,862		75,336		39,741		230,709
Other income and expense:
	Other (income) expense, net						(24	)	11		719		1,183
	Interest expense						12,568		12,029		24,713		25,493
	Translation loss (gain) on subordinated debt						(2,970	)	(7,395	)	(2,821	)	2,301
	Realized gain on derivative instruments, net						(162	)	—		(246	)	—
	Unrealized (gain) loss on derivative instruments, net						416		(8,365	)	616		(13,586	)

					Total other income and expense		9,828		(3,720	)	22,981		15,391

Earnings before income taxes and extraordinary item							19,034		79,056		16,760		215,318
Income tax expense (benefit):
	Current						143		(13,740	)	254		2,236
	Deferred						6,835		40,617		6,003		79,618

							6,978		26,877		6,257		81,854

Net earnings before extraordinary item							12,056		52,179		10,503		133,464
Extraordinary loss on extinguishment of debt							(1,098	)	(1,590	)	(1,329	)	(1,590	)

Net earnings						$	10,958		50,589		9,174		131,874

Weighted average number of common shares outstanding:
	Basic						46,925		48,405		46,880		48,400
	Diluted						48,485		50,236		48,293		50,388
Basic earnings per common share:
	Earnings attributable to common stock before extraordinary item					$	.25		1.08		.23		2.75
	Extraordinary loss on extinguishment of debt						(.02	)	(.03	)	(.03	)	(.03	)

	Earnings attributable to common stock					$	.23		1.05		.20		2.72

Diluted earnings per common share:
	Earnings attributable to common stock before extraordinary item					$	.25		1.04		.22		2.65
	Extraordinary loss on extinguishment of debt						(.02	)	(.03	)	(.03	)	(.03	)

	Earnings attributable to common stock					$	.23		1.01		.19		2.62

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Six Months Ended June 30,
				2002			2001
				(In Thousands)
Cash flows from operating activities:
	Net earnings before extraordinary item			$	10,503		133,464
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation and depletion			87,774		113,940
		Amortization of deferred debt costs			1,041		862
		Translation (gain) loss on subordinated debt			(2,821	)	2,301
		Unrealized loss (gain) on derivative instruments, net			616		(13,586	)
		Deferred income tax expense			6,003		79,618
		Other, net			(1,772	)	(61	)
		Decrease in accounts receivable			28,956		13,265
		Decrease (increase) in other current assets			9,013		(21,995	)
		(Decrease) increase in accounts payable			(47,674	)	25,216
		Decrease in accrued interest and other current liabilities			(1,447	)	(38,985	)

			Net cash provided by operating activities		90,192		294,039
Cash flows from investing activities:
	Capital expenditures for property and equipment				(181,308	)	(253,315	)
	Proceeds from sales of assets				1,632		22,643
	Increase in other assets, net				(2,296	)	(771	)

			Net cash used by investing activities		(181,972	)	(231,443	)
Cash flows from financing activities:
	Proceeds from bank borrowings				177,889		444,628
	Repayments of bank borrowings				(196,878	)	(669,238	)
	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				(5,435	)	(39,934	)
	Proceeds from exercise of options and warrants				3,573		7,938
	Purchase of treasury stock				(560	)	(12,567	)
	Increase (decrease) in other liabilities, net				(528	)	257

			Net cash provided (used) by financing activities		103,624		(69,416	)
Effect of exchange rate changes on cash					(4	)	(202	)

Net increase (decrease) in cash and cash equivalents					11,840		(7,022	)
Cash and cash equivalents at beginning of period					8,387		14,003

Cash and cash equivalents at end of period				$	20,227		6,981

Cash paid during the period for:
	Interest			$	24,002		21,234
	Income taxes			$	1,362		10,123

See accompanying notes to condensed consolidated financial statements.

FOREST OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

THREE AND SIX MONTHS ENDED JUNE 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 June 30, 2002 and the results of operations for the three and six months ended June 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 abandonment 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 June 30,			Six Months Ended June 30,
		2002(1)		2001(2)	2002(3)	2001(4)
		(In Thousands Except Per Share Amounts)
Net earnings before extraordinary item		$	12,056	52,179	10,503	133,464

Weighted average common shares outstanding during the period			46,925	48,405	46,880	48,400
	Add dilutive effects of employee stock options		657	854	568	1,002
	Add dilutive effects of warrants		903	977	845	986

Weighted average common shares outstanding including the effects of dilutive securities			48,485	50,236	48,293	50,388

Basic earnings per share before extraordinary item		$	.25	1.08	.23	2.75

Diluted earnings per share before extraordinary item		$	.25	1.04	.22	2.65

(1): At June 30, 2002, options to purchase 426,250 shares of common stock at prices ranging from $29.90 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 2011.
(2): At June 30, 2001, options to purchase 268,250 shares of common stock at prices ranging from $32.57 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 through 2011.
(3): At June 30, 2002, options to purchase 1,630,800 shares of common stock at prices ranging from $28.33 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.
(4): At June 30, 2001, options to purchase 259,750 shares of common stock at prices ranging from $32.80 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 six months ended June 30, 2002 and 2001 are foreign currency gains and losses related to the translation of the assets and liabilities of the Company's Canadian operations; unrealized gains (losses) related to the change in fair value of derivative instruments designated as cash flow hedges; and unrealized gains (losses) related to the change in fair value of securities available for sale.

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

		Three Months Ended June 30,					Six Months Ended June 30,
		2002			2001		2002		2001
		(In Thousands)
Net earnings		$	10,958		50,589		9,174		131,874
Other comprehensive income (loss):
	Foreign currency translation gains		9,402		1,772		9,091		315
	Unrealized gain (loss) on derivative instruments, net		31		23,640		(26,208	)	1,138
	Unrealized (loss) gain on securities available for sale		(42	)	(203	)	(27	)	109

Total comprehensive earnings (loss)		$	20,349		75,798		(7,970	)	133,436

(3) NET PROPERTY AND EQUIPMENT

Components of net property and equipment are as follows:

	June 30, 2002			December 31, 2001
	(In Thousands)
Oil and gas properties	$	3,606,133		3,408,317
Buildings, transportation and other equipment		25,405		23,137

		3,631,538		3,431,454
Less accumulated depreciation, depletion and valuation allowance		(2,010,635	)	(1,914,554	)

	$	1,620,903		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:

	June 30, 2002			December 31, 2001
	(In Thousands)
Goodwill	$	15,093		14,394
Gas marketing contracts		13,168		12,558

		28,261		26,952
Less accumulated amortization		(14,639	)	(13,689	)

	$	13,622		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. Gas marketing contracts are amortized based on estimated revenues over the life of the contracts.

The following table reflects the effect on net earnings and earnings per common share of the adoption of SFAS No. 142 for the three and six months ended June 30, 2001:

		Three Months Ended June 30, 2001		Six Months Ended June 30, 2001
		(In Thousands)
Net earnings		$	50,589	131,874
Add back: Goodwill amortization, net of tax			112	215

Adjusted net earnings		$	50,701	132,089

Basic earnings per common share:
	Earnings	$	1.05	2.72
	Add back: Goodwill amortization, net of tax		—	.01

	Adjusted earnings	$	1.05	2.73

Diluted earnings per common share:
	Earnings	$	1.01	2.62
	Add back: Goodwill amortization, net of tax		—	—

	Adjusted earnings	$	1.01	2.62

(5) LONG-TERM DEBT

Components of long-term debt are as follows:

	June 30, 2002(1)		December 31, 2001
	(In Thousands)
U.S. Credit Facility	$	—	19,000
8% Senior Notes Due 2008		270,933	264,366
8% Senior Notes Due 2011		163,224	160,000
7³/4% Senior Notes Due 2014		152,015	—
10¹/2% Senior Subordinated Notes Due 2006		68,054	87,569
8³/4% Senior Subordinated Notes Due 2007		57,944	63,243

	$	712,170	594,178

(1): Amounts shown have been increased to reflect changes in the fair market value of the underlying debt recorded in connection with unrealized gains relating to interest rate swaps accounted for as fair value hedges as follows:

	June 30, 2002
	(In Thousands)
8% Senior Notes Due 2008	$	6,517
8% Senior Notes Due 2011		3,225
7³/4% Senior Notes Due 2014		4,840

	$	14,582

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).

The 8³/4% Senior Subordinated Notes (the 8³/4% Notes) were issued by Forest's wholly owned subsidiary, Canadian Forest Oil Ltd. (Canadian Forest), and are guaranteed on a senior subordinated basis by Forest. Forest is required to recognize foreign currency translation gains or losses related to the 8³/4% Notes because the debt is 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 second quarter and first six months of 2002, Forest reported noncash translation (gains) losses related to the 8³/4% Notes of approximately $(2,970,000) and $(2,821,000), respectively, compared to $(7,395,000) and $2,301,000 in the second quarter and first six months of 2001.

(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 designated and qualifies as a cash flow hedge or a fair value hedge. For derivatives designated as 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 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. For fair value hedges, 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.

Interest Rate Swaps:

The Company has entered into interest rate swaps under which the fixed rate on a specified principal amount of notes will be exchanged for a variable rate based on LIBOR plus specified basis points over the term of the note issue. At June 30, 2002, the Company had the following interest rate swaps in place:

						Variable Rate
Note Issue	Principal Amount of Notes		Principal Amount Related to Swap		Fixed Rate	LIBOR	Basis Points
8% Senior Notes due 2008	$	265,000,000	$	100,000,000	8%	6 month	195.00
8% Senior Notes due 2011	$	160,000,000	$	50,000,000	8%	6 month	181.25
7³/4% Senior Notes due 2014	$	150,000,000	$	150,000,000	7³/4%	3 month	153.00

The interest rate swaps are fair value hedges and, accordingly, unrecognized gains (losses) related to such instruments are offset against unrecognized gains (losses) in the fair value of the related debt instruments in the statement of operations. The fair value of interest rate swaps is recorded as a derivative asset (liability) and the corresponding fair value of the related debt instruments is recorded as an increase (decrease) in the related debt balance. At June 30, 2002, with respect to the interest rate swaps, the Company had a current derivative asset of $11,055,000, a long-term derivative asset of $4,322,000, a long-term derivative liability of $795,000, and an increase in the fair value of the related notes of $14,582,000.

For the second quarter and first six months of 2002, the Company recognized net gains of $2,703,000 and $4,260,000, respectively, under these agreements, which were recorded as reductions of interest expense.

Energy 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 energy swaps and collar agreements and a portion of its basis swaps in place at June 30, 2002 have been designated as cash flow hedges. At June 30, 2002 the Company had a current derivative asset of $414,000, a derivative liability of approximately $11,807,000 (of which $10,362,000 was classified as current), a deferred tax asset of $4,330,000 (of which $3,780,000 was classified as current) and accumulated other comprehensive loss of approximately $6,915,000.

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

		Three Months Ended June 30,				Six Months Ended June 30,
		2002		2001		2002		2001
		(In Thousands)
Derivatives designated as cash flow hedges		$	3,802	1,767		(8,610	)	10,715
Derivatives not designated as cash flow hedges			254	(8,365	)	370		(13,586	)

	Total (gain) loss	$	4,056	(6,598	)	(8,240	)	(2,871	)

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 third-party index if the index price is lower. If the index price is higher, Forest pays the difference. By entering into swap agreements the Company effectively fixes the price that it will receive in the future for the hedged production. Forest's current swaps are settled in cash on a monthly basis. As of June 30, 2002, Forest had the following swaps in place:

	Natural Gas			Oil
	BBTUs per Day	Average Hedged Price per MMBTU		Barrels per Day	Average Hedged Price per Barrel
Third Quarter 2002	75.0	$	3.37	10,000	$	22.44
Fourth Quarter 2002	41.8	$	3.47	10,000	$	22.22
First Quarter 2003	25.0	$	3.62	5,500	$	23.09
Second Quarter 2003	—		—	3,500	$	21.74
Third Quarter 2003	—		—	3,500	$	21.67
Fourth Quarter 2003	—		—	3,000	$	21.26
First Quarter 2004	—		—	2,000	$	22.90

The Company also uses basis swaps in connection with natural gas swaps to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. At June 30, 2002 there were basis swaps designated as cash flow hedges in place with weighted average volumes of 40.1 BBTUs per day for the remainder of 2002 and weighted average volumes of 6.16 BBTUs per day for 2003. At June 30, 2002 there were basis swaps not designated as cash flow hedges in place with weighted average volumes of 10.0 BBTUs per day for the remainder of 2002.

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 June 30, 2002, the Company had the following collars in place:

	Natural Gas
	BBTUs per Day	Average Floor Price per MMBTU		Average Ceiling Price per MMBTU
Fourth Quarter 2002	13.3	$	3.25	$	5.13
First Quarter 2003	20.0	$	3.25	$	5.13
Second Quarter 2003	20.0	$	3.25	$	4.08
Third Quarter 2003	20.0	$	3.25	$	4.08
Fourth Quarter 2003	20.0	$	3.25	$	4.89
First Quarter 2004	20.0	$	3.25	$	5.30

	Oil
	Barrels per Day	Average Floor Price per BBL		Average Ceiling Price per BBL
First Quarter 2003	3,000	$	22.00	$	25.42
Second Quarter 2003	3,000	$	22.00	$	25.42
Third Quarter 2003	3,000	$	22.00	$	25.42
Fourth Quarter 2003	3,000	$	22.00	$	25.42
First Quarter 2004	2,000	$	22.00	$	24.08

(7) 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: oil and gas operations in the Gulf of Mexico (GOM) 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 segment and the geographical location of each segment. The segment data presented below was prepared on the same basis as Forest's consolidated financial statements.

Three Months Ended June 30, 2002

		Oil and Gas Operations
		Oil and Gas Operations								Marketing and Processing Canada
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Marketing and Processing Canada	Total Company
		(In Thousands)
Revenue		$	60,513	13,611	17,576	21,556	113,256	13,098	126,354	71,254	197,608
Expenses:
	Marketing and processing		—	246	—	—	246	—	246	70,475	70,721
	Oil and gas production		15,795	5,356	5,010	10,306	36,467	3,908	40,375	—	40,375
	General and administrative		3,728	1,080	1,559	2,086	8,453	1,229	9,682	380	10,062
	Depletion		27,790	3,735	4,572	5,649	41,746	4,781	46,527	145	46,672

Earnings from operations		$	13,200	3,194	6,435	3,515	26,344	3,180	29,524	254	29,778

Capital expenditures		$	28,632	4,419	12,418	45,072	90,541	4,154	94,695	—	94,695

Property and equipment, net		$	489,744	291,597	224,976	283,785	1,290,102	245,044	1,535,146	—	1,535,146

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	29,778
Administrative asset depreciation		(916	)
Other income, net		24
Interest expense		(12,568	)
Translation gain on subordinated debt		2,970
Realized gain on derivative instruments, net		162
Unrealized loss on derivative instruments, net		(416	)

Earnings before income taxes and extraordinary item	$	19,034

CAPITAL EXPENDITURES:
Reportable segments	$	94,695
International interests		4,662
Administrative assets and other		1,167

Total capital expenditures	$	100,524

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,535,146
International interests		79,118
Administrative assets, net and other		6,639

Total property and equipment, net	$	1,620,903

Six Months Ended June 30, 2002

		Oil and Gas Operations
		Oil and Gas Operations								Marketing and Processing Canada
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Marketing and Processing Canada	Total Company
		(In Thousands)
Revenue		$	109,433	24,905	28,511	34,651	197,500	24,894	222,394	124,397	346,791
Expenses:
	Marketing and processing		—	585	—	—	585	—	585	122,886	123,471
	Oil and gas production		30,898	10,800	9,949	19,171	70,818	6,768	77,586	—	77,586
	General and administrative		6,599	2,199	2,970	3,397	15,165	2,321	17,486	733	18,219
	Depletion		51,185	7,906	8,158	8,578	75,827	9,930	85,757	288	86,045

Earnings from operations		$	20,751	3,415	7,434	3,505	35,105	5,875	40,980	490	41,470

Capital expenditures		$	45,548	14,301	23,711	69,399	152,959	13,156	166,115	—	166,115

Property and equipment, net		$	489,744	291,597	224,976	283,785	1,290,102	245,044	1,535,146	—	1,535,146

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	41,470
Administrative asset depreciation		(1,729	)
Other expense, net		(719	)
Interest expense		(24,713	)
Translation gain on subordinated debt		2,821
Realized gain on derivative instruments, net		246
Unrealized loss on derivative instruments, net		(616	)

Earnings before income taxes and extraordinary item	$	16,760

CAPITAL EXPENDITURES:
Reportable segments	$	166,115
International interests		13,079
Administrative assets and other		2,114

Total capital expenditures	$	181,308

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,535,146
International interests		79,118
Administrative assets, net and other		6,639

Total property and equipment, net	$	1,620,903

(7) BUSINESS AND GEOGRAPHICAL SEGMENTS (Continued)

Three Months Ended June 30, 2001

		Oil and Gas Operations
		Oil and Gas Operations								Marketing and Processing Canada
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Marketing and Processing Canada	Total Company
		(In Thousands)
Revenue		$	117,622	16,011	22,781	15,168	171,582	15,819	187,401	88,198	275,599
Expenses:
	Marketing and processing		—	543	—	—	543	—	543	87,127	87,670
	Oil and gas production		23,470	3,726	5,992	7,409	40,597	3,607	44,204	—	44,204
	General and administrative		3,106	659	1,016	1,013	5,794	943	6,737	339	7,076
	Depletion		41,050	3,081	3,681	3,509	51,321	4,567	55,888	471	56,359

Earnings from operations		$	49,996	8,002	12,092	3,237	73,327	6,702	80,029	261	80,290

Capital expenditures		$	80,319	9,058	6,399	17,207	112,983	13,117	126,100	—	126,100

Property and equipment, net		$	562,705	261,327	191,278	160,832	1,176,142	221,617	1,397,759	—	1,397,759

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	80,290
Administrative asset depreciation		(956	)
Other expense, net		(11	)
Merger and seismic licensing expense		(3,998	)
Interest expense		(12,029	)
Translation gain on subordinated debt		7,395
Unrealized gain on derivative instruments, net		8,365

Earnings before income taxes and extraordinary item	$	79,056

CAPITAL EXPENDITURES:
Reportable segments	$	126,100
International interests		12,378
Administrative assets and other		1,596

Total capital expenditures	$	140,074

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,397,759
International interests		65,620
Administrative assets, net and other		9,554

Total property and equipment, net	$	1,472,933

Six Months Ended June 30, 2001

		Oil and Gas Operations
		Oil and Gas Operations								Marketing and Processing Canada
		GOM Offshore		Gulf Coast Onshore	Western	Alaska	Total U.S.	Canada	Total	Marketing and Processing Canada	Total Company
		(In Thousands)
Revenue		$	283,213	40,671	51,482	34,237	409,603	35,770	445,373	198,174	643,547
Expenses:
	Marketing and processing		—	737	—	—	737	—	737	196,210	196,947
	Oil and gas production		41,776	9,011	11,665	13,918	76,370	7,801	84,171	—	84,171
	General and administrative		5,546	1,338	1,849	2,018	10,751	1,813	12,564	718	13,282
	Depletion		78,588	7,891	8,312	7,319	102,110	9,062	111,172	942	112,114

Earnings from operations		$	157,303	21,694	29,656	10,982	219,635	17,094	236,729	304	237,033

Capital expenditures		$	134,853	12,640	10,668	34,596	192,757	31,222	223,979	—	223,979

Property and equipment, net		$	562,705	261,327	191,278	160,832	1,176,142	221,617	1,397,759	—	1,397,759

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

	(In Thousands)
EARNINGS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM:
Earnings from operations for reportable segments	$	237,033
Administrative asset depreciation		(1,826	)
Other expense, net		(1,183	)
Merger and seismic licensing expense		(4,498	)
Interest expense		(25,493	)
Translation loss on subordinated debt		(2,301	)
Unrealized gain on derivative instruments, net		13,586

Earnings before income taxes and extraordinary item	$	215,318

CAPITAL EXPENDITURES:
Reportable segments	$	223,979
International interests		26,901
Administrative assets and other		2,435

Total capital expenditures	$	253,315

PROPERTY AND EQUIPMENT, NET:
Reportable segments	$	1,397,759
International interests		65,620
Administrative assets, net and other		9,554

Total property and equipment, net	$	1,472,933

(8) SUPPLEMENTAL GUARANTOR INFORMATION

Canadian Forest is the issuer of the 8³/4% Notes. The 8³/4% Notes are unconditionally guaranteed on a senior subordinated basis by Forest. The indenture executed in connection with the 8³/4% Notes does not place significant restrictions on a subsidiary's ability to make distributions to the parent.

The Company has not presented separate financial statements and other disclosures concerning Canadian Forest or ProMark because management has determined that such information is not material to holders of the 8³/4% Notes; however, the following condensed consolidating financial information is being provided as of June 30, 2002 and December 31, 2001 and for the three and six months ended June 30, 2002 and 2001. Investments in subsidiaries are accounted for on the cost basis. Earnings or losses of subsidiaries are therefore not reflected in the related investment accounts. The principal eliminating entries eliminate investments in subsidiaries and intercompany balances.

Supplemental Condensed Consolidating Balance Sheets
June 30, 2002

			Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Eliminating Entries		Consolidated Forest Oil Corporation
			(In Thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	10,698		8,360		1,169		—		20,227
	Accounts receivable			78,386		7,187		21,438		—		107,011
	Derivative instruments			11,469		—		—		—		11,469
	Current deferred tax asset			4,257		—		—		—		4,257
	Other current assets			18,058		1,055		—		(250	)	18,863

		Total current assets		122,868		16,602		22,607		(250	)	161,827
Net property and equipment, at cost, full
cost method				1,380,566		240,334		3		—		1,620,903
Deferred income taxes				41,087		—		—		—		41,087
Goodwill and other intangible assets, net				—		—		13,622		—		13,622
Intercompany investments				249,127		25,713		—		(274,840	)	—
Other assets				25,056		923		—		—		25,979

			$	1,818,704		283,572		36,232		(275,090	)	1,863,418

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Accounts payable		$	137,466		6,601		21,605		(250	)	165,422
	Accrued interest			5,430		1,595		—		—		7,025
	Derivative instruments			10,362		—		—		—		10,362
	Other current liabilities			6,989		525		228		—		7,742

		Total current liabilities		160,247		8,721		21,833		(250	)	190,551
Long-term debt				654,226		57,944		—		—		712,170
Other liabilities				22,824		(7	)	—		—		22,817
Deferred income taxes				—		29,833		(10,895	)	—		18,938
Shareholders' equity:
	Common stock			4,907		249,127		25,265		(274,392	)	4,907
	Capital surplus			1,147,917		595		—		—		1,148,512
	Accumulated deficit			(95,059	)	(65,019	)	3,428		—		(156,650	)
	Accumulated other comprehensive loss			(20,270	)	2,378		(3,399	)	—		(21,291	)
	Treasury stock, at cost			(56,088	)	—		—		(448	)	(56,536	)

		Total shareholders' equity		981,407		187,081		25,294		(274,840	)	918,942

			$	1,818,704		283,572		36,232		(275,090	)	1,863,418

(8) SUPPLEMENTAL GUARANTOR INFORMATION (Continued)

Supplemental Condensed Consolidating Statement of Operations
Three months ended June 30, 2002

					Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
					(In Thousands)
Revenue:
	Marketing and processing				$	708		—		71,254		71,962
	Oil and gas sales:
		Gas				66,287		7,510		—		73,797
		Oil, condensate and natural gas liquids				46,261		5,588		—		51,849

			Total oil and gas sales			112,548		13,098		—		125,646

				Total revenue		113,256		13,098		71,254		197,608
Operating expenses:
	Marketing and processing					246		—		70,475		70,721
	Oil and gas production					36,467		3,908		—		40,375
	General and administrative					8,453		1,229		380		10,062
	Depreciation and depletion					42,468		4,975		145		47,588

				Total operating expenses		87,634		10,112		71,000		168,746

Earnings from operations						25,622		2,986		254		28,862
Other income and expense:
	Other (income) expense, net					210		(232	)	(2	)	(24	)
	Interest expense					11,145		1,425		(2	)	12,568
	Translation gain on subordinated debt					—		(2,970	)	—		(2,970	)
	Realized gain on derivative instruments, net					(162	)	—		—		(162	)
	Unrealized loss on derivative instruments, net					416		—		—		416

				Total other income and expense		11,609		(1,777	)	(4	)	9,828

Earnings before income taxes and extraordinary item						14,013		4,763		258		19,034
Income tax expense:
	Current					—		137		6		143
	Deferred					5,730		802		303		6,835

						5,730		939		309		6,978

Earnings (loss) before extraordinary item						8,283		3,824		(51	)	12,056
Extraordinary loss on extinguishment of debt						(1,091	)	(7	)	—		(1,098	)

Net earnings (loss)					$	7,192		3,817		(51	)	10,958

Supplemental Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2002

					Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
					(In Thousands)
Revenue:
	Marketing and processing				$	952		—		124,397		125,349
	Oil and gas sales:
		Gas				119,005		14,224		—		133,229
		Oil, condensate and natural gas liquids				77,543		10,670		—		88,213

			Total oil and gas sales			196,548		24,894		—		221,442

				Total revenue		197,500		24,894		124,397		346,791
Operating expenses:
	Marketing and processing					585		—		122,886		123,471
	Oil and gas production					70,818		6,768		—		77,586
	General and administrative					15,165		2,321		733		18,219
	Depreciation and depletion					77,174		10,312		288		87,774

				Total operating expenses		163,742		19,401		123,907		307,050

Earnings from operations						33,758		5,493		490		39,741
Other income and expense:
	Other (income) expense, net					1,040		(320	)	(1	)	719
	Interest expense					21,778		2,940		(5	)	24,713
	Translation gain on subordinated debt					—		(2,821	)	—		(2,821	)
	Realized gain on derivative instruments, net					(246	)	—		—		(246	)
	Unrealized loss on derivative instruments, net					616		—		—		616

				Total other income and expense		23,188		(201	)	(6	)	22,981

Earnings before income taxes and extraordinary item						10,570		5,694		496		16,760
Income tax expense:
	Current					—		240		14		254
	Deferred					4,323		1,151		529		6,003

						4,323		1,391		543		6,257

Net earnings (loss) before extraordinary item						6,247		4,303		(47	)	10,503
Extraordinary loss on extinguishment of debt						(1,091	)	(238	)	—		(1,329	)

Net earnings (loss)					$	5,156		4,065		(47	)	9,174

(8) SUPPLEMENTAL GUARANTOR INFORMATION (Continued)

Supplemental Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2002

			Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
			(In Thousands)
Cash flows from operating activities:
Net earnings (loss) before extraordinary item			$	6,247		4,303		(47	)	10,503
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
	Depreciation and depletion			77,174		10,312		288		87,774
	Amortization of deferred debt costs			933		108		—		1,041
	Translation gain on subordinated notes			—		(2,821	)	—		(2,821	)
	Unrealized loss on derivative instruments, net			616		—		—		616
	Deferred income tax expense			4,323		1,151		529		6,003
	Other, net			(1,774	)	2		—		(1,772	)
	Decrease in accounts receivable			25,048		3,534		374		28,956
	Decrease in other current assets			8,734		262		17		9,013
	Decrease in accounts payable			(36,994	)	(10,437	)	(243	)	(47,674	)
	Increase (decrease) in accrued interest and other current liabilities			(3,624	)	2,083		94		(1,447	)

		Net cash provided by operating activities		80,683		8,497		1,012		90,192
Cash flows from investing activities:
	Capital expenditures for property and equipment			(168,110	)	(13,198	)	—		(181,308	)
	Proceeds from sale of assets			(942	)	2,574		—		1,632
	(Increase) decrease in other assets, net			(2,297	)	1		—		(2,296	)

		Net cash used by investing activities		(171,349	)	(10,623	)	—		(181,972	)
Cash flows from financing activities:
	Proceeds from bank borrowings			176,000		1,889		—		177,889
	Repayments of bank borrowings			(195,000	)	(1,878	)	—		(196,878	)
	Issuance of 7³/4% senior notes, net of issuance costs			146,846		—		—		146,846
	Repurchases of 10¹/2% senior subordinated notes			(21,283	)	—		—		(21,283	)
	Repurchases of 8³/4% senior subordinated notes			—		(5,435	)	—		(5,435	)
	Proceeds from exercise of options and warrants			3,573		—		—		3,573
	Purchase of treasury stock			(560	)	—		—		(560	)
	Increase (decrease) in other liabilities, net			13		(541	)	—		(528	)

		Net cash provided (used) by financing activities		109,589		(5,965	)	—		103,624
Intercompany advances, net				(16,408	)	16,408		—		—
Effect of exchange rate changes on cash				54		(89	)	31		(4	)

Net increase in cash and cash equivalents				2,569		8,228		1,043		11,840
Cash and cash equivalents at beginning of year				8,129		132		126		8,387

Cash and cash equivalents at end of year			$	10,698		8,360		1,169		20,227

Supplemental Condensed Consolidating Balance Sheets
December 31, 2001

			Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Eliminating Entries		Consolidated Forest Oil Corporation
			(In Thousands)
ASSETS
Current Assets:
	Cash and cash equivalents		$	8,129		132		126		—		8,387
	Accounts receivable			103,436		10,103		20,551		—		134,090
	Derivative instruments			31,632		—		—		—		31,632
	Other current assets			26,838		1,268		—		(250	)	27,856

		Total current assets		170,035		11,503		20,677		(250	)	201,965
Net property and equipment, at cost, full cost method				1,287,996		228,890		14		—		1,516,900
Deferred income taxes				43,930		—		—		—		43,930
Goodwill and other intangible assets, net				—		—		13,263		—		13,263
Intercompany investments				232,721		25,713		—		(258,434	)	—
Other assets				19,271		1,040		—		—		20,311

			$	1,753,953		267,146		33,954		(258,684	)	1,796,369

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
	Accounts payable		$	174,460		14,385		20,568		(250	)	209,163
	Accrued interest			5,748		1,616		—		—		7,364
	Derivative instruments			1,548		—		—		—		1,548
	Current portion of deferred income tax liability			11,154		—		—		—		11,154
	Other current liabilities			10,296		649		125		(1	)	11,069

		Total current liabilities		203,206		16,650		20,693		(251	)	240,298
Long-term debt				530,935		63,243		—		—		594,178
Other liabilities				20,991		533		—		—		21,524
Deferred income taxes				—		27,335		(10,909	)	—		16,426
Shareholders' equity
	Common stock			4,883		232,720		25,265		(257,985	)	4,883
	Capital surplus			1,144,687		595		—		—		1,145,282
	Accumulated deficit			(100,214	)	(69,085	)	3,475		—		(165,824	)
	Accumulated other comprehensive gain (loss)			5,268		(4,845	)	(4,570	)	—		(4,147	)
	Treasury stock, at cost			(55,803	)	—		—		(448	)	(56,251	)

		Total shareholders' equity		998,821		159,385		24,170		(258,433	)	923,943

			$	1,753,953		267,146		33,954		(258,684	)	1,796,369

(8) SUPPLEMENTAL GUARANTOR INFORMATION (Continued)

Supplemental Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2001

					Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
					(In Thousands)
Revenue:
	Marketing and processing				$	175		—		88,198		88,373
	Oil and gas sales:
		Gas				120,643		8,310		—		128,953
		Oil, condensate and natural gas liquids				50,728		7,545		—		58,273

			Total oil and gas sales			171,371		15,855		—		187,226

				Total revenue		171,546		15,855		88,198		275,599
Operating expenses:
	Marketing and processing					543		—		87,127		87,670
	Oil and gas production					40,597		3,607		—		44,204
	General and administrative					5,794		943		339		7,076
	Merger and seismic licensing expense					3,998		—		—		3,998
	Depreciation and depletion					51,725		5,119		471		57,315

				Total operating expenses		102,657		9,669		87,937		200,263

Earnings from operations						68,889		6,186		261		75,336
Other income and expense:
	Other (income) expense, net					44		(15	)	(18	)	11
	Interest expense					7,567		4,462		—		12,029
	Translation gain on subordinated debt					—		(7,395	)	—		(7,395	)
	Realized gain on derivative instruments, net					(8,365	)	—		—		(8,365	)

				Total other income and expense		(754	)	(2,948	)	(18	)	(3,720	)

Earnings before income taxes and extraordinary item						69,643		9,134		279		79,056
Income tax expense (benefit):
	Current					(13,822	)	72		10		(13,740	)
	Deferred					39,112		1,114		391		40,617

						25,290		1,186		401		26,877

Net earnings (loss) before extraordinary item						44,353		7,948		(122	)	52,179
Extraordinary loss on extinguishment of debt						—		(1,590	)	—		(1,590	)

Net earnings (loss)					$	44,353		6,358		(122	)	50,589

Supplemental Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2001

					Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
					(In Thousands)
Revenue:
	Marketing and processing				$	396		—		198,174		198,570
	Oil and gas sales:
		Gas				296,773		18,835		—		315,608
		Oil, condensate and natural gas liquids				112,419		16,950		—		129,369

			Total oil and gas sales			409,192		35,785		—		444,977

				Total revenue		409,588		35,785		198,174		643,547
Operating expenses:
	Marketing and processing					737		—		196,210		196,947
	Oil and gas production					76,370		7,801		—		84,171
	General and administrative					10,751		1,813		718		13,282
	Merger and seismic licensing expense					4,498		—		—		4,498
	Depreciation and depletion					102,850		10,148		942		113,940

				Total operating expenses		195,206		19,762		197,870		412,838

Earnings from operations						214,382		16,023		304		230,709
Other income and expense:
	Other (income) expense, net					1,017		224		(58	)	1,183
	Interest expense					16,227		9,266		—		25,493
	Translation loss on subordinated debt					—		2,301		—		2,301
	Realized gain on derivative instruments, net					(13,586	)	—		—		(13,586	)

				Total other income and expense		3,658		11,791		(58	)	15,391

Earnings before income taxes and extraordinary item						210,724		4,232		362		215,318
Income tax expense:
	Current					2,093		122		21		2,236
	Deferred					75,785		3,152		681		79,618

						77,878		3,274		702		81,854

Net earnings (loss) before extraordinary item						132,846		958		(340	)	133,464
Extraordinary loss on extinguishment of debt						—		(1,590	)	—		(1,590	)

Net earnings (loss)					$	132,846		(632	)	(340	)	131,874

(8) SUPPLEMENTAL GUARANTOR INFORMATION (Continued)

Supplemental Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2001

			Forest Oil Corporation			Canadian Forest Oil Ltd.		Producers Marketing Ltd.		Consolidated Forest Oil Corporation
			(In Thousands)
Cash flows from operating activities:
Net earnings (loss) before extraordinary item			$	132,846		958		(340	)	133,464
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
	Depreciation and depletion			102,850		10,148		942		113,940
	Amortization of deferred debt costs			633		229		—		862
	Translation loss on subordinated notes			—		2,301		—		2,301
	Unrealized gain on derivative instruments, net			(13,586	)	—		—		(13,586	)
	Deferred income tax expense			75,785		3,152		681		79,618
	Other, net			(48	)	(11	)	(2	)	(61	)
	Decrease (increase) in accounts receivable			(6,509	)	(807	)	20,581		13,265
	Increase in other current assets			(21,670	)	(172	)	(153	)	(21,995	)
	Increase (decrease) in accounts payable			27,930		18,924		(21,638	)	25,216
	Increase (decrease) in accrued interest and other current liabilities			(17,408	)	(21,585	)	8		(38,985	)

		Net cash provided by operating activities		280,823		13,137		79		294,039
Cash flows from investing activities:
	Capital expenditures for property and equipment			(221,879	)	(31,436	)	—		(253,315	)
	Proceeds from sale of assets			22,480		163		—		22,643
	Increase in other assets, net			(769	)	(2	)	—		(771	)

		Net cash used by investing activities		(200,168	)	(31,275	)	—		(231,443	)
Cash flows from financing activities:
	Proceeds from bank borrowings			438,000		6,628		—		444,628
	Repayments of bank borrowings			(635,000	)	(34,238	)	—		(669,238	)
	Issuance of 8% senior notes, net of issuance costs			199,500		—		—		199,500
	Repurchases of 8³/4% senior subordinated notes			—		(39,934	)	—		(39,934	)
	Proceeds from exercise of options and warrants			7,938		—		—		7,938
	Purchase of treasury stock			(12,567	)	—		—		(12,567	)
	Increase (decrease) in other liabilities, net			284		(27	)	—		257

		Net cash used by financing activities		(1,845	)	(67,571	)	—		(69,416	)
Intercompany advances, net				(86,588	)	86,588		—		—
Effect of exchange rate changes on cash				(19	)	(184	)	1		(202	)

Net increase (decrease) in cash and cash equivalents				(7,797	)	695		80		(7,022	)
Cash and cash equivalents at beginning of year				14,778		(659	)	(116	)	14,003

Cash and cash equivalents at end of year			$	6,981		36		(36	)	6,981

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 Second Quarter of 2002

Net earnings for the second quarter of 2002 were $10,958,000 compared to net earnings of $50,589,000 in the corresponding period of 2001. The decline in earnings was attributable primarily to lower sales prices for natural gas and liquids and to lower production volumes in the United States. Decreased production volumes are primarily the result of property sales in the Gulf of Mexico and normal declines caused by reduced capital expenditures allocated to that region.

Marketing and processing revenue decreased by 19% to $71,962,000 in the second quarter of 2002 from $88,373,000 in the second quarter of 2001, and the related marketing and processing expense decreased by 19% to $70,721,000 in the second quarter of 2002 from $87,670,000 in the corresponding period of 2001. The earnings contribution for marketing and processing activities increased 77% to $1,241,000 in the second quarter of 2002 from $703,000 in the second quarter of 2001. The increase in the earnings contribution is due primarily to gas plant revenue in the United States.

Oil and gas sales revenue decreased by 33% to $125,646,000 in the second quarter of 2002 from $187,226,000 in the second quarter of 2001, primarily as a result of lower product prices and production volumes. For the second quarter of 2002, the average gas sales price declined 30% and the average liquids sales price declined 11%, compared to average prices in the 2001 period. Volume decreases in the 2002 period were attributable primarily to the Gulf of Mexico Business Unit. The Gulf of Mexico properties were impacted significantly 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 normal production declines as a result of reduced capital expenditures allocated to that region.

Oil and gas production expense for the second quarter of 2002 decreased to $40,375,000 compared to $44,204,000 in the corresponding period in 2001, due primarily to decreases in direct operating expenses and expensed workovers.

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

				Three Months Ended June 30,
				2002			2001
Natural Gas
	Production (MMCF):
		United States			20,067		25,848
		Canada			3,468		2,891

			Total		23,535		28,739

	Sales price received (per MCF)			$	3.15		4.36
	Effects of energy swaps and collars (per MCF)(1)				(.01	)	.13

	Average sales price (per MCF)			$	3.14		4.49
Liquids
Oil and condensate:
	Production (MBBLS)				2,152		2,087
	Sales price received (per BBL)			$	24.27		25.44
	Effects of energy swaps and collars (per BBL)(1)				(1.64	)	(.35	)

	Average sales price (per BBL)			$	22.63		25.09
Natural gas liquids:
	Production (MBBLS)				256		323
	Average sales price (per BBL)			$	12.27		18.28
Total Liquids Production (MBBLS):
		United States			2,134		2,087
		Canada			274		323

			Total		2,408		2,410

	Average sales price (per BBL)			$	21.53		24.18
Total Production
Production volumes (MMCFE)					37,983		43,199
Average sales price (per MCFE)				$	3.31		4.33

(1)

Energy 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 9,710 MMCF and 14,701 MMCF in the second quarter of 2002 and 2001, respectively. Hedged oil and condensate volumes were 1,047 MBBLS and 1,138 MBBLS in the second quarter of 2002 and 2001, respectively. The aggregate net gains (losses) under energy

swap agreements were $(3,802,000) and $2,904,000 respectively, for the three months ended June 30, 2002 and 2001 and were accounted for as increases (reductions), respectively, to oil and gas sales.

General and administrative expense was $10,062,000 in the second quarter of 2002 compared to $7,076,000 in the second quarter of 2001. Total overhead costs (capitalized and expensed general and administrative costs) were $17,190,000 in the second quarter of 2002 compared to $11,902,000 in the second quarter of 2001. The increases in the 2002 period were attributable, in approximately equal measure, to 1) higher gross overhead costs, and 2) lower overhead recoveries for production operations and for exploration and development activities. Higher gross overhead costs are attributable primarily to increases in salaried headcount, legal expense and insurance expense. Lower overhead 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 overhead recoveries for exploration and development activities are the result of decreased capital spending on operated properties in the 2002 period. The percentage of overhead capitalized remained relatively constant at slightly over 40% during the 2002 and 2001 periods.

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

		Three Months Ended June 30,
		2002		2001
		(In Thousands)
Overhead costs capitalized		$	7,128	4,826
General and administrative costs expensed(1)			10,062	7,076

	Total overhead costs	$	17,190	11,902

(1): Includes $380,000 and $339,000 related to marketing operations for the three months ended June 30, 2002 and 2001, respectively.

Depreciation and depletion expense was $47,588,000 in the second quarter of 2002 compared to $57,315,000 in the second quarter of 2001. The decrease was attributable primarily to lower production volumes. On a per-unit basis, the depletion rate was $1.23 per MCFE in the second quarter of 2002 compared to $1.30 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 costs.

Other income of $24,000 in the second quarter of 2002 included interest income offset partially by franchise taxes. Other expense of $11,000 in the second quarter of 2001 represented primarily franchise taxes, offset partially by interest income and an insurance dividend.

Interest expense in the second quarter of 2002 increased to $12,568,000 compared to $12,029,000 in the second quarter of 2001, due primarily to higher debt balances offset partially by lower interest rates on variable and fixed rate debt.

Foreign currency translation gains were $2,970,000 in the second quarter of 2002 and $7,395,000 in the second quarter of 2001. Foreign currency translation gains and losses relate to translation of the 8³/4% Notes issued by Canadian Forest, and are attributable to the increases and decreases in the value of the Canadian dollar relative to the U.S. dollar during the period. The value of the Canadian dollar was $.6584 per $1.00 U.S. at June 30, 2002 compared to $.6259 at March 31, 2002. Forest is required to recognize the noncash foreign currency translation gains or losses related to the 8³/4% Notes because the debt is denominated in U.S. dollars and the functional currency of Canadian Forest is the Canadian dollar.

There was a realized gain on derivative instruments of $162,000 in the second quarter of 2002. This gain related to contracts covering basis differentials, which are differences between NYMEX prices and those in effect at a specific sales point. The gain was the result of realizing widening basis differentials during the period. There was a net unrealized loss on derivative instruments in the second quarter of 2002 of $416,000 compared to a net unrealized gain on derivative instruments of $8,365,000 in the corresponding period in 2001. The unrealized loss in 2002 was attributable primarily to decreases in the estimated future value of existing basis swaps due to a narrowing future basis differential curve. The unrealized 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 increases in commodity future prices. Realized and unrealized gains and losses on derivative instruments are recorded separately in non-operating income since the instruments do not qualify as hedges under the accounting rules governing hedging activities that were adopted in 2001.

Income tax expense of $6,978,000 was recognized in the second quarter of 2002 compared to income tax expense of $26,877,000 in the first quarter of 2001. The decrease is attributable primarily to decreased pre-tax profitability. The income tax provision in the second quarter of 2001 includes an adjustment between current and deferred income tax due to a reduction in forecasted current taxable income for the year.

The extraordinary loss on extinguishment of debt of $1,098,000 (net of tax) in the second quarter of 2002 resulted from the repurchase of $19,710,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 108% of par value and the repurchase of $150,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value. The extraordinary loss on extinguishment of debt of $1,590,000 (net of tax) in the second quarter of 2001 resulted from the repurchase of $38,620,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103% of par value.

Results of Operations for the Six Months Ended June 30, 2002

Net earnings for the first six months of 2002 were $9,174,000 compared to $131,874,000 in the corresponding period of 2001. The decline in earnings is attributable primarily to lower sales prices for natural gas and liquids and to lower production volumes in the United States. Decreased production volumes are primarily the result of property sales in the Gulf of Mexico and normal declines caused by reduced capital expenditures allocated to that region.

Marketing and processing revenue decreased by 37% to $125,349,000 in the first six months of 2002 from $198,570,000 in the first six months of 2001, and the related marketing and processing expense decreased by 37% to $123,471,000 in the first six months of 2002 from $196,947,000 in the corresponding period of 2001. The earnings contribution for marketing and processing activities increased 16% to $1,878,000 in the first six months of 2002 from $1,623,000 in the first six months of 2001. The increase in the earnings contribution is due primarily to gas plant revenue in the United States.

Oil and gas sales revenue decreased by 50% to $221,442,000 in the first six months of 2002 from $444,977,000 in the first six months of 2001, primarily as a result of lower product prices and production volumes. For the first six months of 2002, the average gas sales price declined 48% and the average liquids sales price declined 21% compared to average prices in the corresponding 2001 period. Volume decreases in the 2002 period were attributable primarily to the Gulf of Mexico Business Unit. The Gulf of Mexico properties were impacted significantly 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 normal production declines as a result of reduced capital expenditures allocated to that region.

Oil and gas production expense for the first six months of 2002 decreased to $77,586,000 compared to $84,171,000 in the corresponding period of 2001, due primarily to decreases in direct operating and production tax expense. These decreases were offset partially by increases in expensed workovers and higher ad valorem tax expense.

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

				Six Months Ended June 30,
				2002			2001
Natural Gas
	Production (MMCF):
		United States			38,400		51,015
		Canada			7,342		5,485

			Total		45,742		56,500

	Sales price received (per MCF)			$	2.68		5.66
	Effects of energy swaps and collars (per MCF)(1)				.23		(.07	)

	Average sales price (per MCF)			$	2.91		5.59
Liquids
Oil and condensate:
	Production (MBBLS)				3,781		4,434
	Sales price received (per BBL)			$	22.28		26.44
	Effects of energy swaps and collars (per BBL)(1)				(.56	)	(.30	)

	Average sales price (per BBL)			$	21.72		26.14
Natural gas liquids:
	Production (MBBLS)				565		627
	Average sales price (per BBL)			$	10.77		21.50
Total Liquids Production (MBBLS):
	United States				3,749		4,375
	Canada				597		686

		Total			4,346		5,061

	Average sales price (per BBL)			$	20.30		25.56
Total Production
Production volumes (MMCFE)					71,818		86,866
Average sales price (per MCFE)				$	3.08		5.12

(1): Energy 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 17,360 MMCF and 28,932 MMCF in the first six months of 2002 and 2001, respectively. Hedged oil and condensate volumes were 2,082 MBBLS and 2,063 MBBLS in the first six months of 2002 and 2001, respectively. The aggregate net gains (losses) under energy swap agreements were $8,610,000 and $(5,334,000), respectively, for the six months ended June 30, 2002 and 2001 and were accounted for as increases (reductions), respectively, to oil and gas sales.

General and administrative expense was $18,219,000 in the first six months of 2002 compared to $13,282,000 in the first six months of 2001. Total overhead costs (capitalized and expensed general and administrative costs) were $31,632,000 in the first six months of 2002 compared to $22,799,000 in the first six months of 2001. The increases in the 2002 period were attributable, in approximately equal measure, to 1) higher gross overhead costs, and 2) lower overhead recoveries for production operations and for exploration and development activities. Higher gross overhead costs are attributable primarily to increases in salaried headcount, legal expense and insurance expense. Lower overhead 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 overhead recoveries for exploration and development activities is the result of decreased capital spending on operated properties in the 2002 period. The percentage of overhead capitalized remained relatively constant at slightly over 40% during the 2002 and 2001 periods.

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

	Six Months Ended June 30,
	2002		2001
	(In Thousands)
Overhead costs capitalized	$	13,413	9,517
General and administrative costs expensed(1)		18,219	13,282

	$	31,632	22,799

(1): Includes $733,000 and $718,000 related to marketing and processing operations for the six month periods ended June 30, 2002 and 2001, respectively.

Depreciation and depletion expense was $87,774,000 in the first six months of 2002 compared to $113,940,000 in the first six months of 2001. The decrease was attributable primarily to lower production volumes. On a per-unit basis, the depletion rate was $1.20 per MCFE in the first six months of 2002 compared to $1.29 per MCFE in the first six months of 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 costs.

Other expense of $719,000 in the first six months of 2002 and $1,183,000 in the first six months of 2001 was due primarily to franchise taxes.

Interest expense of $24,713,000 in the first six months of 2002 decreased from $25,493,000 in the first six months of 2001, due primarily to lower interest rates on variable and fixed rate debt, offset partially by higher debt balances.

There was a foreign currency translation gain of $2,821,000 in the first six months of 2002 and a loss of $2,301,000 in the first six months of 2001. Foreign currency translation gains and losses relate to translation of the 8³/4% Notes issued by Canadian Forest, and are attributable to the increases and decreases in the value of the Canadian dollar relative to the U.S. dollar during the period. The value of the Canadian dollar was $.6584 per $1.00 U.S. at June 30, 2002 compared to $.6279 at December 31, 2001. Forest is required to recognize the noncash foreign currency translation gains or losses related to the 8³/4% Notes because the debt is denominated in U.S. dollars and the functional currency of Canadian Forest is the Canadian dollar.

There was a realized gain on derivative instruments of $246,000 in the first six months of 2002. This gain related to contracts covering basis differentials, which are differences between NYMEX prices and those in effect at a specific sales point. The gain was the result of realizing widening basis differentials during the period. There was a net unrealized loss on derivative instruments in the first six months of 2002 of $616,000 compared to a net unrealized gain on derivative instruments of $13,586,000 in the corresponding period in 2001. The unrealized loss in 2002 was attributable primarily to decreases in the estimated future value of existing basis swaps due to a narrowing future basis differential curve. The unrealized 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 increases in commodity future prices. Realized and unrealized gains and losses on derivative instruments are recorded separately in non-operating income since the instruments do not qualify as hedges under the accounting rules governing hedging activities that were adopted in 2001.

Current income tax expense was $254,000 in the first six months of 2002 compared to $2,236,000 in the corresponding period of 2001. The deferred income tax expense was $6,003,000 in the first six months of 2002 compared to $79,618,000 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 $1,329,000 (net of tax) in the first six months of 2002 resulted from the repurchase of $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at approximately 103.5% of par value and the repurchase of $19,710,000 principal amount of 10¹/2% Senior Subordinated Notes at approximately 108% of par value. The extraordinary loss on extinguishment of debt of $1,590,000 (net of tax) in the first six months of 2001 resulted from the repurchase of $38,620,000 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.

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 Repurchased. In the first six months of 2002, we repurchased $5,300,000 principal amount of 8³/4% Senior Subordinated Notes at 103.5% of par value; $15,110,000 principal amount of our 10¹/2% Senior Subordinated Notes at 108.0% of par value; and $4,600,000 principal amount of our 10¹/2% Senior Subordinated Notes at 107.9% of par value. We also purchased 21,894 shares of 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 June 30, 2002, under the most restrictive of these covenants and financial tests, our available borrowing amount under the credit facilities was estimated to be approximately $145,000,000. 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. Reduction of the borrowing base could result in a substantial reduction in the available borrowing amount.

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 June 30, 2002 there were no outstanding borrowings under the U.S. credit facility or the Canadian Forest credit facility. At August 1, 2002, the outstanding borrowings under the U.S. credit facility were $18,000,000 and there were no outstanding borrowings under the Canadian credit facility. At August 1, 2002, Forest had used the credit facilities for letters of credit in the amount of $4,565,133 U.S. and $3,841,953 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 $28,724,000 at June 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 $90,192,000 in the first six months of 2002 compared to $294,039,000 in the first six months of 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 six months of 2002 was $181,972,000 compared to $231,443,000 in the first six months of 2001. The decrease was due primarily to decreased exploration and development activities. Net cash provided by financing activities in the first six months of 2002 was $103,624,000 compared to cash used of $69,416,000 in the first six months of 2001. The 2002 period included net repayments of bank debt of $18,989,000, more than offset by net proceeds of $146,846,000 from the issuance of the 7³/4% Notes. The 2001 period included net repayments of bank borrowings of $224,610,000, cash used for repurchases of the 8³/4% Notes of $39,934,000 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:

		Six Months Ended June 30,
		2002		2001
		(In Thousands)
Property acquisition costs:
	Proved properties	$	2,799	(550	)
	Undeveloped properties		—	(273	)

			2,799	(823	)
Exploration costs:
	Direct costs		53,280	111,525
	Overhead capitalized		6,490	4,266

			59,770	115,791
Development costs:
	Direct costs		109,702	130,661
	Overhead capitalized		6,923	5,251

			116,625	135,912

Total capital expenditures		$	179,194	250,880

Forest's anticipated expenditures for exploration and development in 2002 are estimated to range from $250,000,000 to $350,000,000. 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, but expect that adoption of the statement will result in increases in the capitalized costs of our oil and gas properties and in the recognition of additional liabilities related to asset retirement obligations.

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, 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 are currently evaluating the effects of this pronouncement.

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) additional disclosure requirements for energy trading activities. EITF Issue No. 02-03 will be effective for Forest in the third quarter of 2002. We are evaluating the impact of EITF Issue No. 02-03 and expect adoption to result in presentation of net marketing margins as a revenue line item.

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 energy swaps, collars and other financial instruments. All of our energy swaps and collar agreements and a portion of our basis swaps in place at June 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 42% and 50% of our consolidated production, on an equivalent basis, during the second 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 June 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	2.8	$	2.71 CDN
2003	5.5	$	2.79 CDN
2004	5.5	$	2.90 CDN
2005	5.5	$	3.01 CDN
2006	5.5	$	3.12 CDN
2007	5.5	$	3.24 CDN
2008	5.5	$	3.37 CDN
2009	3.6	$	4.06 CDN
2010	1.7	$	6.21 CDN
2011	0.8	$	6.55 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 and 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	.30	$	3.68 CDN
2003	.60	$	3.82 CDN
2004	.60	$	3.96 CDN
2005	.60	$	4.11 CDN
2006	.50	$	4.27 CDN

Hedging Program. 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 we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of June 30, 2002, Forest had entered into the following swaps:

	Natural Gas			Oil
	BBTUs per Day	Average Hedged Price per MMBTU		Barrels per Day	Average Hedged Price per BBL
Third Quarter 2002	75.0	$	3.37	10,000	$	22.44
Fourth Quarter 2002	41.8	$	3.47	10,000	$	22.22
First Quarter 2003	25.0	$	3.62	5,500	$	23.09
Second Quarter 2003	—		—	3,500	$	21.74
Third Quarter 2003	—		—	3,500	$	21.67
Fourth Quarter 2003	—		—	3,000	$	21.26
First Quarter 2004	—		—	2,000	$	22.90

Between July 1, 2002 and August 9, 2002, we entered into the following oil swaps:

	Oil
	Barrels Per Day	Average Hedged Price per BBL
First Quarter 2003	500	$	25.28
Second Quarter 2003	500	$	24.58
Third Quarter 2003	500	$	24.40
Fourth Quarter 2003	1,000	$	23.93
First Quarter 2004	1,000	$	23.58
Second Quarter 2004	1,000	$	23.33

We also use basis swaps in connection with natural gas swaps to fix the differential price between the NYMEX price and the index price at which the hedged gas is sold. As of June 30, 2002, Forest had entered into basis swaps designated as cash flow hedges with weighted average volumes of 40.1 BBTUs per day for the remainder of 2002. Between July 1, 2002 and August 9, 2002, we entered into additional basis swaps designated as cash flow hedges covering weighted average volumes of 20.0 BBTUs per day from November 2002 through October 2003.

The fair value of our cash flow hedges as of June 30, 2002 was a loss of approximately $11,153,000.

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 June 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	13.3	$	3.25	$	5.13
First Quarter 2003	20.0	$	3.25	$	5.13
Second Quarter 2003	20.0	$	3.25	$	4.08
Third Quarter 2003	20.0	$	3.25	$	4.08
Fourth Quarter 2003	20.0	$	3.25	$	4.89
First Quarter 2004	20.0	$	3.25	$	5.30

	Oil
	Barrels Per Day	Average Floor Price per BBL		Average Ceiling Price per BBL
First Quarter 2003	3,000	$	22.00	$	25.42
Second Quarter 2003	3,000	$	22.00	$	25.42
Third Quarter 2003	3,000	$	22.00	$	25.42
Fourth Quarter 2003	3,000	$	22.00	$	25.42
First Quarter 2004	2,000	$	22.00	$	24.08

Between July 1, 2002 and August 9, 2002, we did not enter into any new oil and gas collars.

Trading Activities. Profits or losses generated by the purchase and sale of third parties' gas are based on the spread between the prices of natural gas purchased and sold. ProMark does not trade natural gas to hold as a speculative or open position. All transactions represent physical volumes and are immediately offset, thereby fixing the margin and eliminating the market risk on the related agreements. At June 30, 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
July-December, 2002	1.6	$	4.82 CDN	$	4.85 CDN
2003	.9	$	4.96 CDN	$	4.99 CDN

As of June 30, 2002, Forest had entered into basis swaps that were not designated as cash flow hedges with weighted average volumes of 10.0 BBTUs per day for the remainder of 2002. Between July 1, 2002 and August 9, 2002 we did not enter into any additional basis swaps not designated as cash flow hedges.

The fair value of our derivative instruments not designated as cash flow hedges as of June 30, 2002 was a loss of approximately $240,000.

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.

Canada. The Canadian dollar is the functional currency of Canadian Forest. As a result, Canadian Forest is exposed to foreign currency translation risk related to translation of the principal amount of the 8³/4% Senior Subordinated Notes that it issued in late 1997 and early 1998 because these notes are denominated in U.S. dollars. The $57,944,000 principal amount of the debt is due in 2007.

Operations outside of North America. Expenditures incurred relative to the foreign concessions held by Forest 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 June 30, 2002:

		2005		2006		2007		2008		2011		2014		Total		Fair Value
		(Dollar Amounts in Thousands)
Long-term debt:
	Fixed rate	$	—	68,470		57,944		265,000		160,000		150,000		701,414		704,461
	Average interest rate		—	10.5	%	8.75	%	8.00	%	8.00	%	7.75	%	8.25	%

Forest has entered into interest rate swaps under which the fixed rate on a specified principal amount of notes will be exchanged for a variable rate based on LIBOR plus specified basis points over the term of the note issue. At June 30, 2002, Forest had the following interest rate swaps in place:

						Variable Rate
Note Issue	Principal Amount of Notes		Principal Amount Related to Swap		Fixed Rate	LIBOR	Basis Points
8% Senior Notes due 2008	$	265,000,000	$	100,000,000	8%	6 month	195.00
8% Senior Notes due 2011	$	160,000,000	$	50,000,000	8%	6 month	181.25
7³/4% Senior Notes due 2014	$	150,000,000	$	150,000,000	7³/4%	3 month	153.00

As of June 30, 2002 the fair value of these interest rate swaps, which are accounted for as fair value hedges, was a gain of approximately $14,582,000.

PART II. OTHER INFORMATION

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

On May 8, 2002, Forest held its Annual Meeting of Shareholders (the Annual Meeting) in Denver, Colorado. A total of 43,651,567 shares of common stock were present at the Annual Meeting, either in person or by proxy, constituting a quorum. The matters voted upon at the Annual Meeting consisted of two proposals set forth in Forest's Proxy Statement dated March 29, 2002. The two proposals submitted to a vote of shareholders are set forth below, and each was adopted by the indicated margins.

Proposal No. 1—Electing four (4) Class II directors.

	Shares Voted for	Shares Withheld
Cortlandt S. Dietler	35,915,452	7,736,112
Forrest E. Hoglund	42,947,325	704,239
James E. Lee	42,954,467	697,097
Craig D. Slater	42,632,955	1,018,609

In addition to the Class II directors, the other directors of Forest whose terms did not expire at the 2002 Annual Meeting include: Philip F. Anschutz, Robert S. Boswell, William L. Britton, Dod A. Fraser, Cannon Y. Harvey, Steven A. Kaplan, and Michael B. Yanney.

Proposal No. 2—Ratifying the appointment of KPMG LLP as the Company's independent auditors.

Shares Voted for		Shares Against		Abstentions
42,985,656		605,176		60,730

There were no broker non-votes.

Item 5. OTHER INFORMATION

On July 25, 2002, Forest renewed Directors and Officers Liability coverages designed to indemnify the directors and officers of Forest and its subsidiaries against certain liabilities incurred by them in the performance of their duties and also providing for reimbursement in certain cases to Forest and its subsidiaries for sums paid by them to directors and officers as indemnification for similar liability. This type of coverage was originally purchased by Forest on May 24, 1978. The 2002 renewal was for a one-year period. Primary insurance of $10,000,000 was secured with Chubb Insurance Company and excess insurance coverage of $15,000,000 was secured with The Hartford Insurance Company for a total coverage of $25,000,000. In addition, we have obtained excess insurance coverage for the officers and directors in the amount of $10,000,000. Aggregate premiums for the 12-month period ending July 2003 is $693,125. Aggregate premiums for the prior 36-month period ending July 2002 were $1,020,000. No claims have been filed and no payments have been made to Forest or its subsidiaries or to any of their directors or officers under this coverage.

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. In 1999, the State of Alaska regulatory approval process used in connection with the exploration phase of our Redoubt Shoal oil and gas project in the Cook Inlet of Alaska (the Exploration Project) was challenged in a lawsuit by a non-governmental third party. In May 2002, the Supreme Court of the State of Alaska issued an injunction in this case ordering Forest to halt drilling operations at the Redoubt Unit No. 5 well and issued a decision to the effect that the State of Alaska's regulatory review and approval process for the Exploration Project did not conform with the statutory requirements. The Court remanded the matter for further review and action by the relevant State agency. As a result of legislative and state agency action after such removal, the foregoing injunction ceased to be in force and effect, and Forest subsequently resumed operations at the No. 5 well in June 2002.

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, the same 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. 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.

4.1: Second Amendment to Combined Credit Agreements dated as of April 3, 2002, by and between Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is a party thereto, Bank of America, N.A., as U.S. Syndication Agent, Citibank N.A., as U.S. Documentation Agent, J.P. Morgan Bank Canada, successor to The Chase Manhattan Bank of Canada, as Canadian Administrative Agent, Bank of Montreal, as Canadian Syndication Agent, The Toronto-Dominion Bank, as Canadian Documentation Agent, and JPMorgan Chase Bank, successor to The Chase Manhattan Bank, as Global Administrative Agent, incorporated herein by reference to Exhibit 4.17 to Forest Oil Corporation's Registration Statement on Form S-4 dated June 11, 2002 (File No. 333-90220).
4.2: Third Amendment dated as of May 31, 2002 to Combined Credit Agreements, by and between Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is a party thereto, Bank of America, N.A., as U.S. Syndication Agent, Citibank N.A., as U.S. Documentation Agent, J.P. Morgan Bank Canada, successor to The Chase Manhattan Bank of Canada, as Canadian Administrative Agent, Bank of Montreal, as Canadian Syndication Agent, The Toronto-Dominion Bank, as Canadian Documentation Agent, and J.P. Morgan Bank Canada, successor to the Chase Manhattan Bank, as Global Administrative Agent, incorporated herein by reference to Exhibit 4.18 to Forest Oil Corporation's Registration Statement on Form S-4 dated June 11, 2002 (File No. 333-90220).
4.3: Indenture dated as of April 25, 2002 between Forest Oil Corporation and State Street Bank and Trust Company, incorporated herein by reference to Exhibit 4.6 to Forest Oil Corporation's Registration Statement on Form S-4 dated June 11, 2002 (File No. 333-90220).

(b) Reports on Form 8-K.

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

Date of Report		Item Reported		Financial Statements Filed
April 5, 2002		Item 9		None
May 8, 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)
Date: August 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)